UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



x☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, ~~2017~~2023



¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12291

THE AES CORPORATION

(Exact name of registrant as specified in its charter)



Delaware						~~54 1163725~~54-1163725
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


4300 Wilson Boulevard
Arlington,	Virginia	22203
(Address of principal executive offices)		(Zip Code)

~~(703) 522-1315~~

~~Registrant’s~~


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


Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share	AES	New York Stock Exchange
Corporate Units	AESC	New York Stock Exchange

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 (§232.405 of this chapter) 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filerx

☒

Accelerated filer¨

☐

Smaller reporting company¨

☐

Emerging growth company¨

☐

Non-accelerated filer¨

~~(Do not check if a smaller reporting company)~~☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐

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 number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on October ~~27, 2017~~31, 2023 was ~~660,386,566.~~

669,629,035.

~~THE AES CORPORATION~~

~~FORM 10-Q~~

~~FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2017~~

~~TABLE OF CONTENTS~~

The AES Corporation

Form 10-Q for the Quarterly Period ended September 30, 2023

Table of Contents


Glossary of Terms			1

~~Glossary of Terms~~			1

PART I: FINANCIAL INFORMATION	23

ITEM 1.		FINANCIAL STATEMENTS (UNAUDITED)	23
		Condensed Consolidated Balance Sheets	23
		Condensed Consolidated Statements of Operations	34
		Condensed Consolidated Statements of Comprehensive Income (Loss)	45
		Condensed Consolidated Statements of Changes in Equity	6
		Condensed Consolidated Statements of Cash Flows	58
		Notes to Condensed Consolidated Financial Statements	69
		Note 1 - Financial Statement Presentation	69
		Note 2 - Inventory	912

		Note 3 - Fair Value	912
		Note 4 - Derivative Instruments and Hedging Activities	1217
		Note 5 - Financing Receivables	1318
		Note 6 - Investments in and Advances to Affiliates	1319
		Note 7 - Debt	1420
		Note 8 - Commitments and Contingencies	1522
		Note 9 - ~~Pension Plans~~Leases	1623
		Note 10 - Redeemable Stock of Subsidiaries	1724
		Note 11 - Equity	1725
		Note 12 - Segments	1928
		Note 13 - Revenue	30
		Note 14 - Other Income and Expense	2031
		Note 1415 - Asset Impairment Expense	2132
		Note 151 6 - ~~Discontinued Operations~~Income Taxes	2232

		Note 161 7 - Held-for-Sale ~~Businesses and Dispositions~~	2333
		Note 171 8 - Acquisitions	2433
		Note 181 9 - Earnings Per Share	2434
		Note 19 2 0 - Risks and Uncertainties	2535
		Note 202 1 - Subsequent Events	2636

ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	2737
		Executive Summary	2837
		~~Overview of Q3 2017 Results and Strategic Performance~~	29
		Review of Consolidated Results of Operations	3140
		SBU Performance Analysis	3746
		Key Trends and Uncertainties	5053
		Capital Resources and Liquidity	5561
		Critical Accounting Policies and Estimates	6768

ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	6768

ITEM 4.		CONTROLS AND PROCEDURES	7071

PART II: OTHER INFORMATION			7172

ITEM 1.		LEGAL PROCEEDINGS	7172

ITEM 1A.		RISK FACTORS	75

ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	75

ITEM 3.		DEFAULTS UPON SENIOR SECURITIES	75

ITEM 4.		MINE SAFETY DISCLOSURES	75

ITEM 5.		OTHER INFORMATION	75

ITEM 6.		EXHIBITS	7576

SIGNATURES			7677

1 | The AES Corporation | September 30, 2023 Form 10-Q

~~GLOSSARY OF TERMS~~Glossary of Terms

The following terms and acronyms appear in the text of this report and have the definitions indicated below:



Adjusted ~~EPS~~EBITDA		Adjusted ~~Earnings Per Share, a non-GAAP measure~~
~~Adjusted PTC~~	~~Adjusted Pretax Contribution,~~earnings before interest income and expense, taxes, depreciation and amortization, a non-GAAP measure of operating performance
~~AFS~~Adjusted EBITDA with Tax Attributes		~~Available For Sale~~Adjusted earnings before interest income and expense, taxes, depreciation and amortization, adding back the pre-tax effect of Production Tax Credits, Investment Tax Credits and depreciation tax expense allocated to tax equity investors, a non-GAAP measure
~~AOCL~~Adjusted EPS		~~Accumulated Other Comprehensive Loss~~Adjusted Earnings Per Share, a non-GAAP measure
~~ASC~~Adjusted PTC		~~Accounting Standards Codification~~Adjusted Pre-tax Contribution, a non-GAAP measure of operating performance
~~ASU~~AES		~~Accounting Standards Update~~The Parent Company and its subsidiaries and affiliates
~~BNDES~~AES Andes		~~Brazilian Development Bank~~AES Andes S.A., formerly AES Gener
~~CAA~~AES Brasil		~~United States Clean Air Act~~AES Brasil Operações S.A., formerly branded as AES Tietê
~~CAMMESA~~AES Clean Energy Development		~~Wholesale Electric Market Administrator in Argentina~~AES Clean Energy Development, LLC
~~CDPQ~~AES Indiana		~~La Caisse de depot et placement du Quebec~~Indianapolis Power & Light Company, formerly branded as IPL. AES Indiana is wholly-owned by IPALCO
~~CHP~~AES Ohio		~~Combined Heat and Power~~
~~COFINS~~	~~Contribution for the Financing of Social Security~~
~~DP&L~~	The Dayton Power & Light Company, formerly branded as DP&L. AES Ohio is wholly-owned by DPL
~~DPL~~AES Renewable Holdings		~~DPL Inc.~~AES Renewable Holdings, LLC, formerly branded as AES Distributed Energy
~~DPLER~~		~~DPL Energy Resources, Inc.~~
~~DPP~~AFUDC		~~Dominican Power Partners, LDC~~Allowance for Funds Used During Construction
~~EPA~~


AGIC		AES Global Insurance Company, AES’ captive insurance company
AOCL		Accumulated Other Comprehensive Loss

ASC		Accounting Standards Codification
ASU		Accounting Standards Update


BESS		Battery Energy Storage System





CAA		United States Clean Air Act



CCR		Coal Combustion Residuals, which includes bottom ash, fly ash, and air pollution control wastes generated at coal-fired generation plant sites


CECL		Current Expected Credit Loss



CO2		Carbon Dioxide


CSAPR		Cross-State Air Pollution Rule

CWA		U.S. Clean Water Act
DG Comp		Directorate-General for Competition



DPL		DPL Inc.


EBITDA		Earnings before interest income and expense, taxes, depreciation and amortization, a non-GAAP measure of operating performance
EPA		United States Environmental Protection Agency
EPC		Engineering, Procurement and Construction
~~EURIBOR~~		~~Euro Interbank Offered Rate~~
~~FASB~~
ESP		Electric Security Plan
EU		European Union


FASB		Financial Accounting Standards Board
~~FERC~~		~~Federal Energy Regulatory Commission~~
FXFluence		~~Foreign Exchange~~Fluence Energy, Inc and its subsidiaries, including Fluence Energy, LLC, which was previously our joint venture with Siemens (NASDAQ: FLNC)
~~GAAP~~


GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
~~IPALCO~~


GILTI		Global Intangible Low Taxed Income

GW		Gigawatts
GWh		Gigawatt Hours
HLBV		Hypothetical Liquidation at Book Value


IPALCO		IPALCO Enterprises, Inc.
~~IPL~~		~~Indianapolis Power & Light Company~~
~~kWh~~		~~Kilowatt Hours~~
~~LIBOR~~		~~London Interbank Offered Rate~~
~~LNG~~ITC		Investment Tax Credit
IURC		Indiana Utility Regulatory Commission


LNG		Liquid Natural Gas
~~MATS~~		~~Mercury and Air Toxics Standards~~
~~MMI~~		~~Mini Maritsa Iztok (state-owned electricity public supplier in Bulgaria)~~
MW		~~Megawatts~~
~~MWh~~MMBtu		~~Megawatt Hours~~Million British Thermal Units
~~NCI~~		~~Noncontrolling Interest~~
~~NEK~~
MW		Megawatts
MWh		Megawatt Hours
NAAQS		National Ambient Air Quality Standards
NCI		Noncontrolling Interest
NEK		Natsionalna Elektricheska Kompania (state-owned electricity public supplier in Bulgaria)
NM		~~Not Meaningful~~
~~NOV~~NM		Not Meaningful
NOV		Notice of Violation
NO_X		Nitrogen ~~Oxides~~Oxide
NPDES		National Pollutant Discharge Elimination System
~~PIS~~		~~Program of Social Integration~~
~~PJM~~		~~PJM Interconnection, LLC~~
~~PPA~~




Parent Company		The AES Corporation

Pet Coke		Petroleum Coke


PPA		Power Purchase Agreement
PREPA		Puerto Rico Electric Power Authority
~~RSU~~

PUCO		The Public Utilities Commission of Ohio


RSU		Restricted Stock Unit
~~SIC~~		~~Central Interconnected Electricity System~~
~~SING~~		~~Norte Grande Interconnected Electricity System~~
SBU		Strategic Business Unit
SEC		United States Securities and Exchange Commission

2 | The AES Corporation | September 30, 2023 Form 10-Q


SO₂			Sulfur Dioxide
~~U.S.~~			~~United States~~
~~USD~~


TDSIC			Transmission, Distribution, and Storage System Improvement Charge
TEG			Termoeléctrica del Golfo, S. de R.L. de C.V.
TEP			Termoeléctrica Peñoles, S. de R.L. de C.V.
U.S.			United States

USD			United States Dollar
~~VAT~~			~~Value-Added Tax~~
VIE			Variable Interest Entity

3 | The AES Corporation | September 30, 2023 Form 10-Q

PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

~~THE AES CORPORATION~~

Condensed Consolidated Balance Sheets(Unaudited)

~~(Unaudited)~~


								September 30, 2023		December 31, 2022
	September 30, 2017			December 31, 2016
	(in millions, except share and per share data)							(in millions, except share and per share amounts)
ASSETS							ASSETS
CURRENT ASSETS							CURRENT ASSETS
Cash and cash equivalents	$	1,398		$	1,305		Cash and cash equivalents	$	1,765	$	1,374
Restricted cash	437			278			Restricted cash	365		536
Short-term investments	563			798			Short-term investments	538		730
Accounts receivable, net of allowance for doubtful accounts of $90 and $111, respectively	2,357			2,166
Accounts receivable, net of allowance for doubtful accounts of $9 and $5, respectively							Accounts receivable, net of allowance for doubtful accounts of $9 and $5, respectively	1,725		1,799
Inventory	660			630			Inventory	798		1,055
Prepaid expenses	89			83			Prepaid expenses	161		98
Other current assets	1,080			1,151			Other current assets	1,472		1,533
Current assets of held-for-sale businesses	76			—
Current held-for-sale assets							Current held-for-sale assets	493		518
Total current assets	6,660			6,411			Total current assets	7,317		7,643
NONCURRENT ASSETS							NONCURRENT ASSETS
Property, Plant and Equipment:							Property, Plant and Equipment:
Land	798			779			Land	492		470
Electric generation, distribution assets and other	29,916			28,539			Electric generation, distribution assets and other	27,998		26,599
Accumulated depreciation	(10,199		)	(9,528		)	Accumulated depreciation	(8,602)		(8,651)
Construction in progress	3,841			3,057			Construction in progress	7,647		4,621
Property, plant and equipment, net	24,356			22,847			Property, plant and equipment, net	27,535		23,039
Other Assets:							Other Assets:
Investments in and advances to affiliates	1,164			621			Investments in and advances to affiliates	894		952
Debt service reserves and other deposits	786			593			Debt service reserves and other deposits	205		177
Goodwill	1,157			1,157			Goodwill	362		362
Other intangible assets, net of accumulated amortization of $563 and $519, respectively	474			359
Other intangible assets, net of accumulated amortization of $486 and $434, respectively							Other intangible assets, net of accumulated amortization of $486 and $434, respectively	2,290		1,841
Deferred income taxes	760			781			Deferred income taxes	428		319
Service concession assets, net of accumulated amortization of $182 and $114, respectively	1,382			1,445
Other noncurrent assets	2,095			1,905

Loan receivable, net of allowance of $24 and $26, respectively							Loan receivable, net of allowance of $24 and $26, respectively	990		1,051
Other noncurrent assets, net of allowance of $16 and $51, respectively							Other noncurrent assets, net of allowance of $16 and $51, respectively	3,140		2,979

Total other assets	7,818			6,861			Total other assets	8,309		7,681
TOTAL ASSETS	$	38,834		$	36,119		TOTAL ASSETS	$	43,161	$	38,363
LIABILITIES AND EQUITY							LIABILITIES AND EQUITY
CURRENT LIABILITIES							CURRENT LIABILITIES
Accounts payable	$	2,091		$	1,656		Accounts payable	$	1,641	$	1,730
Accrued interest	353			247			Accrued interest	379		249
Accrued non-income taxes							Accrued non-income taxes	269		249
Accrued and other liabilities	2,020			2,066			Accrued and other liabilities	2,442		2,151
Non-recourse debt, includes $439 and $273, respectively, related to variable interest entities	2,257			1,303
Current liabilities of held-for-sale businesses	15			—
Recourse debt							Recourse debt	700		—
Non-recourse debt, including $1,015 and $416, respectively, related to variable interest entities							Non-recourse debt, including $1,015 and $416, respectively, related to variable interest entities	3,060		1,758

Current held-for-sale liabilities							Current held-for-sale liabilities	328		354
Total current liabilities	6,736			5,272			Total current liabilities	8,819		6,491
NONCURRENT LIABILITIES							NONCURRENT LIABILITIES
Recourse debt	4,954			4,671			Recourse debt	4,864		3,894
Non-recourse debt, includes $1,305 and $1,502, respectively, related to variable interest entities	14,822			14,489
Non-recourse debt, including $1,781 and $2,295, respectively, related to variable interest entities							Non-recourse debt, including $1,781 and $2,295, respectively, related to variable interest entities	18,767		17,846

Deferred income taxes	742			804			Deferred income taxes	1,257		1,139
Pension and other postretirement liabilities	1,387			1,396

Other noncurrent liabilities	3,047			3,005			Other noncurrent liabilities	2,775		3,168

Total noncurrent liabilities	24,952			24,365			Total noncurrent liabilities	27,663		26,047
Commitments and Contingencies (see Note 8)							Commitments and Contingencies (see Note 8)
Redeemable stock of subsidiaries	967			782			Redeemable stock of subsidiaries	1,423		1,321
EQUITY							EQUITY
THE AES CORPORATION STOCKHOLDERS’ EQUITY							THE AES CORPORATION STOCKHOLDERS’ EQUITY
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 816,312,913 issued and 660,386,566 outstanding at September 30, 2017 and 816,061,123 issued and 659,182,232 outstanding at December 31, 2016)	8			8
Preferred stock (without par value, 50,000,000 shares authorized; 1,043,050 issued and outstanding at September 30, 2023 and December 31, 2022)							Preferred stock (without par value, 50,000,000 shares authorized; 1,043,050 issued and outstanding at September 30, 2023 and December 31, 2022)	838		838
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 819,051,591 issued and 669,629,035 outstanding at September 30, 2023 and 818,790,001 issued and 668,743,464 outstanding at December 31, 2022)							Common stock ($0.01 par value, 1,200,000,000 shares authorized; 819,051,591 issued and 669,629,035 outstanding at September 30, 2023 and 818,790,001 issued and 668,743,464 outstanding at December 31, 2022)	8		8
Additional paid-in capital	8,670			8,592			Additional paid-in capital	6,449		6,688
Accumulated deficit	(934		)	(1,146		)	Accumulated deficit	(1,292)		(1,635)
Accumulated other comprehensive loss	(2,666		)	(2,756		)	Accumulated other comprehensive loss	(1,410)		(1,640)
Treasury stock, at cost (155,926,347 and 156,878,891 shares at September 30, 2017 and December 31, 2016, respectively)	(1,892		)	(1,904		)
Treasury stock, at cost (149,422,556 and 150,046,537 shares at September 30, 2023 and December 31, 2022, respectively)							Treasury stock, at cost (149,422,556 and 150,046,537 shares at September 30, 2023 and December 31, 2022, respectively)	(1,814)		(1,822)
Total AES Corporation stockholders’ equity	3,186			2,794			Total AES Corporation stockholders’ equity	2,779		2,437
NONCONTROLLING INTERESTS	2,993			2,906			NONCONTROLLING INTERESTS	2,477		2,067
Total equity	6,179			5,700			Total equity	5,256		4,504
TOTAL LIABILITIES AND EQUITY	$	38,834		$	36,119		TOTAL LIABILITIES AND EQUITY	$	43,161	$	38,363

See Notes to Condensed Consolidated Financial Statements.

4 | The AES Corporation

~~THE AES CORPORATION~~

Condensed Consolidated Statements of Operations

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,				Nine Months Ended September 30,
	2017			2016			2017			2016				2023		2022		2023		2022

	(in millions, except per share data)													(in millions, except share and per share amounts)
Revenue:													Revenue:
Non-Regulated													Non-Regulated	$	2,571	$	2,651	$	7,051	$	6,944
Regulated	$	1,793		$	1,785		$	5,157		$	4,926		Regulated	863		976		2,649		2,613
Non-Regulated	1,839			1,757			5,437			5,116
Total revenue	3,632			3,542			10,594			10,042			Total revenue	3,434		3,627		9,700		9,557
Cost of Sales:													Cost of Sales:
Non-Regulated													Non-Regulated	(1,813)		(1,839)		(5,392)		(5,237)
Regulated	(1,574		)	(1,623		)	(4,640		)	(4,521		)	Regulated	(703)		(896)		(2,298)		(2,335)
Non-Regulated	(1,347		)	(1,231		)	(3,980		)	(3,750		)
Total cost of sales	(2,921		)	(2,854		)	(8,620		)	(8,271		)	Total cost of sales	(2,516)		(2,735)		(7,690)		(7,572)
Operating margin	711			688			1,974			1,771			Operating margin	918		892		2,010		1,985
General and administrative expenses	(52		)	(40		)	(155		)	(135		)	General and administrative expenses	(64)		(51)		(191)		(149)
Interest expense	(353		)	(354		)	(1,034		)	(1,086		)	Interest expense	(326)		(276)		(966)		(813)
Interest income	101			110			291			365			Interest income	144		100		398		270
Loss on extinguishment of debt	(49		)	(16		)	(44		)	(12		)	Loss on extinguishment of debt	—		(1)		(1)		(8)
Other expense	(47		)	(13		)	(95		)	(42		)	Other expense	(12)		(10)		(38)		(51)
Other income	18			18			105			43			Other income	12		4		36		80
Gain (loss) on disposal and sale of businesses	(1		)	—			(49		)	30
Gain (loss) on disposal and sale of business interests													Gain (loss) on disposal and sale of business interests	—		1		(4)		—

Asset impairment expense	(2		)	(79		)	(260		)	(473		)	Asset impairment expense	(158)		(50)		(352)		(533)
Foreign currency transaction gains (losses)	21			(20		)	13			(16		)	Foreign currency transaction gains (losses)	(100)		8		(209)		(60)

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES	347			294			746			445			INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES	414		617		683		721
Income tax expense	(110		)	(75		)	(270		)	(165		)	Income tax expense	(109)		(145)		(179)		(186)
Net equity in earnings of affiliates	24			11			33			25
INCOME FROM CONTINUING OPERATIONS	261			230			509			305
Loss from operations of discontinued businesses, net of income tax benefit of $4 for the nine months ended September 30, 2016	—			(1		)	—			(7		)
Net loss from disposal and impairments of discontinued businesses, net of income tax benefit of $401 for the nine months ended September 30, 2016	—			—			—			(382		)
NET INCOME (LOSS)	261			229			509			(84		)
Net equity in losses of affiliates													Net equity in losses of affiliates	(14)		(26)		(43)		(54)

NET INCOME													NET INCOME	291		446		461		481

Less: Net income attributable to noncontrolling interests and redeemable stock of subsidiaries	(109		)	(54		)	(328		)	(97		)	Less: Net income attributable to noncontrolling interests and redeemable stock of subsidiaries	(60)		(25)		(118)		(124)
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	152		$	175		$	181		$	(181	)
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:
Income from continuing operations, net of tax	$	152		$	176		$	181		$	208
Loss from discontinued operations, net of tax	—			(1		)	—			(389		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	152		$	175		$	181		$	(181	)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION													NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	231	$	421	$	343	$	357

BASIC EARNINGS PER SHARE:													BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.23		$	0.26		$	0.28		$	0.31
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—			—			—			(0.59		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.23		$	0.26		$	0.28		$	(0.28	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS													NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.34	$	0.63	$	0.51	$	0.53
DILUTED EARNINGS PER SHARE:													DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax	$	0.23		$	0.26		$	0.27		$	0.31
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax	—			—			—			(0.59		)
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.23		$	0.26		$	0.27		$	(0.28	)

NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS													NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS	$	0.32	$	0.59	$	0.48	$	0.50
DILUTED SHARES OUTSTANDING	663			662			662			662			DILUTED SHARES OUTSTANDING	712		711		712		711
DIVIDENDS DECLARED PER COMMON SHARE	$	0.12		$	0.11		$	0.24		$	0.22

See Notes to Condensed Consolidated Financial Statements.

~~THE~~

5 | The AES ~~CORPORATION~~Corporation

Condensed Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)


														Three Months Ended September 30,				Nine Months Ended September 30,
	Three Months Ended September 30,						Nine Months Ended September 30,							2023		2022		2023		2022
	2017			2016			2017			2016
														(in millions)
NET INCOME													NET INCOME	$	291	$	446	$	461	$	481
	(in millions)
NET INCOME (LOSS)	$	261		$	229		$	509		$	(84	)

Foreign currency translation activity:													Foreign currency translation activity:
Foreign currency translation adjustments, net of income tax benefit (expense) of $1, $(1), $0 and $0, respectively	80			(16		)	29			232
Reclassification to earnings, net of $0 income tax	—			—			98			—
Foreign currency translation adjustments, net of $0 income tax for all periods													Foreign currency translation adjustments, net of $0 income tax for all periods	(44)		(80)		75		(97)

Total foreign currency translation adjustments	80			(16		)	127			232			Total foreign currency translation adjustments	(44)		(80)		75		(97)
Derivative activity:													Derivative activity:
Change in derivative fair value, net of income tax benefit (expense) of $(6), $(7), $15 and $39, respectively	5			19			(42		)	(138		)
Reclassification to earnings, net of income tax benefit (expense) of $5, $(4), $(6) and $(5), respectively	1			21			50			23
Change in derivative fair value, net of income tax expense of $73, $62, $78, and $196, respectively													Change in derivative fair value, net of income tax expense of $73, $62, $78, and $196, respectively	274		189		276		731
Reclassification to earnings, net of income tax benefit (expense) of $0, $1, $11 and $(12), respectively													Reclassification to earnings, net of income tax benefit (expense) of $0, $1, $11 and $(12), respectively	(1)		14		(49)		52
Total change in fair value of derivatives	6			40			8			(115		)	Total change in fair value of derivatives	273		203		227		783
Pension activity:													Pension activity:
Reclassification to earnings due to amortization of net actuarial loss, net of income tax expense of $4, $2, $10 and $4, respectively	7			3			20			10

Change in pension adjustments due to net actuarial gain for the period, net of $0 income tax for all periods													Change in pension adjustments due to net actuarial gain for the period, net of $0 income tax for all periods	—		—		1		—
Reclassification to earnings, net of income tax benefit (expense) of $0, $(1), $0, $(1), respectively													Reclassification to earnings, net of income tax benefit (expense) of $0, $(1), $0, $(1), respectively	—		1		—		2
Total pension adjustments	7			3			20			10			Total pension adjustments	—		1		1		2
OTHER COMPREHENSIVE INCOME	93			27			155			127			OTHER COMPREHENSIVE INCOME	229		124		303		688
COMPREHENSIVE INCOME	354			256			664			43			COMPREHENSIVE INCOME	520		570		764		1,169
Less: Comprehensive income attributable to noncontrolling interests	(127		)	(66		)	(360		)	(94		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION	$	227		$	190		$	304		$	(51	)
Less: Comprehensive income attributable to noncontrolling interests and redeemable stock of subsidiaries													Less: Comprehensive income attributable to noncontrolling interests and redeemable stock of subsidiaries	(109)		(50)		(168)		(207)
COMPREHENSIVE INCOME ATTRIBUTABLE TO THE AES CORPORATION													COMPREHENSIVE INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	411	$	520	$	596	$	962

See Notes to Condensed Consolidated Financial Statements.

6 | The AES Corporation

~~THE~~Condensed Consolidated Statements of Changes in Equity

(Unaudited)


	Nine Months Ended September 30, 2023
	Preferred Stock			Common Stock			Treasury Stock			Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Noncontrolling Interests
	Shares	Amount		Shares	Amount		Shares	Amount
	(in millions)
Balance at January 1, 2023	1.0	$	838	818.8	$	8	150.0	$	(1,822)	$	6,688	$	(1,635)	$	(1,640)	$	2,067
Net income	—	—		—	—		—	—		—		151		—		52
Total foreign currency translation adjustment, net of income tax	—	—		—	—		—	—		—		—		33		7
Total change in derivative fair value, net of income tax	—	—		—	—		—	—		—		—		(135)		1
Total pension adjustments, net of income tax	—	—		—	—		—	—		—		—		—		1
Total other comprehensive income (loss)	—	—		—	—		—	—		—		—		(102)		9




Distributions to noncontrolling interests	—	—		—	—		—	—		—		—		—		(37)
Acquisitions of noncontrolling interests	—	—		—	—		—	—		(1)		—		—		1
Contributions from noncontrolling interests	—	—		—	—		—	—		—		—		—		2
Sales to noncontrolling interests	—	—		—	—		—	—		(7)		—		—		3
Issuance of preferred shares in subsidiaries	—	—		—	—		—	—		—		—		—		4


Dividends declared on common stock ($0.1659/share)	—	—		—	—		—	—		(111)		—		—		—

Issuance and exercise of stock-based compensation benefit plans, net of income tax	—	—		—	—		(0.5)	7		(12)		—		—		—
Balance at March 31, 2023	1.0	$	838	818.8	$	8	149.5	$	(1,815)	$	6,557	$	(1,484)	$	(1,742)	$	2,101
Net income (loss)	—	—		—	—		—	—		—		(39)		—		42
Total foreign currency translation adjustment, net of income tax	—	—		—	—		—	—		—		—		74		4
Total change in derivative fair value, net of income tax	—	—		—	—		—	—		—		—		101		—

Total other comprehensive income	—	—		—	—		—	—		—		—		175		4




Distributions to noncontrolling interests	—	—		—	—		—	—		—		—		—		(90)


Sales to noncontrolling interests	—	—		—	—		—	—		(17)		—		—		209




Issuance and exercise of stock-based compensation benefit plans, net of income tax	—	—		—	—		(0.1)	1		10		—		—		—
Balance at June 30, 2023	1.0	$	838	818.8	$	8	149.4	$	(1,814)	$	6,550	$	(1,523)	$	(1,567)	$	2,266
Net income	—	—		—	—		—	—		—		231		—		68
Total foreign currency translation adjustment, net of income tax	—	—		—	—		—	—		—		—		(36)		(7)
Total change in derivative fair value, net of income tax	—	—		—	—		—	—		—		—		216		(3)

Total other comprehensive income (loss)	—	—		—	—		—	—		—		—		180		(10)




Distributions to noncontrolling interests	—	—		—	—		—	—		—		—		—		(7)
Acquisitions of noncontrolling interests	—	—		—	—		—	—		25		—		—		(46)

Sales to noncontrolling interests	—	—		—	—		—	—		(21)		—		(23)		206


Dividends declared on common stock ($0.1659/share)	—	—		—	—		—	—		(111)		—		—		—

Issuance and exercise of stock-based compensation benefit plans, net of income tax	—	—		0.3	—		—	—		6		—		—		—
Balance at September 30, 2023	1.0	$	838	819.1	$	8	149.4	$	(1,814)	$	6,449	$	(1,292)	$	(1,410)	$	2,477

7 | The AES ~~CORPORATION~~Corporation


	Nine Months Ended September 30, 2022
	Preferred Stock			Common Stock			Treasury Stock			Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Loss		Noncontrolling Interests
	Shares	Amount		Shares	Amount		Shares	Amount
	(in millions)
Balance at January 1, 2022	1.0	$	838	818.7	$	8	152.0	$	(1,845)	$	7,106	$	(1,089)	$	(2,220)	$	1,769
Net income	—	—		—	—		—	—		—		115		—		94
Total foreign currency translation adjustment, net of income tax	—	—		—	—		—	—		—		—		131		1
Total change in derivative fair value, net of income tax	—	—		—	—		—	—		—		—		265		22
Total pension adjustments, net of income tax	—	—		—	—		—	—		—		—		1		—
Total other comprehensive income	—	—		—	—		—	—		—		—		397		23




Distributions to noncontrolling interests	—	—		—	—		—	—		—		—		—		(25)
Acquisitions of noncontrolling interests	—	—		—	—		—	—		(93)		—		(76)		(367)
Contributions from noncontrolling interests	—	—		—	—		—	—		—		—		—		86
Sales to noncontrolling interests	—	—		—	—		—	—		7		—		—		30
Issuance of preferred shares in subsidiaries	—	—		—	—		—	—		—		—		—		60
Dividends declared on common stock ($0.1580/share)	—	—		—	—		—	—		(105)		—		—		—

Issuance and exercise of stock-based compensation benefit plans, net of income tax	—	—		—	—		(1.1)	13		(12)		—		—		—
Balance at March 31, 2022	1.0	$	838	818.7	$	8	150.9	$	(1,832)	$	6,903	$	(974)	$	(1,899)	$	1,670
Net income (loss)	—	—		—	—		—	—		—		(179)		—		50
Total foreign currency translation adjustment, net of income tax	—	—		—	—		—	—		—		—		(146)		(3)
Total change in derivative fair value, net of income tax	—	—		—	—		—	—		—		—		255		15

Total other comprehensive income	—	—		—	—		—	—		—		—		109		12




Distributions to noncontrolling interests	—	—		—	—		—	—		—		—		—		(45)
Acquisitions of noncontrolling interests	—	—		—	—		—	—		—		—		—		(2)
Contributions from noncontrolling interests	—	—		—	—		—	—		—		—		—		3
Sales to noncontrolling interests	—	—		—	—		—	—		10		—		—		170




Issuance and exercise of stock-based compensation benefit plans, net of income tax	—	—		—	—		—	—		11		—		—		—
Balance at June 30, 2022	1.0	$	838	818.7	$	8	150.9	$	(1,832)	$	6,924	$	(1,153)	$	(1,790)	$	1,858
Net income	—	—		—	—		—	—		—		421		—		31
Total foreign currency translation adjustment, net of income tax	—	—		—	—		—	—		—		—		(75)		(4)
Total change in derivative fair value, net of income tax	—	—		—	—		—	—		—		—		174		14
Total pension adjustments, net of income tax	—	—		—	—		—	—		—		—		—		1
Total other comprehensive income	—	—		—	—		—	—		—		—		99		11




Distributions to noncontrolling interests	—	—		—	—		—	—		—		—		—		(38)
Acquisitions of noncontrolling interests	—	—		—	—		—	—		(3)		—		—		(2)
Contributions from noncontrolling interests	—	—		—	—		—	—		—		—		—		78
Sales to noncontrolling interests	—	—		—	—		—	—		(2)		—		—		114

Dividends declared on AES common stock ($0.1580/share)	—	—		—	—		—	—		(106)		—		—		—

Issuance and exercise of stock-based compensation benefit plans, net of income tax	—	—		0.1	—		(0.1)	—		5		—		—		—
Balance at September 30, 2022	1.0	$	838	818.8	$	8	150.8	$	(1,832)	$	6,818	$	(732)	$	(1,691)	$	2,052

See Notes to Condensed Consolidated Financial Statements.

8 | The AES Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)


								Nine Months Ended September 30,
								2023		2022

								(in millions)
OPERATING ACTIVITIES:							OPERATING ACTIVITIES:
Net income							Net income	$	461	$	481
Adjustments to net income:							Adjustments to net income:
Depreciation and amortization							Depreciation and amortization	836		800
Loss on disposal and sale of business interests							Loss on disposal and sale of business interests	4		—
Impairment expense							Impairment expense	358		533
Deferred income taxes							Deferred income taxes	(102)		—

Loss of affiliates, net of dividends							Loss of affiliates, net of dividends	47		78
Emissions allowance expense							Emissions allowance expense	211		319
Loss on realized/unrealized foreign currency							Loss on realized/unrealized foreign currency	184		45
Other							Other	150		(1)
Changes in operating assets and liabilities:							Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable							(Increase) decrease in accounts receivable	16		(409)
(Increase) decrease in inventory							(Increase) decrease in inventory	253		(361)
(Increase) decrease in prepaid expenses and other current assets							(Increase) decrease in prepaid expenses and other current assets	76		(116)
(Increase) decrease in other assets							(Increase) decrease in other assets	(4)		251
Increase (decrease) in accounts payable and other current liabilities							Increase (decrease) in accounts payable and other current liabilities	(187)		108
Increase (decrease) in income tax payables, net and other tax payables							Increase (decrease) in income tax payables, net and other tax payables	(67)		(131)
Increase (decrease) in deferred income							Increase (decrease) in deferred income	50		48
Increase (decrease) in other liabilities							Increase (decrease) in other liabilities	23		4
Net cash provided by operating activities							Net cash provided by operating activities	2,309		1,649
INVESTING ACTIVITIES:							INVESTING ACTIVITIES:
Capital expenditures							Capital expenditures	(5,295)		(2,711)
Acquisitions of business interests, net of cash and restricted cash acquired							Acquisitions of business interests, net of cash and restricted cash acquired	(311)		(114)
Proceeds from the sale of business interests, net of cash and restricted cash sold							Proceeds from the sale of business interests, net of cash and restricted cash sold	98		1

Sale of short-term investments							Sale of short-term investments	1,002		654
Purchase of short-term investments							Purchase of short-term investments	(764)		(1,091)
Contributions and loans to equity affiliates							Contributions and loans to equity affiliates	(147)		(202)

Affiliate repayments and returns of capital							Affiliate repayments and returns of capital	—		71
Purchase of emissions allowances							Purchase of emissions allowances	(161)		(415)

Other investing							Other investing	(95)		(18)
Net cash used in investing activities							Net cash used in investing activities	(5,673)		(3,825)
FINANCING ACTIVITIES:							FINANCING ACTIVITIES:
Borrowings under the revolving credit facilities and commercial paper program							Borrowings under the revolving credit facilities and commercial paper program	33,981		4,214
Repayments under the revolving credit facilities and commercial paper program							Repayments under the revolving credit facilities and commercial paper program	(32,168)		(2,782)
Issuance of recourse debt							Issuance of recourse debt	1,400		200
Repayments of recourse debt							Repayments of recourse debt	—		(29)
Issuance of non-recourse debt							Issuance of non-recourse debt	1,784		3,554
Repayments of non-recourse debt							Repayments of non-recourse debt	(1,262)		(1,772)
Payments for financing fees							Payments for financing fees	(76)		(83)
Purchases under supplier financing arrangements							Purchases under supplier financing arrangements	1,307		299
Repayments of obligations under supplier financing arrangements							Repayments of obligations under supplier financing arrangements	(1,099)		(234)
Distributions to noncontrolling interests							Distributions to noncontrolling interests	(173)		(129)
Acquisitions of noncontrolling interests							Acquisitions of noncontrolling interests	(12)		(541)
Contributions from noncontrolling interests							Contributions from noncontrolling interests	63		122
Sales to noncontrolling interests							Sales to noncontrolling interests	371		336
Issuance of preferred shares in subsidiaries							Issuance of preferred shares in subsidiaries	3		60

Dividends paid on AES common stock							Dividends paid on AES common stock	(333)		(316)
Payments for financed capital expenditures							Payments for financed capital expenditures	(8)		(23)

Other financing							Other financing	(38)		(13)
Net cash provided by financing activities							Net cash provided by financing activities	3,740		2,863
Effect of exchange rate changes on cash, cash equivalents and restricted cash							Effect of exchange rate changes on cash, cash equivalents and restricted cash	(108)		(44)
Increase in cash, cash equivalents and restricted cash of held-for-sale businesses							Increase in cash, cash equivalents and restricted cash of held-for-sale businesses	(20)		(93)
Total increase in cash, cash equivalents and restricted cash							Total increase in cash, cash equivalents and restricted cash	248		550
Cash, cash equivalents and restricted cash, beginning							Cash, cash equivalents and restricted cash, beginning	2,087		1,484
Cash, cash equivalents and restricted cash, ending							Cash, cash equivalents and restricted cash, ending	$	2,335	$	2,034
SUPPLEMENTAL DISCLOSURES:							SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized							Cash payments for interest, net of amounts capitalized	$	735	$	654
Cash payments for income taxes, net of refunds							Cash payments for income taxes, net of refunds	267		203
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:							SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:

	Nine Months Ended September 30,
	2017			2016

	(in millions)
OPERATING ACTIVITIES:
Net income (loss)	$	509		$	(84	)
Adjustments to net income (loss):
Depreciation and amortization	884			877
Loss (gain) on sales and disposals of businesses	49			(30		)
Impairment expenses	260			475
Deferred income taxes	(3		)	(475		)
Provisions for contingencies	30			28
Loss on extinguishment of debt	44			12
Loss on sales of assets	34			26
Impairments of discontinued operations	—			783
Other	61			106
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	(279		)	335
(Increase) decrease in inventory	(66		)	36
(Increase) decrease in prepaid expenses and other current assets	140			670
(Increase) decrease in other assets	(266		)	(237		)
Increase (decrease) in accounts payable and other current liabilities	162			(567		)
Increase (decrease) in income tax payables, net and other tax payables	(4		)	(270		)
Increase (decrease) in other liabilities	134			497
Net cash provided by operating activities	1,689			2,182
INVESTING ACTIVITIES:
Capital expenditures	(1,587		)	(1,770		)
Acquisitions of businesses, net of cash acquired, and equity method investments	(606		)	(61		)
Proceeds from the sale of businesses, net of cash sold, and equity method investments	39			157
Sale of short-term investments	2,942			3,747
Purchase of short-term investments	(2,673		)	(3,797		)
Increase in restricted cash, debt service reserves. and other assets	(311		)	(123		)
Other investing	(86		)	(22		)
Net cash used in investing activities	(2,282		)	(1,869		)
FINANCING ACTIVITIES:
Borrowings under the revolving credit facilities	1,489			1,079
Repayments under the revolving credit facilities	(851		)	(856		)
Issuance of recourse debt	1,025			500
Repayments of recourse debt	(1,353		)	(808		)
Issuance of non-recourse debt	2,703			2,118
Repayments of non-recourse debt	(1,731		)	(1,720		)
Payments for financing fees	(96		)	(86		)
Distributions to noncontrolling interests	(263		)	(356		)
Contributions from noncontrolling interests and redeemable security holders	59			154
Proceeds from the sale of redeemable stock of subsidiaries	—			134
Dividends paid on AES common stock	(238		)	(218		)
Payments for financed capital expenditures	(100		)	(108		)
Purchase of treasury stock	—			(79		)
Proceeds from sales to noncontrolling interests	60			—
Other financing	(26		)	(12		)
Net cash provided by (used in) financing activities	678			(258		)
Effect of exchange rate changes on cash	9			7
(Increase) decrease in cash of discontinued operations and held-for-sale businesses	(1		)	6
Total increase in cash and cash equivalents	93			68
Cash and cash equivalents, beginning	1,305			1,257
Cash and cash equivalents, ending	$	1,398		$	1,325
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest, net of amounts capitalized	$	797		$	837
Cash payments for income taxes, net of refunds	$	291		$	425
SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
Assets acquired through capital lease and other liabilities	$	—		$	5
Reclassification of Alto Maipo loans and accounts payable into equity (see Note 11—Equity)	$	279		$	—

Initial recognition of contingent consideration for acquisitions (see Note 18)							Initial recognition of contingent consideration for acquisitions (see Note 18)	215		15
Noncash recognition of new operating and financing leases							Noncash recognition of new operating and financing leases	187		129
Noncash contributions from noncontrolling interests							Noncash contributions from noncontrolling interests	60		—

See Notes to Condensed Consolidated Financial Statements.

~~THE AES CORPORATION~~

9 | Notes to Condensed Consolidated Financial Statements | September 30, 2023 and 2022

Notes to Condensed Consolidated Financial Statements

For the Three and Nine Months Ended September 30, ~~2017~~2023 and ~~2016~~2022

(Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

Consolidation — In this Quarterly Report, the terms “AES,” “the Company,” “us” or “we” refer to the consolidated entity, including its subsidiaries and affiliates. The terms “The AES Corporation” or “the Parent Company” refer only to the publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates. Furthermore, VIEs in which the Company has a variable interest have been consolidated where the Company is the primary beneficiary. Investments in which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of ~~accounting.~~accounting, except for our investment in Alto Maipo, for which we have elected the fair value option as permitted under ASC 825. All intercompany transactions and balances have been eliminated in consolidation.

Interim Financial Presentation — The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with GAAP, as contained in the FASB ASC, for interim financial information and Article 10 of Regulation S-X issued by the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position, comprehensive income, changes in equity, and cash flows. The results of operations for the three and nine months ended September 30, ~~2017,~~2023 are not necessarily indicative of expected results for the year ending December 31, ~~2017.~~2023. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the ~~2016~~2022 audited consolidated financial statements and notes thereto, which are included in the ~~2016~~2022 Form 10-K filed with the SEC on ~~February 27, 2017~~March 1, 2023 (the ~~“2016~~“2022 Form 10-K”). and in Exhibit 99.1 to the Form 8-K filed with the SEC on May 8, 2023.

Cash, Cash Equivalents, and Restricted Cash— The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported on the Condensed Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Condensed Consolidated Statements of Cash Flows (in millions):


	September 30, 2023		December 31, 2022
Cash and cash equivalents	$	1,765	$	1,374
Restricted cash	365		536
Debt service reserves and other deposits	205		177
Cash, Cash Equivalents, and Restricted Cash	$	2,335	$	2,087

ASC 326 - Financial Instruments - Credit Losses — The following table represents the rollforward of the allowance for credit losses for the period indicated (in millions):

10 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022


Nine Months Ended September 30, 2023	Accounts Receivable		Mong Duong Receivables		Argentina Receivables		Lease Receivable (2)		Other		Total
CECL reserve balance at beginning of period	$	4	$	28	$	31	$	20	$	1	$	84
Current period provision	14		—		—		—		11		25
Write-offs charged against allowance	(12)		—		—		(20)		—		(32)
Recoveries collected	2		(2)		—		—		—		—
Foreign exchange	—		—		(15)		—		—		(15)
CECL reserve balance at end of period	$	8	$	26	$	16	$	—	$	12	$	62


Nine Months Ended September 30, 2022	Accounts Receivable (1)		Mong Duong Receivables		Argentina Receivables		Lease Receivable (2)		Other		Total






CECL reserve balance at beginning of period	$	3	$	30	$	23	$	—	$	7	$	63
Current period provision	7		—		22		20		—		49
Write-offs charged against allowance	(9)		—		—		—		(6)		(15)
Recoveries collected	2		(1)		—		—		—		1
Foreign exchange	—		—		(8)		—		—		(8)
CECL reserve balance at end of period	$	3	$	29	$	37	$	20	$	1	$	90

_____________________________

(1)Excludes operating lease receivable allowances and contractual dispute allowances of $2 million as of September 30, 2022. These reserves are not in scope under ASC 326.

(2)Lease receivable credit losses allowance at Southland Energy (AES Gilbert).

ASC 450 - Liabilities - Supplier Finance Programs — With some purchases, AES enters into supplier financing arrangements. The company generally uses an intermediary entity between the supplier and the Company, but sometimes enters into these agreements directly with the supplier, with the goal of securing improved payment terms. These arrangements are included in Accrued and other liabilities on the Condensed Consolidated Balance Sheets as the amounts are all due in less than a year; the related interest expense is recorded on the Condensed Consolidated Statements of Operations within Interest expense. The company had 32 supplier financing arrangements with a total outstanding balance of $775 million as of September 30, 2023, and 46 supplier financing arrangements with a total outstanding balance of $662 million as of December 31, 2022. The agreements ranged from less than $1 million to $69 million with a weighted average interest rate of 7.37% as of September 30, 2023; as of December 31, 2022, the agreements ranged from less than $1 million to $88 million with a weighted average interest rate of 4.32%. Of the amounts outstanding under supplier financing arrangements, $607 million and $296 million were guaranteed by the Parent Company as of September 30, 2023 and December 31, 2022, respectively.

New Accounting Pronouncements Adopted in 2023 — The following table provides a brief description of recent accounting pronouncements that had an impact on the Company’s condensed consolidated financial statements. Accounting pronouncements not listed below were assessed and determined to be either not applicable or ~~may~~did not have a material impact on the Company’s condensed consolidated financial statements.


New Accounting Standards Adopted
ASU Number and Name	Description	Date of Adoption	Effect on the financial statements upon adoption
2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers	This update is to improve the accounting for acquired revenue contracts with customers in a business combination by addressing diversity in practice and inconsistency related to the following: (1) recognition of an acquired contract liability, and (2) payment terms and their effect on subsequent revenue recognized by the acquirer. Early adoption of the amendments is permitted, including adoption in an interim period. An entity that early adopts in an interim period should apply the amendments (1) retrospectively to all business combinations for which the acquisition date occurs on or after the beginning of the fiscal year that includes the interim period of early application and (2) prospectively to all business combinations that occur on or after the date of initial application.	January 1, 2023	The Company adopted this standard on a prospective basis, which is being applied to any business combinations that occur in 2023 or after. The adoption of this ASU did not have a material impact on the Company's consolidated financial statements.

11 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022


2022-02 Financial Instruments - Credit Losses (Topic 326): Troubled Debt Restructurings and Vintage Disclosures	ASU 2022-02 amends ASC 326-20-50-6 to require public business entities to disclose gross write-offs recorded in the current period, on a year-to-date basis, by year of origination in the vintage disclosures. This disclosure should cover each of the previous five annual periods starting with the date of the financial statements and, for the annual periods before that, an aggregate total. However, upon adoption of the ASU, an entity would not provide the previous five annual periods of gross write-offs. The FASB decided that disclosure of gross write-offs would instead be applied on a prospective transition basis so that preparers can “build” the five-annual-period disclosure over time.	January 1, 2023	The Company adopted this standard on a prospective basis and it did not have a material impact on the financial statements.
2022-04,Liabilities - Supplier Finance Programs (Topic 450-50): Disclosure of Supplier Finance Program Obligations	This update is to provide additional information and disclosures about an entity’s use of supplier finance programs to see how these programs will affect an entity’s working capital, liquidity, and cash flows. Entities that use supplier finance programs as the buyer party should disclose (1) the key terms of the payment terms and assets pledged as security or other forms of guarantees provided and (2) the unpaid amount outstanding, a description of where those obligations are presented on the balance sheet, and a rollforward of those obligations during the annual period.	January 1, 2023, except for the rollforward information, which is effective for fiscal years beginning after December 15, 2023.	The ASU only requires disclosures related to the Company's supplier finance programs and does not affect the recognition, measurement, or presentation of supplier finance program obligations on the balance sheet or cash flow statement. The Company adopted the new disclosure requirements in the first quarter of 2023, except for the annual requirement to disclose rollforward information, which the Company expects to adopt and present prospectively beginning in the 2024 annual financial statements.
2023-03, Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718)	This Accounting Standards Update amends various SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 120, SEC Staff Announcement at the March 24, 2022 EITF Meeting, and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280—General Revision of Regulation S-X: Income or Loss Applicable to Common Stock. The amendments in this Update are effective for all entities upon issuance of this Update.	June 30, 2023	The adoption of this ASU did not have a material impact on the Company’s consolidated financial statements.

New Accounting Pronouncements Issued But Not Yet Effective — The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company’s condensed consolidated financial statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company’s condensed consolidated financial statements.

12 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022



~~New Accounting Standards Adopted~~
~~ASU Number and Name~~	~~Description~~	~~Date of Adoption~~	~~Effect on the financial statements upon adoption~~
~~2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~	The standard simplifies the following aspects of accounting for share-based payments awards: accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities and classification of employee taxes paid on statement of cash flows when an employer withholds shares for tax-withholding purposes. Transition method: The recognition of excess tax benefits and tax deficiencies arising from vesting or settlement were applied retrospectively. The elimination of the requirement that excess tax benefits be realized before they are recognized was adopted on a modified retrospective basis.	~~January 1, 2017~~	The recognition of excess tax benefits in the provision for income taxes in the period when the awards vest or are settled, rather than in paid-in-capital in the period when the excess tax benefits are realized, resulted in a decrease of $31 million to deferred tax liabilities, offset by an increase to retained earnings.



New Accounting Standards Issued But Not Yet Effective
ASU Number and Name			Description	Date of Adoption	Effect on the financial statements upon adoption
~~2017-12, Derivatives and Hedging (Topic 815): Targeted improvements to Accounting for Hedging Activities~~	The standard updates the hedge accounting model to expand the ability to hedge risk, reduce complexity, and ease certain documentation and assessment requirements. It also eliminates the requirement to separately measure and report hedge ineffectiveness, and generally requires the change in fair value of a hedging instrument to be presented in the same income statement line as the hedged item. ~~Transition method: modified retrospective and prospective for presentation and disclosures.~~	~~January 1, 2019. Early adoption is permitted.~~	~~The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.~~
2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): Accounting for Certain Financial Instruments and Certain Mandatorily Redeemable Noncontrolling Interests	~~Part 1 of this standard changes the classification of certain equity-linked financial instruments when assessing whether the instrument is indexed to an entity’s own stock.~~ ~~Transition method: retrospective.~~	~~January 1, 2019. Early adoption is permitted.~~	~~The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.~~

~~2017-08, Receivables — Nonrefundable Fees~~2023-05 Business Combinations - Joint Venture Formations (Subtopic 805-60): Recognition and ~~Other Costs (Subtopic 310-20): Premium Amortization~~Initial Measurement

The amendments in this Update address the accounting for contributions made to a joint venture, upon formation, in a joint venture’s separate financial statements. The objectives of the amendments are to (1) provide decision-useful information to investors and other allocators of capital (collectively, investors) in a joint venture’s financial statements and (2) reduce diversity in practice. To reduce diversity in practice and provide decision-useful information to a joint venture’s investors, the Board decided to require that a joint venture apply a new basis of accounting upon formation. By applying a new basis of accounting, a joint venture, upon formation, will recognize and initially measure its assets and liabilities at fair value (with exceptions to fair value measurement that are consistent with the business combinations guidance). The amendments in this Update do not amend the definition of a joint venture (or a corporate joint venture), the accounting by an equity method investor for its investment in a joint venture, or the accounting by a joint venture for contributions received after its formation.

The amendments in this Update permit a joint venture to apply the measurement period guidance in Subtopic 805-10 if the initial accounting for a joint venture formation is incomplete by the end of the reporting period in which the formation occurs.

Prospectively for all Joint Venture formations with a formation date on ~~Purchased Callable Debt Securities~~

~~This standard shortens the period of amortization for the premium on certain callable debt securities to the earliest call date.~~

~~Transition method: modified retrospective.~~

or after January 1, ~~2019. Early adoption is permitted.~~2025. For Joint Ventures formed before January 1, 2025, entities may elect to apply the amendments retrospectively if it has sufficient information.

The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.

~~2017-07, Compensation — Retirement Benefits (Topic 715): Improving~~2023-06 Disclosure Improvements: Codification Amendments in Response to the ~~Presentation~~SEC’s Disclosure Update and Simplification Initiative

In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of ~~Net Periodic Pension Cost~~its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC.

The amendments in this Update represent changes to clarify or improve disclosure and ~~Net Periodic Postretirement Benefit Cost~~presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.

~~This standard changes the presentation of non-service cost associated with defined benefit plans and updates the guidance so that only the service cost component~~The effective date for each amendment will be ~~eligible for capitalization.~~

~~Transition method: Retrospective for presentation~~the date on which the SEC's removal of ~~non-service cost expense. Prospective for the change~~that related disclosure becomes effective, with early adoption prohibited. The amendments in ~~capitalization.~~

~~January 1, 2018. Early adoption is permitted.~~this Update should be applied prospectively.

The Company ~~expects~~will provide the ~~adoption of this standard to result in~~required disclosures on a ~~$144 million reclassification of non-service pension costs from Cost of Sales to Other Expense for 2016.~~prospective basis on the date each amendment becomes effective. The Company ~~plans~~does not expect ASU 2023-06 will have any impact to ~~adopt the standard as of January 1, 2018.~~

~~2017-05, Other Income — Gains and Losses from the Derecognition of Nonfinancial Assets (Topic 610-20)~~

This standard clarifies the scope and application of ASC 610-20 on the sale, transfer, and derecognition of nonfinancial assets and in substance nonfinancial assets to non-customers, including partial sales. It also clarifies that the derecognition of businesses is under scope of ASC 810. The standard must be adopted concurrently with ASC 606, however an entity will not have to apply the same transition method as ASC 606.

~~Transition method: full or modified retrospective.~~

Under a modified retrospective approach, the guidance shall be applied to all contracts that are not completed as of the initial application date (January 1, 2018). The Company is in the process of identifying contracts that would not be completed as of January 1, 2018. Based on the assessment of contracts already executed as of September 30, 2017, the contracts that may require any type of assessment under the new standard are limited.

~~January 1, 2018. Early adoption is permitted only as of January 1, 2017.~~

The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements, will adopt the standard on January 1, 2018, and plans to use the modified retrospective approach.

~~2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment~~

This standard simplifies the accounting for goodwill impairment by removing the requirement to calculate the implied fair value. Instead, it requires that an entity records an impairment charge based on the excess of a reporting unit's carrying amount over its fair value.
~~Transition method: prospective.~~

~~January 1, 2020. Early adoption is permitted as of January 1, 2017.~~

~~The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.~~

~~2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)~~

This standard requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows.

~~Transition method: retrospective.~~

~~January 1, 2018. Early adoption is permitted.~~

~~The Company has performed a preliminary evaluation. However, foreign exchange impacts on movements related to restricted cash have not been quantified.~~

~~2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory~~

~~This standard requires that an entity recognizes the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs.~~

~~Transition method: modified retrospective.~~

~~January 1, 2018. Early adoption is permitted.~~

~~The Company is currently evaluating the impact of adopting the standard on its~~our consolidated financial statements.

~~2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments~~

The standard updates the impairment model for financial assets measured at amortized cost to an expected loss model rather than an incurred loss model. It also allows for the presentation of credit losses on available-for-sale debt securities as an allowance rather than a write down.

~~Transition method: various.~~

~~January 1, 2020. Early adoption is permitted only as of January 1, 2019.~~

~~The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements.~~



~~2016-02, Leases (Topic 842)~~			This standard requires lessees to recognize assets and liabilities for most leases but recognize expenses in a manner similar to today’s accounting. For Lessors, the guidance modifies the lease classification criteria and the accounting for sales-type and direct financing leases. The guidance also eliminates today’s real estate-specific provisions. ~~Transition method: modified retrospective at the beginning of the earliest comparative period presented in the financial statements (January 1, 2017).~~ The Company has established a task force focused on the identification of contracts that would be under the scope of the new standard and on the assessment and measurement of the right-of-use asset and related liability. The implementation team is in the process of evaluating changes to our business processes, systems and controls to support recognition and disclosure under the new standard.	~~January 1, 2019. Early adoption is permitted.~~	~~The Company is currently evaluating the impact of adopting the standard on its consolidated financial statements and intends to adopt the standard as of January 1, 2019.~~
~~2014-09, 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, Revenue from Contracts with Customers (Topic 606)~~	~~See discussion of the ASU below.~~	~~January 1, 2018. Early adoption is permitted only as of January 1, 2017.~~	~~The Company will adopt the standard on January 1, 2018; see below for the evaluation of the impact of its adoption on the consolidated financial statements.~~

ASU 2014-09 and its subsequent corresponding updates provide the principles an entity must apply to measure and recognize revenue. The core principle is that an entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Amendments to the standard were issued that provide further clarification of the principle and to provide certain transition expedients. The standard will replace most existing revenue recognition guidance in GAAP.

In 2016, the Company established a cross-functional implementation team and is in the process of evaluating and implementing changes to our business processes, systems, and controls to support recognition and disclosure under the new standard. At this time, we do not expect any significant impact on our financial systems or a material change to controls as a result of the implementation of the new revenue recognition standard.

Given the complexity and diversity of our non-regulated arrangements, the Company is assessing the standard on a contract-by-contract basis and is in the process of completing the contract assessments by applying the interpretations reached during 2017 on key issues. These issues include the application of the practical expedient for measuring progress towards satisfaction of a performance obligation, when variable quantities would be considered variable consideration versus an option to acquire additional goods and services and how to allocate variable consideration to one or more, but not all, distinct goods or services promised in a series of distinct goods or services that forms part of a single performance obligation. Additionally, the Company is working on the application of the standard to contracts that are under the scope of Service Concession Arrangements (Topic 853) and assessing the gross versus net presentation for spot energy sales and purchases. Through this assessment, the Company to date has identified limited situations where revenue recognized under ASC 606 could differ from that recognized under ASC 605 and where the presentation of sales to and purchases from the energy spot markets will change. The main change that the Company is expecting to have is related to a contract under the scope of Topic 853. The Company will continue its work to complete the assessment of the full population of contracts and determine the overall impact to the consolidated financial statements.

The standard requires retrospective application and allows either a full retrospective adoption in which all periods are presented under the new standard or a modified retrospective approach in which the cumulative effect of initially applying the guidance is recognized at the date of initial application. Although we had previously been working toward adopting the standard using the full retrospective method, given the limited impact of the situations where revenue recognized under ASC 606 differs from that recognized under ASC 605, we now expect to use the modified retrospective approach. However, the Company will continue to assess this conclusion which is dependent on the final impact to the financial statements.

We are continuing to work with various non-authoritative industry groups, and monitoring the FASB and Transition Resource Group activity, as we finalize our accounting policy on these and other industry specific interpretative issues, which is expected in 2017.

2. INVENTORY

The following table summarizes the Company’s inventory balances as of the periods indicated (in millions):


	September 30, 2023		December 31, 2022
Fuel and other raw materials	$	498	$	733
Spare parts and supplies	300		322
Total	$	798	$	1,055

September 30, 2017 December 31, 2016
Fuel and other raw materials $ 350
$ 302
Spare parts and supplies 310
328
Total $ 660
$ 630

3. FAIR VALUE

The fair value of current financial assets and liabilities, debt service reserves, and other deposits approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. ~~By virtue of~~Because these amounts ~~being~~are 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 Company made no changes during the period to the fair~~For further information on our valuation techniques ~~described in~~and policies, see Note 4—5—Fair Value in Item 8.—Financial Statements and Supplementary Data of ~~its 2016~~our 2022 Form 10-K.

Recurring Measurements—

The following table presents, 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 the dates indicated (in millions). For the Company’s investments in marketable debt ~~and equity~~ securities, the security classes presented ~~are~~were determined based on the nature and risk of the security and are consistent with how the Company manages, monitors, and measures its marketable securities:

13 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022


	September 30, 2017								December 31, 2016									September 30, 2023								December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets																	Assets
AVAILABLE FOR SALE:
Debt securities:
Unsecured debentures	$	—	$	157	$	—	$	157	$	—	$	360	$	—	$	360
DEBT SECURITIES:																	DEBT SECURITIES:
Available-for-sale:																	Available-for-sale:

Certificates of deposit	—		340		—		340		—		372		—		372		Certificates of deposit	$	—	$	493	$	—	$	493	$	—	$	698	$	—	$	698
Government debt securities	—		—		—		—		—		9		—		9		Government debt securities	—		—		—		—		—		3		—		3
Subtotal	—		497		—		497		—		741		—		741
Equity securities:
Total debt securities																	Total debt securities	—		493		—		493		—		701		—		701
EQUITY SECURITIES:																	EQUITY SECURITIES:
Mutual funds	—		54		—		54		—		49		—		49		Mutual funds	43		—		—		43		38		—		—		38
Subtotal	—		54		—		54		—		49		—		49
Total available for sale	—		551		—		551		—		790		—		790
TRADING:
Equity securities:
Mutual funds	20		—		—		20		16		—		—		16
Total trading	20		—		—		20		16		—		—		16

Total equity securities																	Total equity securities	43		7		—		50		38		—		—		38
DERIVATIVES:																	DERIVATIVES:
Interest rate derivatives	—		13		—		13		—		18		—		18		Interest rate derivatives	—		478		—		478		—		314		—		314
Cross-currency derivatives	—		14		—		14		—		4		—		4

Foreign currency derivatives	—		37		242		279		—		54		255		309		Foreign currency derivatives	—		22		46		68		—		22		64		86
Commodity derivatives	—		44		8		52		—		38		7		45		Commodity derivatives	—		137		4		141		—		232		13		245
Total derivatives — assets	—		108		250		358		—		114		262		376		Total derivatives — assets	—		637		50		687		—		568		77		645
TOTAL ASSETS	$	20	$	659	$	250	$	929	$	16	$	904	$	262	$	1,182	TOTAL ASSETS	$	43	$	1,137	$	50	$	1,230	$	38	$	1,269	$	77	$	1,384
Liabilities																	Liabilities
Contingent consideration																	Contingent consideration	$	—	$	—	$	267	$	267	$	—	$	—	$	48	$	48
DERIVATIVES:																	DERIVATIVES:
Interest rate derivatives	$	—	$	104	$	192	$	296	$	—	$	121	$	179	$	300	Interest rate derivatives	—		—		—		—		—		6		—		6
Cross-currency derivatives	—		5		—		5		—		18		—		18		Cross-currency derivatives	—		54		—		54		—		42		—		42
Foreign currency derivatives	—		42		—		42		—		64		—		64		Foreign currency derivatives	—		26		—		26		—		20		—		20
Commodity derivatives	—		16		2		18		—		40		2		42		Commodity derivatives	—		127		80		207		—		346		60		406
Total derivatives — liabilities	—		167		194		361		—		243		181		424		Total derivatives — liabilities	—		207		80		287		—		414		60		474
TOTAL LIABILITIES	$	—	$	167	$	194	$	361	$	—	$	243	$	181	$	424	TOTAL LIABILITIES	$	—	$	207	$	347	$	554	$	—	$	414	$	108	$	522

As of September 30, ~~2017,~~2023, all ~~AFS~~available-for-sale debt securities had stated maturities within one year. ~~For~~There were no other-than-temporary impairments of marketable securities during the three and nine months ended September 30, ~~2017 and 2016, no other-than-temporary~~2023. The level 3 contingent consideration relates mainly to the acquisition of Bellefield on June 5, 2023. For further information on the acquisition, see Note 18—Acquisitions. Credit-related impairments ~~of marketable securities were~~are recognized in earnings or ~~Other Comprehensive Income (Loss)~~.under ASC 326. Gains and losses on the sale of investments are determined using the specific-identification method. The following table presents gross proceeds from the sale of ~~AFS~~available-for-sale securities during the periods indicated (in millions):

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Gross proceeds from sale of AFS securities $ 1,020
$ 812
$ 2,982
$ 3,216


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Gross proceeds from sale of available-for-sale securities	$	308	$	318	$	1,047	$	665

The following tables present a reconciliation of ~~net derivative~~ assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and nine months ended September 30, ~~2017~~2023 and ~~2016~~2022 (presented net by type of derivative in millions). Transfers between Level 3 and Level 2 ~~are determined as of the end of the reporting period and~~ principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.

14 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022


														Derivative Assets and Liabilities
Three Months Ended September 30, 2017	Interest Rate			Foreign Currency			Commodity			Total
Balance at July 1	$	(195	)	$	239		$	9		$	53
Three Months Ended September 30, 2023													Three Months Ended September 30, 2023	Interest Rate		Foreign Currency		Commodity		Contingent Consideration		Total
Balance at July 1, 2023													Balance at July 1, 2023	$	(1)	$	63	$	(78)	$	(274)	$	(290)
Total realized and unrealized gains (losses):													Total realized and unrealized gains (losses):
Included in earnings	(5		)	12			—			7			Included in earnings	—		(6)		(3)		(1)		(10)
Included in other comprehensive income — derivative activity	(2		)	—			—			(2		)
Included in other comprehensive income (loss) — derivative activity													Included in other comprehensive income (loss) — derivative activity	5		(2)		7		—		10

Acquisitions													Acquisitions	—		—		—		3		3
Settlements	10			(9		)	(3		)	(2		)	Settlements	—		(9)		(2)		5		(6)
Balance at September 30	$	(192	)	$	242		$	6		$	56

Transfers of assets, net out of Level 3													Transfers of assets, net out of Level 3	(4)		—		—		—		(4)
Balance at September 30, 2023													Balance at September 30, 2023	$	—	$	46	$	(76)	$	(267)	$	(297)
Total (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period													Total (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	—	$	(13)	$	(3)	$	(1)	$	(17)

														Derivative Assets and Liabilities
Three Months Ended September 30, 2022													Three Months Ended September 30, 2022	Interest Rate		Foreign Currency		Commodity		Contingent Consideration		Total
Balance at July 1, 2022													Balance at July 1, 2022	$	1	$	50	$	37	$	(80)	$	8
Total realized and unrealized gains (losses):													Total realized and unrealized gains (losses):
Included in earnings													Included in earnings	1		22		(1)		4		26
Included in other comprehensive income (loss) — derivative activity													Included in other comprehensive income (loss) — derivative activity	(1)		7		(14)		—		(8)
Included in other comprehensive income (loss) — foreign currency translation activity													Included in other comprehensive income (loss) — foreign currency translation activity	—		—		—		1		1
Included in regulatory (assets) liabilities													Included in regulatory (assets) liabilities	—		—		(3)		—		(3)

Settlements													Settlements	—		(9)		—		16		7
Transfers of liabilities, net into Level 3													Transfers of liabilities, net into Level 3	—		—		(2)		—		(2)
Transfers of assets, net out of Level 3													Transfers of assets, net out of Level 3	(2)		—		(15)		—		(17)
Balance at September 30, 2022													Balance at September 30, 2022	$	(1)	$	70	$	2	$	(59)	$	12
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	(1	)	$	3		$	—		$	2		Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	—	$	14	$	(1)	$	4	$	17

15 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

Three Months Ended September 30, 2016 Interest Rate Foreign Currency Commodity Total
Balance at July 1 $ (421 ) $ 271
$ 11
$ (139 )
Total realized and unrealized gains (losses):
Included in earnings (1 ) 12
1
12
Included in other comprehensive income — derivative activity 6
—
—
6
Included in other comprehensive income — foreign currency translation activity —
(5 ) —
(5 )
Settlements 17
(4 ) (3 ) 10
Transfers of liabilities into Level 3 (2 ) —
—
(2 )
Transfers of liabilities out of Level 3 94
—
—
94
Balance at September 30 $ (307 ) $ 274
$ 9
$ (24 )
Total gains for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $ —
$ 8
$ 1
$ 9

Nine Months Ended September 30, 2017 Interest Rate Foreign Currency Commodity Total
Balance at January 1 $ (179 ) $ 255
$ 5
$ 81
Total realized and unrealized gains (losses):
Included in earnings (5 ) 12
(1 ) 6
Included in other comprehensive income — derivative activity (29 ) —
—
(29 )
Included in regulatory liabilities —
—
10
10
Settlements 28
(25 ) (8 ) (5 )
Transfers of liabilities into Level 3 (7 ) —
—
(7 )
Balance at September 30 $ (192 ) $ 242
$ 6
$ 56
Total losses for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $ —
$ (12 ) $ —
$ (12 )

Nine Months Ended September 30, 2016 Interest Rate Foreign Currency Commodity Total
Balance at January 1 $ (304 ) $ 277
$ 3
$ (24 )
Total realized and unrealized gains (losses):
Included in earnings —
30
3
33
Included in other comprehensive income — derivative activity (172 ) 6
—
(166 )
Included in other comprehensive income — foreign currency translation activity (3 ) (43 ) —
(46 )
Included in regulatory liabilities —
—
11
11
Settlements 56
(8 ) (8 ) 40
Transfers of liabilities into Level 3 (2 ) —
—
(2 )
Transfers of assets out of Level 3 118
12
—
130
Balance at September 30 $ (307 ) $ 274
$ 9
$ (24 )
Total gains for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $ 5
$ 25
$ 3
$ 33


	Derivative Assets and Liabilities
Nine Months Ended September 30, 2023	Interest Rate		Foreign Currency		Commodity		Contingent Consideration		Total
Balance at January 1, 2023	$	—	$	64	$	(47)	$	(48)	$	(31)
Total realized and unrealized gains (losses):
Included in earnings	—		—		(3)		(9)		(12)
Included in other comprehensive income (loss) — derivative activity	2		—		(20)		—		(18)
Included in other comprehensive income (loss) — foreign currency translation activity	—		—		—				—
Included in regulatory (assets) liabilities	—		—		(2)		—		(2)
Acquisitions	—		—		—		(215)		(215)
Settlements	—		(18)		(5)		5		(18)

Transfers of (assets) liabilities, net out of Level 3	(2)		—		1		—		(1)
Balance at September 30, 2023	$	—	$	46	$	(76)	$	(267)	$	(297)
Total (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	—	$	(14)	$	(4)	$	(9)	$	(27)

	Derivative Assets and Liabilities
Nine Months Ended September 30, 2022	Interest Rate		Foreign Currency		Commodity		Contingent Consideration		Total
Balance at January 1, 2022	$	(6)	$	108	$	(1)	$	(67)	$	34
Total realized and unrealized gains (losses):
Included in earnings	4		(22)		(4)		4		(18)
Included in other comprehensive income (loss) — derivative activity	13		(7)		(7)		—		(1)
Included in other comprehensive income (loss) — foreign currency translation activity	—		—		—		(1)		(1)
Included in regulatory (assets) liabilities	—		—		13		—		13
Acquisitions	—		—		—		(15)		(15)
Settlements	(1)		(9)		1		20		11

Transfers of assets, net out of Level 3	(11)		—		—		—		(11)
Balance at September 30, 2022	$	(1)	$	70	$	2	$	(59)	$	12
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	3	$	(44)	$	1	$	4	$	(36)

The following table summarizes the significant unobservable inputs used for Level 3 derivative assets (liabilities) as of September 30, ~~2017~~2023 (in millions, except range amounts):

Type of Derivative Fair Value Unobservable Input Amount or Range (Weighted Average)
Interest rate $ (192 ) Subsidiaries’ credit spreads 2.4% to 5.1% (4.7%)
Foreign currency:
Argentine Peso 242

Argentine Peso to USD currency exchange rate after one year ⁽¹⁾
21.3 to 47.8 (33.8)
Commodity:
Other 6

Total $ 56

~~_____________________________~~

⁽¹⁾

Type of Derivative

~~During the nine months ended September 30, 2017, the Company began utilizing the interest~~

Fair Value

Unobservable Input

Amount or Range (Weighted Average)

Foreign currency:

Argentine peso

Argentine peso to U.S. dollar currency exchange rate ~~differential approach to construct the remaining portion of the forward curve~~ after one year ~~(beyond the traded points). In previous periods, the Company used the purchasing price parity approach~~

860 to ~~construct the forward curve.~~1,500 (1,222)

Commodity:

CAISO Energy Swap

(79)

Forward energy prices per MWh after 2030

$12 to $96 ($52)

Other

Total

(30)

For interest rate derivatives and foreign currency derivatives, increases (decreases) in the estimates of the Company’s own credit spreads would decrease (increase) the value of the derivatives in a liability position. For foreign currency derivatives, increases (decreases) in the estimate of the above exchange rate would increase (decrease) the value of the derivative.

Contingent consideration is primarily related to future milestone payments associated with acquisitions of renewable development projects. The estimated fair value of contingent consideration is determined using probability-weighted discounted cash flows based on internal forecasts, which are considered Level 3 inputs. Changes in Level 3 inputs, particularly changes in the probability of achieving development milestones, could result in material changes to the fair value of the contingent consideration and could materially impact the amount of expense or income recorded each reporting period. Contingent consideration is updated quarterly with any prospective changes in fair value recorded through earnings.

Nonrecurring Measurements

~~When evaluating impairment of long-lived assets~~

16 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and ~~equity method investments, the~~2022

The Company measures fair value using the applicable fair value measurement guidance. Impairment expense, shown as pre-tax loss below, is measured by comparing the fair value at the evaluation date to the then-latest available carrying ~~amount.~~amount and is included in Asset impairment expense on the Condensed Consolidated Statements of Operations. The following table summarizes our major categories of ~~assets and liabilities~~asset groups measured at fair value on a nonrecurring basis and their level within the fair value hierarchy (in millions):.

Nine Months Ended September 30, 2017 Measurement Date
Carrying Amount (1)
Fair Value Pretax Loss
Assets Level 1 Level 2 Level 3
Long-lived assets held and used: ⁽²⁾

DPL 02/28/2017 $ 77
$ —
$ —
$ 11
$ 66
Tait Energy Storage 02/28/2017 15
—
—
7
8
Dispositions and held-for-sale businesses: ⁽³⁾

Kazakhstan Hydroelectric 06/30/2017 190
—
92
—
92
Kazakhstan CHPs 03/31/2017 171
—
29
—
94

Nine Months Ended September 30, 2016 Measurement Date
Carrying Amount (1)
Fair Value Pretax Loss
Assets Level 1 Level 2 Level 3
Long-lived assets held and used: ⁽²⁾

Buffalo Gap I 08/31/2016 $ 113
$ —
$ —
$ 35
$ 78
DPL 06/30/2016 324
—
—
89
235
Buffalo Gap II 03/31/2016 251
—
—
92
159
Discontinued operations and held-for-sale businesses: ⁽³⁾

Sul 06/30/2016 1,581
—
470
—
783


	Measurement Date	Carrying Amount (1)		Fair Value						Pre-tax Loss
Nine Months Ended September 30, 2023				Level 1		Level 2		Level 3
Long-lived asset groups held and used:
Norgener (2)	5/1/2023	$	196	$	—	$	—	$	24	$	137
GAF Projects (AES Renewable Holdings)	5/31/2023	29		—		—		11		18
TEP	7/31/2023	153		—		—		94		59
TEG	7/31/2023	170		—		—		93		77
Held-for-sale businesses: (3)
Jordan (4)	3/31/2023	$	179	$	—	$	170	$	—	$	14
Jordan (4)	6/30/2023	179		—		170		—		15
Jordan (4)	9/30/2023	178		—		170		—		14

	Measurement Date	Carrying Amount (1)		Fair Value
Nine Months Ended September 30, 2022				Level 1		Level 2		Level 3		Pre-tax Loss
Long-lived asset groups held and used:
Maritza	4/30/2022	$	920	$	—	$	—	$	452	$	468
Held-for-sale businesses: (3)
Jordan (4)	9/30/2022	216		—		170		—		51

_____________________________

⁽¹⁾

(1)Represents the carrying values of the asset groups at the dates of measurement, before fair value adjustment.

(2)The Norgener asset group includes long-lived assets, inventory, land, and other working capital, however per ASC 360-10, the pre-tax impairment expense is limited to the carrying amount of the long-lived assets. See Note 15—Asset Impairment Expense for further information. The Company evaluated the carrying amount of the assets outside the scope of ASC 360-10 and determined that the carrying value of the other assets should not be reduced.

(3)See Note 17—Held-for-Sale for further information.

(4)The pre-tax loss recognized was calculated using the $170 million fair value of the Jordan disposal group less costs to sell of $5 million for the September 30, 2022 and March 31, 2023 measurement dates and $6 million for the June 30, 2023 and September 30, 2023 measurement dates.

~~Represents the carrying values at the dates of measurement, before fair value adjustment.~~


⁽²⁾	~~See Note 14—Asset Impairment Expense~~ ~~for further information.~~


⁽³⁾	~~Per the Company’s policy, pretax loss is limited to the impairment of long-lived assets. Any additional loss will be recognized on completion of the sale. See Note 16—Held-for-Sale Businesses and Dispositions~~ ~~for further information.~~

The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets held and used measured on a nonrecurring basis during the nine months ended September 30, ~~2017~~2023 (in millions, except range amounts):

Fair Value

Valuation Technique

Unobservable Input

Range (Weighted Average)

Long-lived asset groups held and used:

TEP

Discounted cash flow

Annual revenue growth

(31)% to 6% (-2%)

Annual variable margin

22% to 37% (26%)

Discount rate

14% to 25% (14%)

TEG

Discounted cash flow

Annual revenue growth

(7)% to 9% (—%)

Annual variable margin

14% to 33% (20%)

Discount rate

14% to 25% (14%)

Norgener (1)

Discounted cash flow

Annual revenue growth

(90)% to 994% (85%)

Annual variable margin

(75)% to 276% (16%)

GAF Projects (AES Renewable Holdings)

Discounted cash flow

Annual revenue growth

(42)% to 44% (1%)

Annual variable margin

(194)% to 77% (66%)

Discount rate

Total

222

Fair Value Valuation Technique Unobservable Input Range (Weighted Average)
Long-lived assets held and used:
DPL $ 11
Discounted cash flow Pretax operating margin (through remaining life) 10% to 22% (15%)
Weighted average cost of capital 7%
Tait Energy Storage 7
Discounted cash flow Annual pretax operating margin 46% to 85% (80%)
Weighted average cost of capital 9%
_____________________________

(1)The fair value of the Norgener asset group is mainly related to existing coal inventory not subject to impairment under ASC 360-10.

Financial Instruments not Measured at Fair Value in the Condensed Consolidated Balance Sheets

The following table presents (in millions) the carrying amount, fair value, and fair value hierarchy of the Company’s financial assets and liabilities that are not measured at fair value in the Condensed Consolidated Balance Sheets as of ~~September 30, 2017 and December 31, 2016,~~the periods indicated, but for which fair value is disclosed:

17 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022


		September 30, 2017												September 30, 2023
		Carrying Amount		Fair Value										Carrying Amount		Fair Value
				Total		Level 1		Level 2		Level 3						Total		Level 1		Level 2		Level 3
Assets:	Accounts receivable — noncurrent ⁽¹⁾	$	200	$	262	$	—	$	6	$	256	Assets:	Accounts receivable — noncurrent (1)	$	117	$	153	$	—	$	—	$	153
Liabilities:	Non-recourse debt	17,079		17,706		—		15,479		2,227		Liabilities:	Non-recourse debt	21,618		21,108		—		19,646		1,462
	Recourse debt	4,958		5,266		—		5,266		—			Recourse debt	5,564		5,106		—		5,106		—


		December 31, 2016												December 31, 2022
		Carrying Amount		Fair Value										Carrying Amount		Fair Value
				Total		Level 1		Level 2		Level 3						Total		Level 1		Level 2		Level 3
Assets:	Accounts receivable — noncurrent ⁽¹⁾	$	264	$	350	$	—	$	20	$	330	Assets:	Accounts receivable — noncurrent (1)	$	301	$	340	$	—	$	—	$	340
Liabilities:	Non-recourse debt	15,792		16,188		—		15,120		1,068		Liabilities:	Non-recourse debt	19,429		18,527		—		17,089		1,438
	Recourse debt	4,671		4,899		—		4,899		—			Recourse debt	3,894		3,505		—		3,505		—

_____________________________


⁽¹⁾	~~These amounts primarily relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and are included in~~ ~~Other noncurrent assets~~ in the accompanying Condensed Consolidated Balance Sheets. The fair value and carrying amount of these receivables exclude VAT of $38 million and $24 million as of September 30, 2017 and December 31, 2016, respectively.

(1)These amounts primarily relate to amounts impacted by the Stabilization Funds enacted by the Chilean government, and are included in Other noncurrent assets in the accompanying Condensed Consolidated Balance Sheets.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

~~There are no changes to~~For further information on the ~~information disclosed in~~Company’s derivative and hedge accounting policies, see Note 1—General and Summary of Significant Accounting Policies—Derivatives and Hedging Activities of Item 8.—Financial Statements and Supplementary Data in the ~~2016~~2022 Form 10-K.

Volume of Activity — The following ~~table presents~~tables present the Company’s maximum notional (in millions) over the remaining contractual period by type of derivative as of September 30, ~~2017,~~2023, regardless of whether they are in qualifying cash flow hedging relationships, and the dates through which the maturities for each type of derivative range:


Interest Rate and Foreign Currency Derivatives	Maximum Notional Translated to USD		Latest Maturity
Interest rate	$	5,949	2059
Cross-currency swaps (Brazilian real)	404		2026
Foreign Currency:
Chilean peso	220		2026
Euro	100		2026
Mexican peso	73		2024
Colombian peso	43		2025
Brazilian real	39		2026
Argentine peso	2		2026

Derivatives Maximum Notional Translated to USD Latest Maturity
Interest Rate (LIBOR and EURIBOR) $ 4,557
2035
Cross-Currency Swaps (Chilean Unidad de Fomento and Chilean Peso) 394
2029
Foreign Currency:
Argentine Peso 233
2026
Chilean Peso 504
2020
Colombian Peso 255
2019
Others, primarily with weighted average remaining maturities of a year or less 326
2020


Commodity Derivatives	Maximum Notional	Latest Maturity
Natural Gas (in MMBtu)	62	2029
Power (in MWhs)	14	2040
Coal (in Tons or Metric Tons)	5	2025

Accounting and Reporting —Assets and Liabilities — The following tables present the fair value of the Company’s derivative assets and liabilities ~~related to the Company’s derivative instruments~~ as of the periods indicated (in millions):


Fair Value	September 30, 2023						December 31, 2022
Assets	Designated		Not Designated		Total		Designated		Not Designated		Total
Interest rate derivatives	$	478	$	—	$	478	$	313	$	1	$	314

Foreign currency derivatives	20		48		68		27		59		86
Commodity derivatives	—		141		141		—		245		245
Total assets	$	498	$	189	$	687	$	340	$	305	$	645
Liabilities
Interest rate derivatives	$	—	$	—	$	—	$	6	$	—	$	6
Cross-currency derivatives	54		—		54		42		—		42
Foreign currency derivatives	11		15		26		9		11		20
Commodity derivatives	79		128		207		59		347		406
Total liabilities	$	144	$	143	$	287	$	116	$	358	$	474


	September 30, 2023				December 31, 2022
Fair Value	Assets		Liabilities		Assets		Liabilities
Current	$	355	$	113	$	271	$	168
Noncurrent	332		174		374		306
Total	$	687	$	287	$	645	$	474

18 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, ~~2017~~2023 and ~~December 31, 2016 (in millions):~~

2022

Fair Value September 30, 2017 December 31, 2016
Assets Designated Not Designated Total Designated Not Designated Total
Interest rate derivatives $ 13
$ —
$ 13
$ 18
$ —
$ 18
Cross-currency derivatives 14
—
14
4
—
4
Foreign currency derivatives 5
274
279
9
300
309
Commodity derivatives 7
45
52
20
25
45
Total assets $ 39
$ 319
$ 358
$ 51
$ 325
$ 376
Liabilities
Interest rate derivatives $ 151
$ 145
$ 296
$ 295
$ 5
$ 300
Cross-currency derivatives 5
—
5
18
—
18
Foreign currency derivatives 7
35
42
19
45
64
Commodity derivatives 5
13
18
26
16
42
Total liabilities $ 168
$ 193
$ 361
$ 358
$ 66
$ 424

September 30, 2017 December 31, 2016
Fair Value Assets Liabilities Assets Liabilities
Current $ 101
$ 221
$ 99
$ 155
Noncurrent 257
140
277
269
Total $ 358
$ 361
$ 376
$ 424

Credit Risk-Related Contingent Features ⁽¹⁾
September 30, 2017 December 31, 2016
Present value of liabilities subject to collateralization $ 12
$ 41
Cash collateral held by third parties or in escrow 5
18

~~_____________________________~~


⁽¹⁾	~~Based on the credit rating of certain subsidiaries~~

Earnings and Other Comprehensive Income (Loss) — The ~~next~~following table presents ~~(in millions)~~ the ~~pretax~~pre-tax gains (losses) recognized in AOCL and earnings ~~related to all~~on the Company’s derivative instruments for the periods ~~indicated:~~indicated (in millions):


														Three Months Ended September 30,				Nine Months Ended September 30,
	Three Months Ended September 30,						Nine Months Ended September 30,							2023		2022		2023		2022
	2017			2016			2017			2016
Effective portion of cash flow hedges
Cash flow hedges													Cash flow hedges
Gains (losses) recognized in AOCL													Gains (losses) recognized in AOCL
Interest rate derivatives	$	(6	)	$	7		$	(79	)	$	(213	)	Interest rate derivatives	$	358	$	238	$	380	$	865
Cross-currency derivatives	12			15			14			12

Foreign currency derivatives	(4		)	(6		)	(15		)	(11		)	Foreign currency derivatives	(18)		8		(6)		(4)
Commodity derivatives	9			10			23			35			Commodity derivatives	7		5		(20)		66
Total	$	11		$	26		$	(57	)	$	(177	)	Total	$	347	$	251	$	354	$	927
Gains (losses) reclassified from AOCL into earnings													Gains (losses) reclassified from AOCL into earnings
Interest rate derivatives	$	(19	)	$	(26	)	$	(63	)	$	(81	)	Interest rate derivatives	$	(2)	$	(11)	$	47	$	(61)
Cross-currency derivatives	14			4			18			14

Foreign currency derivatives	(1		)	(7		)	(24		)	(3		)	Foreign currency derivatives	(1)		2		(4)		2
Commodity derivatives	10			4			13			42			Commodity derivatives	4		(4)		17		(5)
Total	$	4		$	(25	)	$	(56	)	$	(28	)	Total	$	1	$	(13)	$	60	$	(64)
Gains (losses) recognized in earnings related to
Ineffective portion of cash flow hedges	$	4		$	(2	)	$	4		$	—
Gains (losses) on fair value hedging relationship													Gains (losses) on fair value hedging relationship

Cross-currency derivatives													Cross-currency derivatives	$	29	$	6	$	(57)	$	(29)
Hedged items													Hedged items	1		—		54		22
Total													Total	$	30	$	6	$	(3)	$	(7)

Gains reclassified from AOCL to earnings due to change in forecast													Gains reclassified from AOCL to earnings due to change in forecast	$	—	$	2	$	14	$	17
Gains recognized in earnings related to													Gains recognized in earnings related to

Not designated as hedging instruments:													Not designated as hedging instruments:
Interest rate derivatives													Interest rate derivatives	$	—	$	1	$	—	$	4
Foreign currency derivatives	$	5		$	(6	)	$	(13	)	$	10		Foreign currency derivatives	3		35		3		20
Commodity derivatives and other	1			7			7			(11		)	Commodity derivatives and other	74		3		265		20
Total	$	6		$	1		$	(6	)	$	(1	)	Total	$	77	$	39	$	268	$	44
Pretax losses reclassified to earnings as a result of discontinuance of cash flow hedge because it was probable that the forecasted transaction would not occur	$	—		$	—		$	(16	)	$	—

AOCL isreclassifications are expected to ~~decrease pretax~~increase pre-tax income from continuing operations for the twelve months ended September 30, ~~2018,~~2024 by ~~$67~~$198 million, primarily due to interest rate derivatives.

5. FINANCING RECEIVABLES

~~Financing receivables are defined as receivables~~Receivables with contractual maturities of greater than one ~~year. The Company’s~~year are considered financing ~~receivables are primarily related to amended agreements or government resolutions that are due from CAMMESA, the administrator of the wholesale electricity market in Argentina.~~receivables. The following table presents financing receivables by country as of the dates indicated (in millions):


	September 30, 2023						December 31, 2022
	Gross Receivable		Allowance		Net Receivable		Gross Receivable		Allowance		Net Receivable
U.S.	$	77	$	—	$	77	$	46	$	—	$	46
Chile	29		—		29		239		—		239



Other	12		—		12		18		—		18
Total	$	118	$	—	$	118	$	303	$	—	$	303

September 30, 2017 December 31, 2016
Argentina $ 216
$ 236
Brazil 9
8
United States 6
20
Other 7
—
Total $ 238
$ 264

~~Argentina~~U.S. — ~~Collection~~During this period, AES has recorded non-current receivables pertaining to the sale of the ~~principal~~Redondo Beach land and ~~interest~~the Warrior Run PPA termination agreement. The anticipated collection period extends beyond September 30, 2024. See Note 13—Revenue for further details regarding the Warrior Run PPA termination agreement.

Chile— AES Andes has recorded receivables pertaining to revenues recognized on regulated energy contracts that were impacted by the Stabilization Funds created by the Chilean government in October 2019 and August 2022, in conjunction with the Tariff Stabilization Laws. Historically, the government updated the prices for these contracts every six months to reflect the contracts' indexation to exchange rates and commodities prices. The Tariff Stabilization Laws do not allow the pass-through of these contractual indexation updates to customers beyond the pricing in effect at July 1, 2019, until new lower-cost renewable contracts are incorporated to supply regulated contracts. Consequently, costs incurred in excess of the July 1, 2019 price are accumulated and borne by generators. Through different programs, AES Andes aims to reduce its exposure and has already sold a significant portion of the receivables ~~is subject~~accumulated as of September 30, 2023.

On August 14, 2023, AES Andes executed an agreement aiming for the sale of up to ~~various business risks and uncertainties, including, but not limited~~$227 million of receivables pursuant to the ~~operation~~Stabilization Funds, of ~~power plants~~ which ~~generate cash for payments~~$122 million was sold and collected as of ~~these~~September 30, 2023. Through different agreements and programs, as of September 30, 2023, $16 million of current receivables ~~regulatory changes that could impact the timing~~ and ~~amount~~$7 million of ~~collections,~~noncurrent receivables were recorded in Accounts receivable and ~~economic conditions in Argentina. The Company monitors these risks, including the credit ratings~~Other noncurrent assets,

19 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

respectively. Additionally, $22 million of ~~the Argentine government, on a quarterly basis~~payment deferrals granted to ~~assess the collectability~~mining customers as part of these receivables. The Company accrues interest on these receivables once the recognition criteria have been met. The Company’s collection estimates are based on assumptions that it believes to be reasonable but are inherently uncertain. Actual future cash flows could differ from these estimates. The decrease in Argentinaour green blend agreements were recorded as financing receivables ~~was primarily due to planned collections, as well as the recognition of a $15 million allowance on a non-trade receivable.~~included in Other noncurrent assets at September 30, 2023.

6. INVESTMENTS IN AND ADVANCES TO AFFILIATES

Summarized Financial Information — The following table summarizes financial information of the Company’s 50%-or-less-owned affiliates and majority-owned unconsolidated subsidiaries that are accounted for using the equity method (in millions):


	50%-or-less Owned Affiliates				Majority-Owned Unconsolidated Subsidiaries
Nine Months Ended September 30,	2023		2022		2023		2022
Revenue	$	2,089	$	1,218	$	1	$	1
Operating loss	(21)		(322)		(1)		—
Net loss	(129)		(410)		(1)		—
Net loss attributable to affiliates	(111)		(332)		(1)		—

Nine Months Ended September 30,
50%-or-less-Owned Affiliates 2017 2016
Revenue $ 532
$ 439
Operating margin 91
108
Net income 44
46

~~sPower~~ Grupo Energía Gas Panamá— In ~~February 2017,~~September 2023, AES Latin America completed the ~~Company and Alberta Investment Management Corporation (“AIMCo”) entered into an agreement to acquire FTP Power LLC (“sPower”). On July 25, 2017, AES closed on the acquisition~~

sale of its ~~48% ownership~~ interest in ~~sPower~~Grupo Energía Gas Panamá, a joint venture formed for ~~$461 million.~~the Gatun combined cycle natural gas development project, to AES Panama, a 49%-owned consolidated subsidiary. As a result of the transaction, the Company’s effective ownership in Grupo Energía Gas Panamá decreased from 49% to approximately 24%. As the Company still does not control ~~sPower,~~the investment after this transaction, it ~~was~~continues to be accounted for as an equity method ~~investment. The sPower portfolio includes solar~~investment and ~~wind projects in operation, under construction, and in development located in the United States. The sPower equity method investment~~ is reported in the USEnergy Infrastructure SBU reportable segment.

~~7. DEBT~~

~~Recourse Debt~~

sPower— In ~~August 2017,~~December 2022, the Company ~~issued $500 million aggregate principal amount of 5.125% senior notes due in 2027. The Company used these proceeds~~agreed to ~~redeem at par $240 million aggregate principal~~sell 49% of its ~~existing LIBOR + 3.00% senior unsecured notes due~~indirect interest in ~~2019 and repurchased $217 million~~a portfolio of ~~its existing 8.00% senior unsecured notes due in 2020.~~sPower's operating assets ("OpCo B"). On February 28, 2023, sPower closed on the sale for $196 million. As a result of the ~~latter transactions,~~transaction, the Company ~~recognized~~received $98 million in sales proceeds and recorded a ~~loss~~pre-tax gain on ~~extinguishment~~sale of ~~debt~~$5 million, recorded in Gain (loss) on disposal and sale of ~~$36~~business interests. After the sale, the Company's ownership interest in OpCo B decreased from 50% to approximately 26%. As the Company still does not control but has significant influence over sPower after the transaction, it continues to be accounted for as an equity method investment and is reported in the Renewables SBU reportable segment.

Alto Maipo — In May 2022, Alto Maipo emerged from bankruptcy in accordance with Chapter 11 of the U.S. Bankruptcy Code. Alto Maipo, as restructured, is considered a VIE. As the Company lacks the power to make significant decisions, it does not meet the criteria to be considered the primary beneficiary of Alto Maipo and therefore does not consolidate the entity. The Company has elected the fair value option to account for its investment in Alto Maipo as management believes this approach will better reflect the economics of its equity interest. As of September 30, 2023, the fair value is insignificant. Alto Maipo is reported in the Energy Infrastructure SBU reportable segment.

20 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

7. DEBT

Recourse Debt

Senior Notes due 2028 — In May 2023, the Company issued $900 million aggregate principal of 5.45% senior notes due in 2028. The Company used the proceeds from this issuance for general corporate purposes and to fund investments in the Company’s Renewables and Utilities SBUs.

AES Clean Energy Development — In March 2023, AES Clean Energy Development Holdings, LLC executed a $500 million bridge loan due in December 2023 and used the proceeds for general corporate purposes. The obligations under the bridge loan are unsecured and are fully guaranteed by the Parent Company.

Commercial Paper Program— In March 2023, the Company established a commercial paper program under which the Company may issue unsecured commercial paper notes (the “Notes”) up to a maximum aggregate face amount of $750 million outstanding at any time. The maturities of the Notes may vary but will not exceed 397 days from the date of issuance. The proceeds of the Notes will be used for general corporate purposes. The Notes will be sold on customary terms in the U.S. commercial paper market on a private placement basis. The commercial paper program is backed by the Company's $1.5 billion revolving credit facility, and the Company cannot issue commercial paper in an aggregate amount exceeding the then available capacity under its revolving credit facilities. As of September 30, 2023, the Company had $604 million outstanding borrowings under the commercial paper program with a weighted average interest rate of 6.16%. The Notes are classified as noncurrent.

Revolving Credit Facility— In September 2022, AES executed an amendment to its revolving credit facility. The aggregate commitment under the new agreement is $1.5 billion and matures in August 2027. The existing credit agreement had an aggregate commitment of $1.25 billion and matured in September 2026. As of September 30, 2023, AES had no outstanding drawings under its revolving credit facility.

Term Loan due 2024— In September 2022, the AES Corporation entered into a term loan agreement, under which AES can obtain term loans in an aggregate principal amount of up to $200 million, with all term loans to mature no later than September 30, 2024. On September 30, 2022 the AES Corporation borrowed $200 million under this agreement with a maturity date of September 30, 2024.

Non-Recourse Debt

During the nine months ended September 30, ~~2017.~~2023, the Company’s following subsidiaries had significant debt issuances (in millions):


Subsidiary	Issuances (1)


AES Clean Energy	$	885
Netherlands and Colon	350

_____________________________

(1) These amounts do not include revolving credit facility activity at the Company’s subsidiaries.

21 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

Netherlands and Colon — In ~~May 2017, the Company closed on $525~~March 2022, AES Hispanola Holdings BV, a Netherlands based company, and Colon, as co-borrowers, executed a $500 million ~~aggregate principal LIBOR + 2.00% secured term~~bridge loan due in ~~2022. In June 2017, the~~2023. The Company ~~used these proceeds to redeem at par all $517~~allocated $450 million ~~aggregate principal of its existing Term Convertible Securities. As a result~~and $50 million of the ~~latter transaction,~~proceeds from the ~~Company recognized a loss on extinguishment of debt of $6 million for the nine months ended September 30, 2017.~~agreement to AES Hispanola Holdings BV and Colon, respectively.

In ~~March 2017, the Company redeemed via tender offers $276~~January 2023, AES Hispanola Holdings BV and Colon, as co-borrowers, executed a $350 million ~~aggregate principal of its existing 7.375% senior unsecured notes~~credit agreement at 8.85%, due in ~~2021~~2028. The Company allocated $300 million and ~~$24~~$50 million of ~~its existing 8.00% senior unsecured notes due~~the proceeds from the agreement to AES Hispanola Holdings BV and Colon, respectively. The net proceeds from the agreement were used to partially repay the $500 million bridge loan executed in ~~2020.~~2022. The remaining principal outstanding of the bridge loan was repaid with proceeds from operating cash flows as well as cash from the Parent Company. As a result of these transactions, the Company recognized a loss on extinguishment of debt of ~~$47~~$1 million for the nine months ended September 30, ~~2017.~~2023.

~~In July 2016,~~United Kingdom — On January 6, 2022, Mercury Chile HoldCo LLC (“Mercury Chile”), a UK based company, executed a $350 million bridge loan, and used the proceeds, as well as an additional capital contribution of $196 million from the Parent Company, ~~redeemed~~to purchase the minority interest in ~~full the $181~~AES Andes through intermediate holding companies (see Note 11—Equity for further information). On January 24, 2022, Mercury Chile issued $360 million ~~balance~~aggregate principal of ~~its 8.00% outstanding~~6.5% senior ~~unsecured~~secured notes due ~~2017 using~~in 2027 and used the proceeds from ~~its senior secured credit facility. As~~the issuance to fully prepay the $350 million bridge loan.

AES Clean Energy — In December 2022, AES Clean Energy Development, AES Renewable Holdings, and sPower, an equity method investment, collectively referred to as the Issuers, entered into a ~~result,~~Master Indenture agreement whereby long-term notes will be issued from time to time to finance or refinance operating wind, solar, and energy storage projects that are owned by the ~~Company recognized a loss on extinguishment of debt of $16 million~~Issuers. On December 13, 2022, the Issuers entered into the Note Purchase Agreement for the ~~three and nine months ended September 30, 2016.~~

issuance of up to $647 million of 6.55% Senior Notes due in 2047. The notes were sold on December 14, 2022, at par for $647 million. In ~~May 2016,~~2023, the ~~Company issued $500~~Issuers sold an additional $246 million in 6.37% notes, resulting in aggregate principal amount of ~~6.00% senior~~ notes ~~due in 2026. The Company used these proceeds to redeem at par $495 million aggregate principal~~issued of ~~its existing LIBOR + 3.00% senior unsecured notes due 2019.~~$893 million. Each of the Issuers is considered a “Co-Issuer” and will be jointly and severally liable with each other Co-Issuer for all obligations under the facility. As a result of the ~~latter transaction,~~2023 issuance, AES Clean Energy Development recorded an increase in liabilities of $215 million, resulting in an aggregate carrying amount of the ~~Company recognized a loss on extinguishment~~notes attributable to AES Clean Energy Development and AES Renewable Holdings of ~~debt~~$252 million as of ~~$4 million for the nine months ended~~ September 30, ~~2016.~~2023.

In ~~January 2016,~~2021, AES Clean Energy Development, AES Renewable Holdings, and sPower, collectively referred to as the ~~Company redeemed $125 million~~Borrowers, executed two Credit Agreements with aggregate commitments of ~~its senior unsecured notes outstanding.~~$1.2 billion and maturity dates in December 2024 and September 2025. The ~~repayment included~~Borrowers executed amendments to the revolving credit facilities, which resulted in an aggregate increase in the commitments of $2.3 billion, bringing the total commitments under the new agreements to $3.5 billion. Under a ~~portion~~2023 amendment, the maturity date of one of the ~~7.375% senior notes due in 2021~~,Credit Agreements was extended from December 2024 to May 2026. Each of the ~~4.875% senior notes due in 2023,~~Borrowers is considered a “Co-Borrower” and will be jointly and severally liable with each other Co-Borrower for all obligations under the ~~5.5% senior notes due in 2024, the 5.5% senior notes due in 2025 and the floating rate senior notes due in 2019.~~facilities. As a result of ~~these transactions,~~increases in commitments used, AES Clean Energy Development and AES Renewable Holdings recorded, in aggregate, an increase in liabilities of $1.4 billion in 2023, resulting in total commitments used under the ~~Company recognized a net gain on extinguishment~~revolving credit facilities, as of ~~debt of $7 million for the nine months ended~~ September 30, ~~2016.~~

~~Non-Recourse Debt~~

~~During the nine months ended September 30, 2017, the Company’s subsidiaries had the following significant debt transactions:~~

Subsidiary Issuances Repayments Gain (Loss) on Extinguishment of Debt
Tietê $ 585
$ (293 ) $ (5 )
IPALCO 532

(480 ) (9 )
Southland 360
—
—
AES Argentina 307
(181 ) 65
Los Mina 278
(259 ) (4 )
Gener 243

(78 ) —
Colon 220
—
—
Eletropaulo 189

(147 ) —
Other 261
(509 ) (3 )
Total $ 2,975
$ (1,947 ) $ 44

~~Southland~~ ~~— In June 2017, AES Southland Energy LLC closed on $2 billion~~2023, of aggregate principal long-term non-recourse debt financing to fund the Southland re-powering construction projects (“the Southland financing”). The Southland financing consists of $1.5 billion senior secured notes, amortizing through 2040, and $492 million senior secured term loan, amortizing through 2027. The long term debt financing has a combined weighted average cost of approximately 4.5%.$2.7 billion. As of September 30, ~~2017, $360 million~~2023, the aggregate commitments used under the revolving credit facilities for the Co-Borrowers was $3.4 billion.

Non-Recourse Debt Covenants, Restrictions, and Defaults — The terms of the ~~senior secured notes were outstanding under the Southland financing.~~

~~AES Argentina~~ — In February 2017, AES Argentina issued $300 million aggregate principal of unsecured and unsubordinated notes due in 2024. The net proceeds from this issuance were used for the prepayment of $75 million ofCompany's non-recourse debt ~~related~~include certain financial and nonfinancial 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 and financial ratios, minimum levels of working capital, and limitations on incurring additional indebtedness.

As of September 30, 2023 and December 31, 2022, approximately $369 million and $424 million, respectively, of restricted cash was maintained in accordance with certain covenants of the non-recourse debt agreements. These amounts were included within Restricted cash and Debt service reserves and other deposits in the accompanying Condensed Consolidated Balance Sheets. As of September 30, 2023 and December 31, 2022, approximately $91 million and $56 million, respectively, of the restricted cash balances were for collateral held to cover potential liability for current and future insurance claims being assumed by AGIC, AES' captive insurance company.

Various lender and governmental provisions restrict the ability of certain of the Company's subsidiaries to transfer their net assets to the ~~construction~~Parent Company. Such restricted net assets of subsidiaries amounted to approximately $1.4 billion at September 30, 2023.

The following table summarizes the ~~San Nicolas Plant resulting~~Company’s subsidiary non-recourse debt in ~~a gain on extinguishment~~default (in millions) as of ~~debt of approximately $65 million.~~

~~Non-Recourse Debt~~September 30, 2023. Due to the defaults, these amounts are included in ~~Default~~ ~~— The~~the current portion of non-recourse debt ~~includes~~unless otherwise indicated:

22 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022


Subsidiary	Primary Nature of Default	Debt in Default		Net Assets (Liabilities)
AES Mexico Generation Holdings (TEG and TEP) (1)	Covenant	$	157	$	50
AES Puerto Rico	Covenant/Payment	143		(169)
AES Ilumina (Puerto Rico)	Covenant	25		28
AES Jordan Solar	Covenant	7		11
Total		$	332

_____________________________

(1)On October 3, 2023, AES Mexico Generation Holdings failed to comply with a covenant on its debt, resulting in a technical default. The associated non-recourse debt is classified as current in the ~~following subsidiary debt~~accompanying Condensed Consolidated Balance Sheets.

The amounts in default asrelated to AES Puerto Rico are covenant and payment defaults. In July 2023, AES Puerto Rico signed forbearance and standstill agreements with its noteholders because of ~~September 30, 2017 (in millions).~~

the insufficiency of funds to meet the principal and interest obligations on its Series A Bond Loans due and payable on June 1, 2023, and going forward. AES Puerto Rico continues to work with PREPA and its noteholders on these liquidity challenges. These agreements will expire on December 31, 2023.

Subsidiary Primary Nature of Default Debt in Default Net Assets
Alto Maipo (Chile) Covenant $ 623
$ 352
AES Puerto Rico Covenant 365
566
AES Ilumina Covenant 36
56
$ 1,024

~~The above~~All other defaults listed are not payment defaults. All ~~of the~~other subsidiary non-recourse ~~debt~~ defaults were triggered by failure to comply with covenants and/or other conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the applicable subsidiary.

The AES Corporation’s recourse debt agreements include cross-default clauses that will trigger if a subsidiary or group of subsidiaries for which the non-recourse debt is in default provides ~~more than~~ 20% or more of the Parent Company’s total cash distributions from businesses for the four most recently completed fiscal quarters. As of September 30, ~~2017,~~2023, the Company ~~has~~had no defaults which ~~result~~resulted in, or ~~are~~were at risk of triggering, a cross-default under the recourse debt of the Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its ~~senior secured~~ revolving credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the then-prevailing rate. Payment defaults and bankruptcy defaults would preclude the making of any restricted payments.

8. COMMITMENTS AND CONTINGENCIES

Guarantees, Letters of Credit and Commitments— In connection with certain project financings, acquisitions and dispositions, power purchases and other agreements, the Parent 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. In the normal course of business, the Parent Company 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 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 no more than 1733 years.

The following table summarizes the Parent Company’s contingent contractual obligations as of September 30, ~~2017.~~2023. Amounts presented in the following table represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential ~~exposure.~~exposure and excludes guarantees presented on the Condensed Consolidated Balance Sheets within Recourse debt. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees.


Contingent Contractual Obligations	Amount (in millions)		Number of Agreements	Maximum Exposure Range for Each Agreement (in millions)
Guarantees and commitments	$	2,431	81	<$1 — 484
Letters of credit under bilateral agreements	248		3	$59 — 125
Letters of credit under the unsecured credit facilities	136		30	<$1 — 50
Letters of credit under the revolving credit facility	39		6	<$1 — 30
Surety bonds	2		2	<$1 — 1

Total	$	2,856	122

Contingent Contractual Obligations
Amount
(in millions)
Number of Agreements Maximum Exposure Range for Each Agreement (in millions)
Guarantees and commitments $ 806
21
<$1 — 272
Letters of credit under the unsecured credit facility 125
5
$2 — 73
Asset sale related indemnities ⁽¹⁾
27
1
$27
Letters of credit under the senior secured credit facility 9
17
<$1 — 2
Total $ 967
44

~~_____________________________~~


⁽¹⁾	Excludes normal and customary representations and warranties in agreements for the sale of assets (including ownership in associated legal entities) where the associated risk is considered to be nominal.

During the nine months ended September 30, ~~2017,~~2023, the Company paid letter of credit fees ranging from ~~0.25%~~1% to ~~2.25%~~3% per annum on the outstanding amounts of letters of credit.

23 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

Contingencies

Environmental — The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. ~~As of~~For the periods ended September 30, ~~2017~~2023 and December 31, ~~2016,~~2022, the Company ~~had~~ recognized liabilities of $9$10 million ~~and $12 million, respectively,~~ for projected environmental

remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Moreover, where no liability has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of September 30, ~~2017.~~2023. In aggregate, the Company estimates the range of potential losses related to environmental matters, where estimable, to be up to ~~$19~~$12 million. The amounts considered reasonably possible do not include amounts accrued as discussed above.

Litigation —The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has recognized aggregate liabilities for all claims of approximately ~~$174 million and $179~~$22 million as of September 30, ~~2017~~2023 and December 31, ~~2016, respectively.~~2022. These amounts are reported on the Condensed Consolidated Balance Sheets within Accrued and other liabilities and Other noncurrent liabilities. A significant portion of these accrued liabilities relate to ~~labor~~regulatory matters and ~~employment, non-income tax and customer~~commercial disputes in international jurisdictions. 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 these accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

Where no accrued liability 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 but could not be estimated as of September 30, ~~2017.~~2023. The material contingencies where a loss is reasonably possible primarily include ~~claims under financing agreements, including the Eletrobrás case;~~ disputes with offtakers, suppliers and EPC contractors; alleged breaches of contract; alleged violation of ~~monopoly~~ laws and regulations; income tax and non-income tax matters with tax authorities; and regulatory matters. In October 2017, Eletropaulo and Eletrobrás entered into a memorandum of understanding to engage in settlement discussions. If settlement is achieved, it will be subject to the approval of the Eletropaulo Board of Directors and the majority of non-AES board members of Eletropaulo. As such, no contingency has been recorded as it does not meet the criteria under ASC 450. In aggregate, the Company estimates the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between ~~$1.6 billion~~$182 million and ~~$1.9 billion.~~$219 million. The amounts considered reasonably possible do not include the amounts accrued, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.

9. ~~PENSION PLANS~~LEASES

~~Total pension cost~~LESSOR — The Company has operating leases for certain generation contracts that contain provisions to provide capacity to a customer, which is a stand-ready obligation to deliver energy when required by the customer. Capacity receipts are generally considered lease elements as they cover the majority of available output from a facility. The allocation of contract payments between the lease and ~~employer contributions were~~non-lease elements is made at the inception of the lease. Lease receipts from such contracts are recognized as ~~follows~~lease revenue on a straight-line basis over the lease term, whereas variable lease receipts are recognized when earned.

The following table presents lease revenue from operating leases in which the Company is the lessor, recognized in Revenue on the Condensed Consolidated Statements of Operations for the periods indicated (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Lease Revenue	2023		2022		2023		2022
Total lease revenue	$	133	$	134	$	390	$	408
Less: Variable lease revenue	(22)		(14)		(54)		(37)
Total Non-variable lease revenue	$	111	$	120	$	336	$	371

24 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
U.S. Foreign U.S. Foreign U.S. Foreign U.S. Foreign
Service cost $ 3
$ 4
$ 3
$ 3
$ 10
$ 11
$ 9
$ 9
Interest cost 10
99
10
92
31
296
30
255
Expected return on plan assets (17 ) (73 ) (17 ) (59 ) (52 ) (219 ) (50 ) (164 )
Amortization of prior service cost 1
—
2
—
4
—
6
—
Amortization of net loss 5
10
5
5
14
31
14
14
Curtailment loss recognized —
—
—
—
4
—
—
—
Total pension cost $ 2
$ 40
$ 3
$ 41
$ 11
$ 119
$ 9
$ 114

Nine Months Ended
September 30, 2017 Remainder of 2017 (Expected)
U.S. Foreign U.S. Foreign
Total employer contributions $ 14
$ 118
$ —
$ 41

The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment on the Condensed Consolidated Balance Sheets as of the periods indicated (in millions):


Property, Plant and Equipment, Net	September 30, 2023		December 31, 2022
Gross assets	$	1,223	$	1,319
Less: Accumulated depreciation	(180)		(139)
Net assets	$	1,043	$	1,180

The option to extend or terminate a lease is based on customary early termination provisions in the contract, such as payment defaults, bankruptcy, and lack of performance on energy delivery. The Company has not recognized any early terminations as of September 30, 2023. Certain leases may provide for variable lease payments based on usage or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments.

The following table shows the future lease receipts as of September 30, 2023 for the remainder of 2023 through 2027 and thereafter (in millions):


	Future Cash Receipts for
	Sales-Type Leases		Operating Leases
2023	$	7	$	96
2024	26		385
2025	26		386
2026	26		278
2027	26		183
Thereafter	375		544
Total	$	486	$	1,872
Less: Imputed interest	(257)
Present value of total lease receipts	$	229

Battery Storage Lease Arrangements — The Company constructs and operates projects consisting only of a stand-alone battery energy storage system (“BESS”) facility, as well as projects that pair a BESS with solar energy systems. These projects allow more flexibility on when to provide energy to the grid. The Company will enter into PPAs for the full output of the facility that allow customers the ability to determine when to charge and discharge the BESS. These arrangements include both lease and non-lease elements under ASC 842, with the BESS component typically constituting a sales-type lease. The Company recognized lease income on sales-type leases through interest income of $3 million and $10 million for the three and nine months ended September 30, 2023, respectively; and $4 million and $20 million for the three and nine months ended September 30, 2022, respectively.

10. REDEEMABLE STOCK OF SUBSIDIARIES

The following table summarizes the Company’s redeemable stock of subsidiaries balances as of the periods indicated (in millions):

September 30, 2017 December 31, 2016
IPALCO common stock $ 618
$ 618
Eletropaulo preferred stock 152
—
Colon quotas ⁽¹⁾
137
100
IPL preferred stock 60
60
Other common stock —
4
Redeemable stock of subsidiaries $ 967
$ 782


	September 30, 2023		December 31, 2022
IPALCO common stock	$	778	$	782
AES Clean Energy Development common stock	557		436
AES Clean Energy tax equity partnerships	70		86

Potengi common and preferred stock	18		17

Total redeemable stock of subsidiaries	$	1,423	$	1,321

~~_____________________________~~


⁽¹⁾	~~Characteristics of quotas are similar to common stock.~~

~~Eletropaulo~~Potengi — In ~~September 2017, Eletropaulo obtained shareholder approval for~~March 2022, Tucano Holding I (“Tucano”), a subsidiary of AES Brasil, issued new shares in the ~~transfer of Eletropaulo’s~~Potengi wind development project. BRF S.A. (“BRF”) acquired shares ~~to Novo Mercado, which is a listing segment~~representing 24% of the ~~Brazilian stock exchange with~~equity in the ~~highest standards of corporate governance. Certain preferred shareholders who did not vote~~project for $12 million, reducing the Company’s indirect ownership interest in ~~favor~~Potengi to 35.5%. As the Company maintained control after the transaction, Potengi continues to be consolidated by the Company. As part of the ~~share transfer~~transaction, BRF was given an option to sell its entire ownership interest at the conclusion of the PPA term. As a result, the minority ownership interest is considered temporary equity, which will be adjusted for earnings or losses allocated to the Novo Mercado have withdrawal rights which allow the shareholder to receive a cash payment for tendering their shares to Eletropaulo over a 30-day withdrawal rights window that expired on October 30, 2017. Due to these withdrawal rights, these shares were probable of becoming redeemable as of September 30, 2017 and the corresponding non-controllingnoncontrolling interest ~~was reclassified to temporary equity.~~

~~Colon~~ ~~— Our partner in Colon made capital contributions of $30 million and $106 million during the nine months ended September 30, 2017 and 2016, respectively.~~under ASC 810. Any subsequent ~~adjustments to allocate earnings and dividends to our partner, or measure~~changes in the ~~investment at fair~~redemption value of the exit rights will be ~~classified as temporary equity each reporting period~~recognized in accordance with ASC 480-10-S99, as it is probable that the shares will become redeemable. Potengi is reported in the Renewables SBU reportable segment.

~~IPALCO~~ —

25 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

11. EQUITY

Equity Units

In March ~~2016, CDPQ exercised~~2021, the Company issued 10,430,500 Equity Units with a total notional value of $1,043 million. Each Equity Unit has a stated amount of $100 and was initially issued as a Corporate Unit, consisting of a forward stock purchase contract (“2024 Purchase Contracts”) and a 10% undivided beneficial ownership interest in one share of 0% Series A Cumulative Perpetual Convertible Preferred Stock, issued without par and with a liquidation preference of $1,000 per share (“Series A Preferred Stock”).

The Company concluded that the Equity Units should be accounted for as one unit of account based on the economic linkage between the 2024 Purchase Contracts and the Series A Preferred Stock, as well as the Company's assessment of the applicable accounting guidance relating to combining freestanding instruments. The Equity Units represent mandatorily convertible preferred stock. Accordingly, the shares associated with the combined instrument are reflected in diluted earnings per share using the if-converted method.

In conjunction with the issuance of the Equity Units, the Company received approximately $1 billion in proceeds, net of underwriting costs and commissions, before offering expenses. The proceeds for the issuance of 1,043,050 shares are attributed to the Series A Preferred Stock for $838 million and $205 million for the present value of the quarterly payments due to holders of the 2024 Purchase Contracts ("Contract Adjustment Payments"). The proceeds were used for the development of the AES renewable businesses, U.S. utility businesses, LNG infrastructure, and for other developments determined by management.

The Series A Preferred Stock will initially not bear any dividends and the liquidation preference of the convertible preferred stock will not accrete. The Series A Preferred Stock has no maturity date and will remain outstanding unless converted by holders or redeemed by the Company. Holders of the shares of the convertible preferred stock will have limited voting rights.

The Series A Preferred Stock is pledged as collateral to support holders’ purchase obligations under the 2024 Purchase Contracts and can be remarketed. In connection with any successful remarketing, the Company may increase the dividend rate, increase the conversion rate, and modify the earliest redemption date for the convertible preferred stock. After any successful remarketing in connection with which the dividend rate on the convertible preferred stock is increased, the Company will pay cumulative dividends on the convertible preferred stock, if declared by the board of directors, quarterly in arrears from the applicable remarketing settlement date.

Holders of Corporate Units may create Treasury Units or Cash Settled Units from their Corporate Units as provided in the Purchase Contract Agreement by substituting Treasury securities or cash, respectively, for the Convertible Preferred Stock comprising a part of the Corporate Units.

The Company may not redeem the Series A Preferred Stock prior to March 22, 2024. At the election of the Company, on or after March 22, 2024, the Company may redeem for cash, all or any portion of the outstanding shares of the Series A Preferred Stock at a redemption price equal to 100% of the liquidation preference, plus any accumulated and unpaid dividends.

The 2024 Purchase Contracts obligate the holders to purchase, on February 15, 2024, for a price of $100 in cash, a maximum number of 57,407,386 shares of the Company’s common stock (subject to customary anti-dilution adjustments). The 2024 Purchase Contract holders may elect to settle their obligation early, in cash. The Series A Preferred Stock is pledged as collateral to guarantee the holders’ obligations to purchase common stock under the terms of the 2024 Purchase Contracts. The initial settlement rate determining the number of shares that each holder must purchase will not exceed the maximum settlement rate and is determined over a market value averaging period preceding February 15, 2024.

The initial maximum settlement rate of 3.864 was calculated using an initial reference price of $25.88, equal to the last reported sale price of the Company’s common stock on March 4, 2021. As of September 30, 2023, due to the customary anti-dilution provisions, the maximum settlement rate was 3.8768, equivalent to a reference price of $25.79. If the applicable market value of the Company’s common stock is less than or equal to the reference price, the settlement rate will be the maximum settlement rate; and if the applicable market value of common stock is greater than the reference price, the settlement rate will be a number of shares of the Company’s common stock equal to $100 divided by the applicable market value. Upon successful remarketing of the Series A Preferred Stock (“Remarketed Series A Preferred Stock”), the Company expects to receive additional cash proceeds of $1 billion and issue shares of Remarketed Series A Preferred Stock.

26 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

The Company pays Contract Adjustment Payments to the holders of the 2024 Purchase Contracts at a rate of 6.875% per annum, payable quarterly in arrears on February 15, May 15, August 15, and November 15, commencing on May 15, 2021. The $205 million present value of the Contract Adjustment Payments at inception reduced the Series A Preferred Stock. As each quarterly Contract Adjustment Payment is made, the related liability is reduced and the difference between the cash payment and the present value will accrete to interest expense, approximately $5 million over the three-year term. As of September 30, 2023, the present value of the Contract Adjustment Payments was $36 million.

The holders can settle the purchase contracts early, for cash, subject to certain exceptions and conditions in the prospectus supplement. Upon early settlement of any purchase contracts, the Company will deliver the number of shares of its ~~final purchase option by investing $134~~common stock equal to 85% of the number of shares of common stock that would have otherwise been deliverable.

Equity Transactions with Noncontrolling Interests

AES Clean Energy Tax Equity Partnerships — The majority of solar projects under AES Clean Energy have been financed with tax equity structures, in which tax equity investors receive a portion of the economic attributes of the facilities, including tax attributes, that vary over the life of the projects.

During the nine months ended September 30, 2023 and 2022, AES Clean Energy Development and AES Renewable Holdings, through multiple transactions, sold noncontrolling interests in project companies to tax equity partners, resulting in increases to NCI of $292 million and $210 million, respectively.

In the third quarter of 2023, AES Renewable Holdings completed buyouts of tax equity partners at Buffalo Gap I, Buffalo Gap II and six other project companies, resulting in ~~IPALCO. The company also recognized~~a decrease to NCI of $45 million and an increase to additional paid-in capital of $34 million. AES Clean Energy Development and AES Renewable Holdings are reported in the Renewables SBU reportable segment.

Chile Renovables — Under its renewable partnership agreement with Global Infrastructure Management, LLC (“GIP”), AES Andes will contribute a ~~reduction~~specified pipeline of renewable development projects to ~~retained earnings of $84 million for~~Chile Renovables as the ~~excess~~projects reach commercial operations, and GIP may make additional contributions to maintain its 49% ownership interest. During the nine months ended September 30, 2022 and 2023, AES Andes completed the sale of the ~~fair value of the shares over their book value. In June 2016, CDPQ contributed an additional $24 million~~following projects to ~~IPALCO. Any subsequent adjustments to allocate earnings and dividends to CDPQ will be classified as NCI within permanent equity as it is not probable that the shares will become redeemable.~~

~~11. EQUITY~~

~~Changes in Equity~~ ~~— The following table is a reconciliation of the beginning and ending equity attributable to stockholders of The AES Corporation, NCI and total equity as of the periods indicated~~Chile Renovables (in millions):


Business	Transaction Period	Sale Price		Increase to Noncontrolling Interests		Increase (Decrease) to Additional Paid-In Capital
Andes Solar 2a	January 2022	$	37	$	28	$	9
Los Olmos	June 2022	80		68		12
Campo Lindo	September 2023	50		59		(9)

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
The Parent Company Stockholders’ Equity NCI Total Equity The Parent Company Stockholders’ Equity NCI Total Equity
Balance at the beginning of the period $ 2,794
$ 2,906
$ 5,700
$ 3,149
$ 3,022
$ 6,171
Net income (loss) ⁽¹⁾
181
328
509
(181 ) 97
(84 )
Total foreign currency translation adjustment, net of income tax 117
10
127
179
53
232
Total change in derivative fair value, net of income tax 5
3
8
(52 ) (63 ) (115 )
Total pension adjustments, net of income tax 1
19
20
3
7
10
Cumulative effect of a change in accounting principle ⁽²⁾
31
—
31
—
—
—
Fair value adjustment ⁽³⁾
(19 ) —
(19 ) (4 ) —
(4 )
Disposition of businesses —
—
—
—
18
18
Distributions to noncontrolling interests —
(261 ) (261 ) (2 ) (293 ) (295 )
Contributions from noncontrolling interests —
17
17
—
23
23
Dividends declared on common stock (158 ) —
(158 ) (144 ) —
(144 )
Purchase of treasury stock —
—
—
(79 ) —
(79 )
Issuance and exercise of stock-based compensation benefit plans 12
—
12
15
—
15
Sale of subsidiary shares to noncontrolling interests 22
47
69
—
17
17
Acquisition of subsidiary shares from noncontrolling interests 200
(85 ) 115
(2 ) (3 ) (5 )
Less: Net loss attributable to redeemable stock of subsidiaries —
9
9
—
8
8
Balance at the end of the period $ 3,186
$ 2,993
$ 6,179
$ 2,882
$ 2,886
$ 5,768

~~_____________________________~~


⁽¹⁾	Net income attributable to noncontrolling interest of $337 million and net loss attributable to redeemable stocks of subsidiaries of $9 million for the nine months ended September 30, 2017. Net income attributable to noncontrolling interest of $105 million and net loss attributable to redeemable stock of subsidiaries of $8 million for the nine months ended September 30, 2016.


⁽²⁾	~~See Note~~ 1~~—Financial Statement Presentation, New Accounting Standards Adopted~~ ~~for further information.~~


⁽³⁾	~~Adjustment to record the of redeemable stock of Colon at fair value.~~

~~Equity Transactions with Noncontrolling Interests~~

~~Dominican Republic~~ — On September 28, 2017, Linda Group, an investor-based group in the Dominican Republic acquired an additional 5% of our Dominican Republic business for $60 million, pre tax. This transaction resulted in a net increase of $25 million to the Company’s additional paid-in capital and noncontrolling interest, respectively. No gain or loss was recognized in net income as the sale was not considered a sale of in-substance real estate. As the Company maintained control after ~~the sale, our businesses in the Dominican Republic continue~~these transactions, Chile Renovables continues to be consolidated by the Company within the ~~MCAC~~Energy Infrastructure SBU reportable segment.

~~Alto Maipo~~ AES Panama— ~~On March 17, 2017,~~In September 2023, AES ~~Gener~~Latin America completed the ~~legal and financial restructuring~~sale of ~~Alto Maipo. As part of this restructuring, AES indirectly acquired the 40% ownership interest of the noncontrolling shareholder, for a de minimis payment, and sold a 6.7%~~its interest in the ~~project~~Grupo Energía Gas Panamá joint venture to AES Panama, a 49%-owned consolidated subsidiary. See Note 6—Investments in and Advances to Affiliates for further information.As a result of the transaction, AES Panama received $42 million from noncontrolling interest holders and the Company reclassified accumulated other comprehensive income from AOCL to NCI of $23 million. AES Panama is reported in the Renewables SBU reportable segment however the investment in Grupo Energía Gas Panamá is reported in the Energy Infrastructure SBU reportable segment.

AES Brasil — In September 2022, AES Brasil commenced a private placement offering for its existing shareholders to subscribe for up to 107 million newly issued shares. AES Holdings Brasil Ltda. subscribed for 54 million shares and noncontrolling interest holders subscribed for 53 million shares, thereby increasing AES’ indirect beneficial interest in AES Brasil to 47.4%. AES Brasil received $77 million from noncontrolling interest holders during the third quarter of 2022, prior to the ~~construction contractor. This~~issuance of the shares in October 2022. Since the consideration received was nonrefundable, the impact was recorded in noncontrolling interests. AES Brasil is reported in the Renewables SBU reportable segment.

Guaimbê Holding — In January 2022, the Ventus wind complex and AGV solar complex were incorporated by Guaimbê Holding. Guaimbê Holding issued preferred shares representing 3.5% ownership in the subsidiary for total proceeds of $63 million. The transaction decreased the Company’s indirect ownership interest to 35.8%. As the Company maintained control after these transactions, Guaimbê Holding continues to be consolidated by the Company within the Renewables SBU reportable segment.

27 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

AES Andes — In January 2022, Inversiones Cachagua SpA (“Cachagua”) completed a tender offer for the shares of AES Andes held by minority shareholders for $522 million, net of transaction costs. Upon completion, AES' indirect beneficial interest in AES Andes increased from 67.1% to 98.1%. Through multiple transactions following the tender offer during the first quarter of 2022, Cachagua acquired an additional 0.8% ownership in AES Andes for $13 million, further increasing AES’ indirect beneficial interest to 98.9%. The tender offer and these follow-on transactions resulted in a ~~$196~~$169 million ~~increase~~decrease to ~~the~~ Parent ~~Company’s Stockholders’~~Company Stockholder’s Equity due to ~~an increase~~a decrease in ~~additional-paid-in~~additional paid-in capital of ~~$229~~$93 million ~~offset by~~and the reclassification of accumulated other comprehensive losses from NCI to AOCL of $76 million. AES Andes is reported in the Parent Company Stockholders’ Equity of $33 million. No gain or loss was recognized in net income as the sale was not considered to be a sale of in-substance real estate. After completion of the sale, the Company has an effective 62% economic interest in Alto Maipo. As the Company maintained control of the partnership after the sale, Alto Maipo continues to be consolidated by the Company within the AndesEnergy Infrastructure SBU reportable segment.

~~Jordan~~ — On February 18, 2016, the Company completed the sale of 40% of its interest in a wholly owned subsidiary in Jordan which owns a controlling interest in the Jordan IPP4 gas-fired plant, for $21 million. The transaction was accounted for as a sale of in-substance real estate and a pretax gain of $4 million, net of transaction costs, was recognized in net income. The cash proceeds from the sale are reflected in ~~Proceeds from the sale of businesses, net of cash sold, and equity investments~~ on the Consolidated Statement of Cash Flows for the period ended September 30, 2016. After completion of the sale, the Company has a 36% economic interest in Jordan IPP4 and will continue to manage and operate the plant, with 40% owned by Mitsui Ltd. and 24% owned by Nebras Power Q.S.C. As the Company maintained control after the sale, Jordan IPP4 continues to be consolidated by the Company within the Eurasia SBU reportable segment.

~~Deconsolidations~~

~~UK Wind~~ — During the second quarter of 2016, the Company determined it no longer had control of its wind development projects in the United Kingdom (“UK Wind”) as the Company no longer held seats on the board of directors. In accordance with the accounting guidance, UK Wind was deconsolidated and a loss on deconsolidation of $20 million was recorded to ~~Gain (loss) on disposal and sale of businesses~~ ~~in the Condensed Consolidated Statement of Operations to write off the Company’s noncontrolling interest in the project. The UK Wind projects were reported in the Eurasia SBU reportable segment.~~

Accumulated Other Comprehensive Loss — The following table summarizes the changes in AOCL by component, net of tax and NCI, for the nine months ended September 30, ~~2017~~2023 (in millions):

Foreign currency translation adjustment, net Unrealized derivative gains (losses), net Unfunded pension obligations, net Total
Balance at the beginning of the period $ (2,147 ) $ (323 ) $ (286 ) $ (2,756 )
Other comprehensive income (loss) before reclassifications 19
(35 ) (3 ) (19 )
Amount reclassified to earnings 98
40
4
142
Other comprehensive income 117
5
1
123
Reclassification from NCI due to Alto Maipo Restructuring —
(33 ) —
(33 )
Balance at the end of the period $ (2,030 ) $ (351 ) $ (285 ) $ (2,666 )


	Foreign currency translation adjustment, net		Unrealized derivative gains (losses), net		Unfunded pension obligations, net		Total
Balance at the beginning of the period	$	(1,828)	$	211	$	(23)	$	(1,640)
Other comprehensive income before reclassifications	71		227		—		298
Amount reclassified to earnings	—		(45)		—		(45)
Other comprehensive income	71		182		—		253
Reclassification to NCI due to sales	—		(23)		—		(23)
Balance at the end of the period	$	(1,757)	$	370	$	(23)	$	(1,410)

Reclassifications out of AOCL are presented in the following table. Amounts for the periods indicated are in millions and those in ~~parenthesis~~parentheses indicate debits to the Condensed Consolidated Statements of Operations:


AOCL Components	Affected Line Item in the Condensed Consolidated Statements of Operations	Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022





Derivative gains (losses), net
	Non-regulated revenue	$	—	$	—	$	(8)	$	(1)
	Non-regulated cost of sales	(1)		(5)		(2)		(7)
	Interest expense	(3)		(9)		13		(42)
	Gain (loss) on disposal and sale of business interests	—		—		33		—
	Asset impairment expense	—		—		—		(16)
	Foreign currency transaction gains (losses)	—		2		(3)		2
	Income from continuing operations before taxes and equity in earnings of affiliates	(4)		(12)		33		(64)
	Income tax expense	—		(1)		(11)		12
	Net equity in losses of affiliates	5		(1)		27		—

	Net income	1		(14)		49		(52)
	Less: Net income attributable to noncontrolling interests and redeemable stock of subsidiaries	1		3		(4)		11
	Net income attributable to The AES Corporation	$	2	$	(11)	$	45	$	(41)
Amortization of defined benefit pension actuarial gain (loss), net
	Regulated cost of sales	$	—	$	—	$	—	$	(1)


	Other expense	—		(2)		—		(2)

	Income from continuing operations before taxes and equity in earnings of affiliates	—		(2)		—		(3)
	Income tax expense	—		1		—		1



	Net income	—		(1)		—		(2)
	Less: Net income attributable to noncontrolling interests and redeemable stock of subsidiaries	—		1		—		1

	Net income attributable to The AES Corporation	$	—	$	—	$	—	$	(1)
Total reclassifications for the period, net of income tax and noncontrolling interests		$	2	$	(11)	$	45	$	(42)

Details About AOCL Components Affected Line Item in the Condensed Consolidated Statements of Operations Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Foreign currency translation adjustment, net
Loss on disposal and sale of businesses $ —
$ —
$ (98 ) $ —
Net income (loss) attributable to The AES Corporation $ —
$ —
$ (98 ) $ —
Unrealized derivative gains (losses), net
Non-regulated revenue $ 12
$ 20
$ 22
$ 94
Non-regulated cost of sales (2 ) (17 ) (11 ) (54 )
Interest expense (20 ) (25 ) (63 ) (86 )
Foreign currency transaction gains (losses) 14
(3 ) (4 ) 18
Income (loss) from continuing operations before taxes and equity in earnings of affiliates 4
(25 ) (56 ) (28 )
Income tax benefit (expense) (5 ) 4
6
5
Loss from continuing operations (1 ) (21 ) (50 ) (23 )
Less: Net loss from operations attributable to noncontrolling interests and redeemable stock of subsidiaries 1
5
10
4
Net income (loss) attributable to The AES Corporation $ —
$ (16 ) $ (40 ) $ (19 )
Amortization of defined benefit pension actuarial loss, net
Regulated cost of sales $ (10 ) $ (4 ) $ (30 ) $ (13 )
General and administrative expenses —
—
1
—
Other expense (1 ) —
(1 ) —
Loss from continuing operations before taxes and equity in earnings of affiliates (11 ) (4 ) (30 ) (13 )
Income tax benefit 4
2
10
4
Loss from continuing operations (7 ) (2 ) (20 ) (9 )
Net loss from disposal and impairments of discontinued businesses —
(1 ) —
(1 )
Net loss (7 ) (3 ) (20 ) (10 )
Less: Net loss from operations attributable to noncontrolling interests and redeemable stock of subsidiaries 6
2
16
7
Net income (loss) attributable to The AES Corporation $ (1 ) $ (1 ) $ (4 ) $ (3 )
Total reclassifications for the period, net of income tax and noncontrolling interests $ (1 ) $ (17 ) $ (142 ) $ (22 )

Common Stock Dividends — The Parent Company paid dividends of ~~$0.12~~$0.1659 per outstanding share to its common stockholders during the first, second, and third quarters of ~~2017~~2023 for dividends declared in December ~~2016,~~2022, February ~~2017,~~2023 and July ~~2017,~~2023, respectively.

On October 6, ~~2017,~~2023, the Board of Directors declared a quarterly common stock dividend of ~~$0.12~~$0.1659 per share payable on November 15, ~~2017,~~2023, to shareholders of record at the close of business on November 1, ~~2017.~~2023.

28 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

12. SEGMENTS

The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the businesses ~~internally~~internally. In our 2022 Form 10-K, the management reporting structure and isthe Company’s reportable segments were mainly organized by geographic ~~regions which provides~~regions. In March 2023, we announced internal management changes as a ~~socio-political-economic understanding~~part of our ~~business. During the third quarter of 2017, the Europe~~ongoing strategy to align our business to meet our customers’ needs and ~~Asia SBUs were merged in order to leverage scale and are now reported as part of the Eurasia SBU.~~deliver on our major strategic objectives. The management reporting structure is now composed of four SBUs, mainly organized by ~~five SBUs~~technology, led by our President and Chief Executive ~~Officer: US, Andes, Brazil, MCAC, and Eurasia SBUs.~~Officer. Using the accounting guidance on segment reporting, the Company determined that ~~it has five~~its four operating ~~and five~~segments are aligned with its four reportable segments corresponding to its SBUs. All prior period results have been retrospectively revised to reflect the new segment reporting structure.

~~Corporate~~•Renewables— Solar, wind, energy storage, and ~~Other~~hydro generation facilities;

•Utilities— ~~Corporate~~AES Indiana, AES Ohio, and AES El Salvador regulated utilities and their generation facilities;

•Energy Infrastructure— Natural gas, LNG, coal, pet coke, diesel and oil generation facilities, and our businesses in Chile, which have a mix of generation sources, including renewables, that are pooled to service our existing PPAs; and

•New Energy Technologies— Green hydrogen initiatives and investments inFluence, Uplight, 5B, and other new and innovative energy technology businesses.

Our Renewables, Utilities and Energy Infrastructure SBUs participate in our generation business line, in which we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. Our Utilities SBU participates in our utilities business line, in which we own and/or operate utilities to generate or purchase, distribute, transmit, and sell electricity to end-user customers in the residential, commercial, industrial, and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market. Our New Energy Technologies SBU includes investments in new and innovative technologies to support leading-edge greener energy solutions.

Included in “Corporate and Other” are the results of the AES self-insurance company, corporate overhead costs which are not directly associated with the operations of our ~~five~~four reportable segments, ~~are included in “Corporate~~ and ~~Other.” Also included are~~ certain intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.

~~The~~During the first quarter of 2023, management began assessing operational performance and making resource allocation decisions using Adjusted EBITDA. Therefore, the Company uses Adjusted ~~PTC~~EBITDA as its primary segment performance measure. Adjusted ~~PTC,~~EBITDA, a non-GAAP measure, is defined by the Company as ~~pretax~~earnings before interest income ~~from continuing operations attributable to The AES Corporation~~and expense, taxes, depreciation and amortization, adjusted for the impact of NCI and interest, taxes, depreciation and amortization of our equity affiliates, and adding back interest income recognized under service concession arrangements; excluding gains or losses of both consolidated entities and entities accounted for under the ~~consolidated entity~~equity method due to (a) unrealized gains or losses related to derivative ~~transactions;~~transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, or losses, ~~and associated~~ benefits and costs ~~due to~~associated with dispositions and acquisitions of business interests, including early plant closures, and ~~the tax impact from the repatriation~~gains and losses recognized at commencement of ~~sales proceeds;~~sales-type leases; (d) losses due to impairments; ~~and~~ (e) gains, losses and costs due to the early retirement of ~~debt. Adjusted PTC also includes~~debt; and (f) net ~~equity~~gains at Angamos, one of our businesses in ~~earnings of affiliates on an after-tax basis~~the Energy Infrastructure SBU, associated with the early contract terminations with Minera Escondida and Minera Spence.

~~adjusted for the same gains or losses excluded from consolidated entities.~~ The Company has concluded ~~that~~ Adjusted ~~PTC~~EBITDA better reflects the underlying business performance of the Company and is the most relevant measure considered in the ~~Company’s~~Company's internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and overall complexity, the Company ~~has~~ concluded that Adjusted ~~PTC~~EBITDA is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the ~~Company’s~~Company's results.

Revenue and Adjusted ~~PTC~~EBITDA are presented before inter-segment eliminations, which includes the effect of intercompany transactions with other segments except for ~~interest,~~ charges for certain management fees and the write-off of intercompany balances, as applicable. All intra-segment activity has been eliminated within the segment. Inter-segment activity has been eliminated within the total consolidated results.

29 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

The following tables present financial information by segment for the periods indicated (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
Total Revenue	2023		2022		2023		2022
Renewables SBU	$	708	$	532	$	1,744	$	1,407
Utilities SBU	880		994		2,703		2,674
Energy Infrastructure SBU	1,861		2,126		5,239		5,553
New Energy Technologies SBU	—		—		75		2
Corporate and Other	29		24		96		81
Eliminations	(44)		(49)		(157)		(160)
Total Revenue	$	3,434	$	3,627	$	9,700	$	9,557


	Three Months Ended September 30,				Nine Months Ended September 30,
Reconciliation of Adjusted EBITDA (in millions)	2023		2022		2023		2022
Net income	$	291	$	446	$	461	$	481
Income tax expense	109		145		179		186
Interest expense	326		276		966		813
Interest income	(144)		(100)		(398)		(270)
Depreciation and amortization	286		266		836		800
EBITDA	$	868	$	1,033	$	2,044	$	2,010

Less: Adjustment for noncontrolling interests and redeemable stock of subsidiaries (1)	(183)		(174)		(508)		(486)
Less: Income tax expense (benefit), interest expense (income) and depreciation and amortization from equity affiliates	27		36		93		93
Interest income recognized under service concession arrangements	18		19		54		58
Unrealized derivative and equity securities losses (gains)	10		(8)		3		—
Unrealized foreign currency losses	97		3		161		23
Disposition/acquisition losses	8		4		21		36
Impairment losses	145		17		318		497
Loss on extinguishment of debt	—		1		1		7

Adjusted EBITDA	$	990	$	931	$	2,187	$	2,238

_____________________________

(1)The allocation of earnings to tax equity investors from both consolidated entities and equity affiliates is removed from Adjusted EBITDA.


	Three Months Ended September 30,				Nine Months Ended September 30,
Adjusted EBITDA	2023		2022		2023		2022
Renewables SBU	$	267	$	195	$	557	$	476
Utilities SBU	216		137		526		456
Energy Infrastructure SBU	520		620		1,165		1,353
New Energy Technologies SBU	(22)		(27)		(61)		(88)
Corporate and Other	8		9		20		10
Eliminations	1		(3)		(20)		31
Adjusted EBITDA	$	990	$	931	$	2,187	$	2,238

The Company uses long-lived assets as its measure of segment assets. Long-lived assets includes amounts recorded in Property, plant and equipment, net and right-of-use assets for operating leases recorded in Other noncurrent assets on the Condensed Consolidated Balance Sheets.


Long-Lived Assets	September 30, 2023		December 31, 2022
Renewables SBU	$	13,618	$	9,533
Utilities SBU	6,809		6,311
Energy Infrastructure SBU	7,467		7,532
New Energy Technologies SBU	8		2

Corporate and Other	10		17
Long-Lived Assets	27,912		23,395
Current assets	7,317		7,643
Investments in and advances to affiliates	894		952
Debt service reserves and other deposits	205		177
Goodwill	362		362
Other intangible assets	2,290		1,841
Deferred income taxes	428		319
Loan receivable	990		1,051
Other noncurrent assets, excluding right-of-use assets for operating leases	2,763		2,623
Total Assets	$	43,161	$	38,363

Three Months Ended September 30, Nine Months Ended September 30,
Total Revenue 2017 2016 2017 2016
US SBU $ 852
$ 916
$ 2,445
$ 2,582
Andes SBU 689
667
1,979
1,864
Brazil SBU 1,085
1,027
3,106
2,761
MCAC SBU 630
547
1,851
1,596
Eurasia SBU 380
386
1,204
1,249
Corporate and Other 9
6
29
8
Eliminations (13 ) (7 ) (20 ) (18 )
Total Revenue $ 3,632
$ 3,542
$ 10,594
$ 10,042

30 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

13. REVENUE

The following table presents our revenue from contracts with customers and other revenue for the periods indicated (in millions):



	Three Months Ended September 30, 2023
	Renewables SBU		Utilities SBU		Energy Infrastructure SBU		New Energy Technologies SBU		Corporate, Other and Eliminations		Total
Non-Regulated Revenue
Revenue from contracts with customers	$	672	$	16	$	1,655	$	—	$	(14)	$	2,329


Other non-regulated revenue (1)	36		1		206		—		(1)		242
Total non-regulated revenue	708		17		1,861		—		(15)		2,571
Regulated Revenue
Revenue from contracts with customers	—		855		—		—		—		855

Other regulated revenue	—		8		—		—		—		8
Total regulated revenue	—		863		—		—		—		863
Total revenue	$	708	$	880	$	1,861	$	—	$	(15)	$	3,434

	Three Months Ended September 30, 2022
	Renewables SBU		Utilities SBU		Energy Infrastructure SBU		New Energy Technologies SBU		Corporate, Other and Eliminations		Total
Non-Regulated Revenue
Revenue from contracts with customers	$	494	$	17	$	2,030	$	—	$	(25)	$	2,516


Other non-regulated revenue (1)	38		1		96		—		—		135
Total non-regulated revenue	532		18		2,126		—		(25)		2,651
Regulated Revenue
Revenue from contracts with customers	—		968		—		—		—		968

Other regulated revenue	—		8		—		—		—		8
Total regulated revenue	—		976		—		—		—		976
Total revenue	$	532	$	994	$	2,126	$	—	$	(25)	$	3,627



	Nine Months Ended September 30, 2023
	Renewables SBU		Utilities SBU		Energy Infrastructure SBU		New Energy Technologies SBU		Corporate, Other and Eliminations		Total
Non-Regulated Revenue
Revenue from contracts with customers	$	1,654	$	51	$	4,717	$	74	$	(60)	$	6,436


Other non-regulated revenue (1)	90		3		522		1		(1)		615
Total non-regulated revenue	1,744		54		5,239		75		(61)		7,051
Regulated Revenue
Revenue from contracts with customers	—		2,624		—		—		—		2,624

Other regulated revenue	—		25		—		—		—		25
Total regulated revenue	—		2,649		—		—		—		2,649
Total revenue	$	1,744	$	2,703	$	5,239	$	75	$	(61)	$	9,700

	Nine Months Ended September 30, 2022
	Renewables SBU		Utilities SBU		Energy Infrastructure SBU		New Energy Technologies SBU		Corporate, Other and Eliminations		Total
Non-Regulated Revenue
Revenue from contracts with customers	$	1,325	$	58	$	5,207	$	1	$	(79)	$	6,512


Other non-regulated revenue (1)	82		3		346		1		—		432
Total non-regulated revenue	1,407		61		5,553		2		(79)		6,944
Regulated Revenue
Revenue from contracts with customers	—		2,590		—		—		—		2,590

Other regulated revenue	—		23		—		—		—		23
Total regulated revenue	—		2,613		—		—		—		2,613
Total revenue	$	1,407	$	2,674	$	5,553	$	2	$	(79)	$	9,557

(1) Other non-regulated revenue primarily includes lease and derivative revenue not accounted for under ASC 606.

Contract Balances — The timing of revenue recognition, billings, and cash collections results in accounts receivable and contract liabilities. The contract liabilities from contracts with customers were $379 million and $337 million as of September 30, 2023 and December 31, 2022, respectively.

31 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

Three Months Ended September 30, Nine Months Ended September 30,
Total Adjusted PTC 2017 2016 2017 2016
Reconciliation from Income from Continuing Operations before Taxes and Equity In Earnings of Affiliates:
Income from continuing operations before taxes and equity in earnings of affiliates $ 347
$ 294
$ 746
$ 445
Add: Net equity in earnings of affiliates 24
11
33
25
Less: Income from continuing operations before taxes, attributable to noncontrolling interests (148 ) (82 ) (454 ) (196 )
Pretax contribution 223
223
325
274
Unrealized derivative losses (gains) (8 ) 5
(7 ) 1
Unrealized foreign currency transaction losses (gains) (21 ) 3
(54 ) 12
Disposition/acquisition losses (gains) 1
(3 ) 107
(5 )
Impairment expense 2
24
264
309
Losses on extinguishment of debt 48
20
43
26
Total Adjusted PTC $ 245
$ 272
$ 678
$ 617

Three Months Ended September 30, Nine Months Ended September 30,
Total Adjusted PTC 2017 2016 2017 2016
US SBU $ 129
$ 114
$ 240
$ 257
Andes SBU 62
134
232
279
Brazil SBU 12
6
64
18
MCAC SBU 98
74
256
197
Eurasia SBU 61
46
218
197
Corporate and Other (117 ) (102 ) (332 ) (331 )
Total Adjusted PTC $ 245
$ 272
$ 678
$ 617
During the nine months ended September 30, 2023 and 2022, we recognized revenue of $30 million and $34 million, respectively, that was included in the corresponding contract liability balance at the beginning of the periods.

In June 2023, the Company closed on an agreement to terminate the PPA for the Warrior Run coal-fired power plant for total consideration of $357 million, to be paid by the offtaker through the end of the previous contract term in January 2030. Under the termination agreement, the plant will continue providing capacity through May 2024. The termination represents a contract modification under which the discounted termination payments, as well as a pre-existing contract liability, will be recognized as revenue on a straight-line basis over the remaining performance obligation period for approximately $32 million per month. As of September 30, 2023, the corresponding receivable balance was $77 million, of which $40 million and $37 million was recorded in Other current assets and Other noncurrent assets, respectively, on the Condensed Consolidated Balance Sheet. A significant financing component of $57 million will be recognized over the life of the payment term as interest income using the effective interest method.

A significant financing arrangement exists for our Mong Duong plant in Vietnam. The plant was constructed under a build, operate, and transfer contract and will be transferred to the Vietnamese government after the completion of a 25 year PPA. The performance obligation to construct the facility was substantially completed in 2015. Contract consideration related to the construction, but not yet collected through the 25 year PPA, was reflected on the Condensed Consolidated Balance Sheet. As of September 30, 2023 and December 31, 2022, the Mong Duong loan receivable had a balance of $1.1 billion, net of CECL reserves of $26 million and $28 million, respectively. Of the loan receivable balance, $105 million and $97 million, respectively, was classified as Other current assets, and $990 million and $1 billion, respectively, was classified as Loan receivable on the Condensed Consolidated Balance Sheets.

Remaining Performance Obligations — The transaction price allocated to remaining performance obligations represents future consideration for unsatisfied (or partially unsatisfied) performance obligations at the end of the reporting period. As of September 30, 2023, the aggregate amount of transaction price allocated to remaining performance obligations was $6 million, primarily consisting of fixed consideration for the sale of renewable energy credits in long-term contracts in the U.S. We expect to recognize revenue of approximately $1 million per year between 2023 and 2027 and the remainder thereafter.

Total Assets September 30, 2017 December 31, 2016
US SBU $ 10,104
$ 9,333
Andes SBU 9,339
8,971
Brazil SBU 7,416
6,448
MCAC SBU 5,640
5,162
Eurasia SBU 5,938
5,777
Assets of held-for-sale businesses 76
—
Corporate and Other 321
428
Total Assets $ 38,834
$ 36,119

~~13.~~14. OTHER INCOME AND EXPENSE

Other income generally includes gains on insurance recoveries in excess of property damage, gains on asset sales and liability extinguishments, favorable judgments on contingencies, ~~gains on contract terminations,~~ allowance for funds used during construction, and other income from miscellaneous transactions. Other expense generally includes losses on asset sales and dispositions, losses on

legal contingencies, and losses from other miscellaneous transactions. The components are summarized as follows (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
Other Income	AFUDC (US Utilities)	$	5	$	4	$	11	$	9
	Legal settlements	—		—		3		6
	Gain on sale of assets	1		—		3		—
	Gain on remeasurement of investment (1)	—		—		—		26
	Insurance proceeds (2)	—		—		—		16
	Gain on acquired customer contracts	—		—		—		5
	Gain on remeasurement of contingent consideration	—		—		—		3


	Other	6		—		19		15
	Total other income	$	12	$	4	$	36	$	80




Other Expense	Loss on sale and disposal of assets	$	3	$	—	$	12	$	9
	Non-service pension and other postretirement costs	2		—		9		—
	Loss on remeasurement of contingent consideration	1		—		9		—
	Allowance for lease receivable (3)	—		—		—		20
	Legal contingencies and settlements	—		8		1		8
	Other	6		2		7		14
	Total other expense	$	12	$	10	$	38	$	51

(1) Related to the remeasurement of our existing investment in 5B, accounted for using the measurement alternative.

(2) Primarily related to insurance recoveries associated with property damage at TermoAndes.

(3) Related to a full allowance recognized on a sales-type lease receivable at AES Gilbert due to a fire incident in April 2022.

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Other Income
Legal settlements ⁽¹⁾
$ —
$ —
$ 60
$ —
Allowance for funds used during construction (US Utilities) 7
8
20
22
Gain on sale of assets 2
—
3
3
Other 9
10
22
18
Total other income $ 18
$ 18
$ 105
$ 43

Other Expense Loss on sale and disposal of assets $ 16
$ 12
$ 54
$ 26
Water rights write-off 15
—
18
7

Allowance for other receivables ⁽²⁾
15
—
15
—
Legal contingencies and settlements 1
1
2
5
Other —
—
6
4
Total other expense $ 47
$ 13
$ 95
$ 42

32 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

~~_____________________________~~


⁽¹⁾	In December 2016, the Company and YPF entered into a settlement agreement in which all parties agreed to give up any and all legal action related to gas supply contracts that were terminated in 2008 and have been in dispute since 2009. In January 2017, the YPF board approved the agreement and paid the Company $60 million, thereby resolving all uncertainties around the dispute.


⁽²⁾	~~During the third quarter of 2017, we recognized a full allowance on a non-trade receivable in Andes due to collection uncertainties.~~

~~14.~~15. ASSET IMPAIRMENT EXPENSE

Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2017 2016 2017 2016
Kazakhstan Hydroelectric $ 2
$ —
$ 92
$ —
Kazakhstan CHPs —
—
94
—
Buffalo Gap I —
78
—
78
DPL —
—
66
235
Tait Energy Storage —
—
8
—
Buffalo Gap II —
—
—
159
Other —
1
—
1
Total $ 2
$ 79
$ 260
$ 473

~~Kazakhstan Hydroelectric~~ — In April 2017, the Republic of Kazakhstan stated the concession would not be extended for Shulbinsk HPP and Ust-Kamenogorsk HPP, two hydroelectric plants in Kazakhstan, and initiated the process to transfer these plants back to the government. The ~~fair value of the asset group was determined to be below carrying value. As a result, the Company recognized~~following table presents our asset impairment expense for the periods indicated (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Norgener	$	—	$	—	$	137	$	—
TEG	77		—		77		—
TEP	59		—		59		—
Jordan	14		51		43		51
GAF Projects (AES Renewable Holdings)	—		—		18		—
Maritza	—		—		—		468












Other	8		(1)		18		14
Total	$	158	$	50	$	352	$	533

TEG and TEP — During the third quarter of ~~$92 million during~~2023, management identified an impairment indicator at the ~~nine months ended September 30, 2017. The Kazakhstan hydroelectric plants are reported~~TEG and TEP asset groups due to a reduction in ~~the Eurasia SBU reportable segment. See Note 16—Held-for-Sale Businesses and Dispositions~~ ~~of this Form 10-Q for further information.~~

~~DPL~~ ~~— On March 17, 2017, the board of directors of DPL approved the retirement~~expected cash flows after expiration of the ~~DPL operated and co-owned Stuart Station coal-fired and diesel-fired generating units, and the Killen Station coal-fired generating unit and combustion turbine on or before June 1, 2018.~~current PPAs. The Company performed ~~a long-lived asset~~an impairment analysis as of July 31, 2023, and determined that the carrying amounts of the ~~facilities~~asset groups were not recoverable. The ~~Stuart Station~~TEG and ~~Killen Station~~TEP asset groups were determined to have fair values of $3$93 million and $8$94 million, respectively, using the income approach. As a result, the Company recognized ~~a total~~pre-tax asset impairment expense of ~~$66 million. DPL is~~$77 million and $59 million, respectively. TEG and TEP are reported in the USEnergy Infrastructure SBU reportable segment.

~~During~~Norgener — In May 2023, AES Andes announced its intention to accelerate the ~~second quarter~~retirement of ~~2016,~~the Norgener coal-fired plant in Chile in order to further advance its decarbonization strategy. Due to this strategic development and the resulting decrease in useful life of the generation facility, the Company tested the recoverability of its long-lived generation assets at DPL. Uncertainty created by the Supreme Court of Ohio’s June 20, 2016 opinion, lower expectations of future revenue resulting from the most recent PJM capacity auction, and higher anticipated environmental compliance costs resulting from third party studies were collectively determined to beperformed an impairment ~~indicator for these assets. The Company performed a long-lived asset impairment~~ analysis as of May 1, 2023, and determined that the carrying amount of Killen, a coal-fired generation facility, and certain DPL peaking generation facilities were not recoverable. The Killen and DPL peaking generation asset groups were determined to have a fair value of $84 million and $5 million, respectively, using the ~~income approach. As a result, the Company recognized a total asset impairment expense of $235 million. DPL is reported in the US SBU reportable segment.~~

~~Kazakhstan CHPs~~ — In January 2017, the Company entered into an agreement for the sale of Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan. The fair value of the Kazakhstan asset group was determined to be below carrying value. As a result, the Company recognized asset

impairment expense of $94 million during the three months ended March 31, 2017. The Company completed the sale of its interest in the Kazakhstan CHP plants on April 7, 2017. Prior to their sale, the plants were reported in the Eurasia SBU reportable segment. See Note 16—~~Held-for-Sale Businesses and Dispositions~~ ~~of this Form 10-Q for further information.~~

~~Buffalo Gap I~~ — During the third quarter of 2016, the Company tested the recoverability of its long-lived assets at Buffalo Gap I. As a result of decreases in wind production, management underwent a process to enhance the methodology for forecasting wind dispatch. The change in management’s estimate of dispatch resulted in lower forecasted revenues from September 2016 through the end of the asset group’s useful life. The Company determined that the carrying amount of the Buffalo Gap I asset group was not recoverable. The ~~Buffalo Gap I~~Norgener asset group was determined to have a fair value of ~~$35~~$24 million, using the income approach. As a result, and since pre-tax losses are limited to the carrying amount of the long-lived assets, the Company recognized pre-tax asset impairment expense of $137 million. Norgener is reported in the Energy Infrastructure SBU reportable segment.

Jordan — In November 2020, the Company signed an agreement to sell 26% ownership interest in Amman East and IPP4 for $58 million and as of September 30, 2023, the generation plants were classified as held-for-sale. Due to the delay in closing the transaction, the carrying amount of the asset group in subsequent periods exceeded the agreed-upon sales price, and total pre-tax impairment expense of $43 million and $51 million was recorded during the nine months ended September 30, 2023 and 2022, respectively. See Note 17—Held-for-Sale for further information. Amman East and IPP4 are reported in the Energy Infrastructure SBU reportable segment.

GAF Projects — During the second quarter of 2023, management concluded that the carrying value of six project companies at AES Renewable Holdings (the “GAF Projects”) may not be recoverable as the expected purchase price on the buyout of tax equity partners implied a loss on the transaction. The buyout was completed in July 2023. Management performed a recoverability test as of May 31, 2023 and concluded that the undiscounted cash flows of the GAF Projects did not exceed the carrying values of the asset groups for five of the six projects. The asset groups for the GAF Projects were determined to have a fair value of $11 million, using the income approach. As a result, the Company recognized anpre-tax asset impairment expense of ~~$78 million ($23 million attributable to AES). Buffalo Gap I~~$18 million. AES Renewable Holdings is reported in the USRenewables SBU reportable segment.

~~Buffalo Gap II~~ Maritza— ~~During~~In May 2022, the ~~first quarter of 2016,~~Council for the European Union approved Bulgaria’s National Recovery and Resilience plan, which commits the country to cease generating electricity from coal beyond 2038. As this plan is expected to prohibit the Company ~~tested~~from operating the ~~recoverability~~Maritza coal-fired plant through its estimated useful life, it was determined that an indicator of ~~its long-lived assets at Buffalo Gap II. Impairment indicators were identified based on a decline~~impairment had occurred. The Company reassessed the useful life of the facility and performed an impairment analysis as of April 30, 2022, in ~~forward power curves. The Company~~which it was determined that the carrying amount of the asset group was not recoverable. The ~~Buffalo Gap II~~Maritza asset group was determined to have a fair value of ~~$92~~$452 million, using the income approach. As a result, the Company recognized pre-tax asset impairment expense of ~~$159 million ($49 million attributable to AES). Buffalo Gap II~~$468 million. Maritza is reported in the USEnergy Infrastructure SBU reportable segment.

~~15. DISCONTINUED OPERATIONS~~16. INCOME TAXES

~~Brazil Distribution —~~ ~~Due to a portfolio evaluation in~~The Company’s provision for income taxes is based on the ~~first half of 2016, management decided to pursue a strategic shift of its distribution companies in Brazil, Sul~~estimated annual effective tax rate, plus discrete items. The effective tax rate for both the three and Eletropaulo. In June 2016, the Company executed an agreement for the sale of Sul and reported its results of operations and financial position as discontinued operations. The disposal of Sul was completed in October 2016. Prior to its classification as discontinued operations, Sul was reported in the Brazil SBU reportable segment. In December 2016, Eletropaulo underwent a corporate restructuring which is expected to, among other things, provide more liquidity of its shares. AES is continuing to pursue strategic options for Eletropaulo in order to complete its strategic shift to reduce AES’ exposure to the Brazilian distribution businesses, including preparation for listing its shares into the Novo Mercado, which is a listing segment of the Brazilian stock exchange with the highest standards of corporate governance.

~~As the sale of Sul was completed during 2016, there were no assets or liabilities of discontinued operations at~~nine months ended September 30, ~~2017 or December 31, 2016. There were no significant losses from discontinued operations or cash flows used in operating or investing activities of discontinued operations~~2023 was 26%. The effective tax rates for the three and nine months ended September 30, ~~2017.~~2022 were 24% and 26%, respectively. The difference between the Company’s effective tax rates for the 2023 and 2022 periods and the U.S. statutory tax rate of 21%

~~The following table summarizes~~

33 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

related primarily to U.S. taxes on foreign earnings, foreign tax rate differentials, the ~~major line items constituting the~~ ~~loss from discontinued operations~~ ~~for~~impacts of foreign currency fluctuations at certain foreign subsidiaries, nondeductible expenses, and valuation allowance.

For the three and nine months ended September 30, ~~2016 (in millions):~~

Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016
Loss from discontinued operations, net of tax
Revenue — regulated
$ 213
$ 632
Cost of sales (200 ) (608 )
Asset impairment expense —
(783 )
Other income and expense items that are not major, net (14 ) (35 )
Pretax loss from discontinued operations $ (1 ) $ (794 )
Income tax benefit —
405
Loss from discontinued operations, net of tax $ (1 ) $ (389 )

~~The following table summarizes the operating and investing cash flows from discontinued operations for the nine months ended September 30, 2016 (in millions):~~

Nine Months Ended September 30, 2016
Cash flows provided by operating activities of discontinued operations $ 68
Cash flows used in investing activities of discontinued operations (63 )

~~16. HELD-FOR-SALE BUSINESSES AND DISPOSITIONS~~

~~Held-for-Sale Businesses~~

~~Kazakhstan Hydroelectric~~— ~~Affiliates of~~2023, the Company ~~(the “Affiliates”) previously operated Shulbinsk HPP~~recorded discrete tax benefit of approximately $15 million and Ust-Kamenogorsk HPP (the “HPPs”), two hydroelectric plants in Kazakhstan, under a concession agreement with the Republic of Kazakhstan (“RoK”). In April 2017, the RoK initiated the process to transfer these plants back to the RoK. Management considered it probable that the transfer would occur, and these plants met the held-for-sale criteria in the second quarter of 2017. $31 million, respectively, resulting from foreign currency fluctuations at certain Argentine businesses.

For the nine months ended September 30, ~~2017, impairment charges~~2022, the Company recorded discrete tax benefit of ~~$92~~approximately $19 million ~~were recorded and were limited to~~resulting from foreign currency fluctuations at certain Argentine businesses.

17. HELD-FOR-SALE

Jordan — In November 2020, the carrying value of the long lived assets. As of September 30, 2017, the remaining carrying value of the asset group, which was classified as held-for-sale, totaled $114 million, which included cumulative translation losses of $103 million.

On September 29, 2017, rather than paying the Affiliates, the RoK deposited $77 million into an escrow account that was not established in accordance with the requirements of the concession agreement. The amount deposited by the RoK equaled the Affiliates’ calculation of the transfer payment. In return, the RoK asserted that the Affiliates would be required to transfer the HPPs and that arbitration would be necessary to determine the correct transfer payment. On October 2, 2017, the Affiliates transferred 100% of the shares in the plants to the RoK, under protest and with a reservation of rights. As such, the HPPs remained classified as held-for-sale as of September 30, 2017. The Company expects to record a loss on disposal of at least $37 million in the fourth quarter of 2017. The Affiliates will proceed with arbitration to recover the $77 million that was placed in escrow, unless the parties can resolve the dispute prior to the initiation of arbitration. Additional losses may be incurred if some or all of the disputed consideration is not subsequently paid by the RoK. The transfer does not meet the criteria to be reported as discontinued operations. The Kazakhstan HPPs are reported in the Eurasia SBU reportable segment. Excluding the impairment charge, pretax income attributable to AES was as follows:

Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2017 2016 2017 2016
Kazakhstan Hydroelectric $ 12
$ 10
$ 33
$ 28

~~Zimmer and Miami Fort —~~ ~~In April 2017, DP&L and AES Ohio Generation entered into~~signed an agreement ~~for the sale of DP&L’s undivided~~to sell 26% ownership interest in ~~Zimmer~~Amman East and ~~Miami Fort~~IPP4 for ~~$50 million~~ ~~in cash and the assumption of certain liabilities, including environmental, subject to predefined closing adjustments.~~$58 million. The sale ~~is subject to approval by the Federal Energy Regulatory Commission and~~ is expected to close in 2023. After completion of the ~~fourth quarter~~sale, the Company will retain a 10% ownership interest in Amman East and IPP4, which will be accounted for as an equity method investment. As of ~~2017. Accordingly, Zimmer and Miami Fort remained~~September 30, 2023, the generation plants were classified as held-for-sale, ~~as of September 30, 2017,~~ but did not meet the criteria to be reported as discontinued operations. ~~Zimmer~~On a consolidated basis, the carrying value of the plants held-for-sale as of September 30, 2023 was $164 million. Amman East and ~~Miami Fort~~IPP4 are reported in the USEnergy Infrastructure SBU reportable segment. ~~Their combined pretax~~

Excluding any impairment charges, pre-tax income (loss) attributable to AES of businesses held-for-sale as of September 30, 2023 was as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2023		2022		2023		2022

Jordan	$	5	$	(13)	$	16	$	(2)

18. ACQUISITIONS

Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2017 2016 2017 2016
Zimmer and Miami Fort $ 11
$ 1
$ 19
$ (10 )

~~Dispositions~~

~~Kazakhstan CHPs~~Petersburg Solar Project— ~~In April 2017,~~On August 31, 2023, the Company ~~completed~~entered into agreements for project development and for the ~~sale~~purchase of ~~Ust-Kamenogorsk CHP and Sogrinsk CHP, its combined heating and power coal plants in Kazakhstan, for net proceeds of $24 million. The carrying value~~100% of the membership in Petersburg Energy Center, LLC, a 250 MW solar and BESS project. The transaction was accounted for as an asset ~~group~~acquisition of $171 million was greater than its fair value less costs to sell of $29 million. The Company recognized an impairment charge of $94 million, which was limited to the carrying value of the long lived assets, and recognized a pretax loss on sale of $49 million, primarily related to cumulative translation losses. The salevariable interest entities that did not meet the ~~criteria to be reported as discontinued operations. Prior to~~definition of a business. The assets acquired and liabilities assumed were recorded at their ~~sale,~~fair values, which equaled the ~~Kazakhstan CHP plants were~~fair value of the consideration paid of approximately $49 million. Petersburg Solar Project is reported in the ~~Eurasia~~Utilities SBU reportable segment. ~~Excluding the impairment charge and loss on sale, pretax income (loss) attributable to AES was as follows:~~

Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2017 2016 2017 2016
Kazakhstan CHPs $ —
$ (2 ) $ 13
$ 5

~~DPLER~~Calhoun— On ~~January 1, 2016,~~July 18, 2023, the Company ~~completed~~entered into an agreement for the ~~sale~~purchase of ~~its~~100% of the membership interests in Calhoun County Solar Project, LLC., which holds a late development-stage 125 MW solar project. The transaction was accounted for as an asset acquisition of variable interest in DPLER, a competitive retail marketer selling electricity to customers in Ohio. Upon completion, proceeds of $76 million were received and a gain on sale of $49 million was recognized. The sale of DPLERentities that did not meet the ~~criteria~~definition of a business. The assets acquired and liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration paid of approximately $64 million, including contingent consideration of $42 million. The estimated fair value of the contingent consideration for Calhoun was determined using probability-weighted discounted cash flows based on internal forecasts, which are considered Level 3 inputs. The probability of achieving the milestone payment used to calculate the acquisition date fair value of the contingent consideration was 99%. Payments under the contingent consideration arrangement are largely binary and thus, a single probability of achieving the milestone was applied in the calculation of fair value.The contingent consideration will be ~~reported as a discontinued operation. Prior to its sale, DPLER was~~updated quarterly with any prospective changes in fair value recorded through earnings. Calhoun is reported in the USRenewables SBU reportable segment.

~~Kelanitissa~~Bellefield— On ~~January 27, 2016,~~June 5, 2023, the Company ~~completed~~entered into an agreement for the ~~sale~~purchase of ~~its~~100% of the membership interests in the Bellefield projects, consisting of two late development-stage solar and BESS projects of 1 GW each. The transaction was accounted for as an asset acquisition of variable interest ~~in Kelanitissa, a diesel-fired generation station in Sri Lanka. Upon completion, proceeds of $18 million were received and a loss on sale of $5 million was recognized. The sale of Kelanitissa~~entities that did not meet the ~~criteria~~definition of a business. The Company agreed to make total cash payments including reimbursement of development and equipment costs of approximately $449 million, a portion of which is contingent upon future milestones and price adjustments. In the case that future milestones are not met, the total cash payment will be adjusted accordingly, along with any other purchase price adjustments.

The assets acquired and liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration to be ~~reported as~~paid of approximately $358 million, including cash paid of $165 million, contingent consideration of $165 million, and deferred payments of $28 million.

34 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

The estimated fair value of the contingent consideration of Bellefield was determined using probability-weighted discounted cash flows based on internal forecasts, which are considered Level 3 inputs. The weighted average probability of achieving the milestone payments used to calculate the acquisition date fair value of the contingent consideration was 91.9%. Payments under the contingent consideration arrangements are largely binary and thus, a ~~discontinued operation. Prior to its sale, Kelanitissa~~single probability of achieving the milestone was applied in the calculation of fair value. The contingent consideration will be updated quarterly with any prospective changes in fair value recorded through earnings. Bellefield is reported in the ~~Eurasia~~Renewables SBU reportable segment.

~~UK Wind~~Bolero Solar Park — ~~During the second quarter of 2016,~~On June 9, 2023, the Company, ~~deconsolidated UK Wind and recorded a loss on deconsolidation of~~ ~~$20 million~~ to ~~Gain (loss) on disposal and sale of businesses~~ ~~in the Condensed Consolidated Statement of Operations. Prior to deconsolidation, UK Wind was reported in the Eurasia SBU reportable segment.~~

~~17. ACQUISITIONS~~

~~Alto Sertão II —~~ ~~On August 3, 2017, the Company completed the acquisition of~~through its subsidiary AES Andes S.A., acquired 100% of the ~~Alto Sertão II Wind Complex (“Alto Sertão II”) from Renova Energia S.A.~~equity interests in Helio Atacama Tres SpA, owner of the Bolero photovoltaic power plant for ~~$189 million, subject to customary purchase price adjustments, plus~~consideration of $114 million. The transaction was accounted for as an asset acquisition that did not meet the ~~assumption~~definition of $363 million of non-recourse debt, and up to $32 million of contingent consideration. At closing, the Company made an initial cash payment of $143 million, which excludes holdbacks related to indemnifications and purchase price adjustments.a business. As ~~of September 30, 2017, the purchase price allocation for Alto Sertão II~~Helio Atacama Tres is ~~preliminary. The Company is in the process of assessing~~not a VIE, any difference between the fair value of the assets and consideration transferred will be allocated to PP&E on a relative fair value basis. Helio Atacama Tres is reported in the Energy Infrastructure SBU reportable segment.

Agua Clara — On June 17, 2022, the Company, through its subsidiaries AES Dominicana Renewable Energy and AES Andres DR, S.A., acquired 100% of the equity interests in Agua Clara, S.A.S., a wind project for consideration of $98 million. The transaction was accounted for as an asset acquisition that did not meet the definition of a business. As Agua Clara is not a VIE, any difference between the fair value of the assets and consideration transferred will be allocated to PP&E on a relative fair value basis. Agua Clara is reported in the Renewables SBU reportable segment.

Tunica Windpower, LLC — On June 17, 2022, the Company entered into an agreement for the purchase of 100% of the membership interests in Tunica Windpower, LLC. The transaction was accounted for as an asset acquisition of variable interest entities that did not meet the definition of a business. The assets acquired and liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration paid of approximately $22 million, including contingent consideration of $7 million. The contingent consideration will be updated quarterly with any prospective changes in fair value recorded through earnings. Tunica Windpower is reported in the Renewables SBU reportable segment.

Windsor PV1, LLC — On May 27, 2022, the Company entered into an agreement for the purchase of 100% of the membership interests in Windsor PV1, LLC, an early development-stage solar project. The transaction was accounted for as an asset acquisition of variable interest entities that did not meet the definition of a business. The assets acquired and ~~expects to complete~~liabilities assumed were recorded at their fair values, which equaled the fair value of the consideration paid of approximately $17 million, including contingent consideration of $5 million. The contingent consideration will be updated quarterly with any prospective changes in fair value recorded through earnings. Windsor is reported in the Renewables SBU reportable segment.

Community Energy — In the first quarter of 2022, the Company finalized the purchase price allocation ~~within~~related to the ~~one year measurement period. Alto Sertão II~~acquisition of Community Energy, LLC. There were no significant adjustments made to the preliminary purchase price allocation recorded in the fourth quarter of 2021 when the acquisition was completed. Community Energy is ~~a wind farm with total installed capacity of 386 MW~~ reported in the ~~Brazil~~Renewables SBU reportable segment.

~~Bauru Solar Complex~~ New York Wind — ~~On September 25, 2017, AES Tietê executed an investment agreement with Cobra do Brasil~~ In the first quarter of 2022, the Company finalized the purchase price allocation related to ~~provide approximately $150 million~~the acquisition of ~~non-convertible debentures in project financing for~~Cogentrix Valcour Intermediate Holdings, LLC. There were no significant adjustments made to the ~~construction of photovoltaic solar plants in Brazil with total forecasted capacity of 180 MW. Upon completion of the project, expected to be concluded~~preliminary purchase price allocation recorded in the ~~first half~~fourth quarter of ~~2018, and subject to~~2021 when the ~~solar plants’ compliance with certain technical specifications defined~~acquisition was completed. New York Wind is reported in the ~~agreement, Tietê expects to acquire the solar complex in exchange for the non-convertible debentures and an additional investment of approximately $60 million.~~Renewables SBU reportable segment.

~~18.~~19. 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 RSUs, stock options, and ~~convertible securities.~~equity units. The effect of such potential common stock is computed using the treasury stock method orfor RSUs and stock options, and is computed using the if-converted method ~~as applicable.~~for equity units.

The following table is a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the three and nine months ended September 30, ~~2017~~2023 and ~~2016,~~2022, where income ~~or loss~~ represents the numerator and weighted average shares represent the denominator.

35 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022


Three Months Ended September 30,	2017						2016					Three Months Ended September 30,	2023					2022
(in millions, except per share data)	Income		Shares	$ per Share			Income		Shares	$ per Share		(in millions, except per share data)	Income		Shares	$ per Share		Income		Shares	$ per Share

BASIC EARNINGS PER SHARE												BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax ⁽¹⁾	$	152	660	$	0.23		$	171	659	$	0.26
Income from continuing operations attributable to The AES Corporation common stockholders												Income from continuing operations attributable to The AES Corporation common stockholders	$	231	670	$	0.34	$	421	668	$	0.63
EFFECT OF DILUTIVE SECURITIES												EFFECT OF DILUTIVE SECURITIES

Stock options												Stock options	—		—	—		—		1	—
Restricted stock units	—		3	—			—		3	—		Restricted stock units	—		2	—		—		2	—
Equity units												Equity units	—		40	(0.02)		—		40	(0.04)
DILUTED EARNINGS PER SHARE	$	152	663	$	0.23		$	171	662	$	0.26	DILUTED EARNINGS PER SHARE	$	231	712	$	0.32	$	421	711	$	0.59

Nine Months Ended September 30,	2017						2016
(in millions, except per share data)	Income		Shares	$ per Share			Income		Shares	$ per Share

BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax ⁽²⁾	$	181	660	$	0.28		$	203	660	$	0.31
EFFECT OF DILUTIVE SECURITIES
Restricted stock units	—		2	(0.01		)	—		2	—
DILUTED EARNINGS PER SHARE	$	181	662	$	0.27		$	203	662	$	0.31

~~_____________________________~~


⁽¹⁾	Income from continuing operations, net of tax, of $176 million less the $5 million adjustment to retained earnings to record the DP&L redeemable preferred stock at its redemption value as of September 30, 2016.


⁽²⁾	Income from continuing operations, net of tax, of $208 million less the $5 million adjustment to retained earnings to record the DP&L redeemable preferred stock at its redemption value as of September 30, 2016.


Nine Months Ended September 30,	2023					2022
(in millions, except per share data)	Income		Shares	$ per Share		Income		Shares	$ per Share

BASIC EARNINGS PER SHARE
Income from continuing operations attributable to The AES Corporation common stockholders	$	343	669	$	0.51	$	357	668	$	0.53
EFFECT OF DILUTIVE SECURITIES

Stock options	—		1	—		—		1	—
Restricted stock units	—		2	—		—		2	—
Equity units	1		40	(0.03)		1		40	(0.03)
DILUTED EARNINGS PER SHARE	$	344	712	$	0.48	$	358	711	$	0.50

~~For~~The calculation of diluted earnings per share excluded 2 million outstanding stock awards for the three and nine months ended September 30, ~~2017~~2023 and ~~2016, respectively, the calculation of diluted earnings per share excluded 6 million and 7 million outstanding~~September 30, 2022, which would be anti-dilutive. These stock awards ~~that~~ could potentially dilute basic earnings per share in the future. ~~All~~

As described in Note 11—Equity, the Company issued 10,430,500 Equity Units in March 2021 with a total notional value of $1,043 million. Each Equity Unit has a stated amount of $100 and was initially issued as a Corporate Unit, consisting of a 2024 Purchase Contract and a 10% undivided beneficial ownership interest in one share of Series A Preferred Stock. Prior to February 15, ~~million~~2024, the Series A Preferred Stock may be converted at the option of the holder only in connection with a fundamental change. On and after February 15, 2024, the Series A Preferred Stock may be converted freely at the option of the holder. Upon conversion, the Company will deliver to the holder with respect to each share of Series A Preferred Stock being converted (i) a share of our Series B Preferred Stock, or, solely with respect to conversions in connection with a redemption, cash and (ii) shares of ~~potential~~our common stock, ~~associated with convertible debentures (“TECONs”) were omitted from~~if any, in respect of any conversion value in excess of the ~~earnings~~liquidation preference of the preferred stock being converted. The conversion rate was initially 31.5428 shares of common stock per one share of Series A Preferred Stock, which was equivalent to an initial conversion price of approximately $31.70 per share ~~calculation for the three and nine months ended~~of common stock. As of September 30, ~~2016.~~2023, due to customary anti-dilution provisions, the conversion rate was 31.6465, equivalent to a conversion price of approximately $31.60 per share of common stock. The ~~company redeemed all~~Series A Preferred Stock and the 2024 Purchase Contracts are being accounted for as one unit of ~~its existing TECONs in June 2017. The stock awards~~account. In calculating diluted EPS, the Company has applied the if-converted method to determine the impact of the forward purchase feature and ~~convertible debentures were excluded from~~considered if there are incremental shares that should be included related to the ~~calculation because they were anti-dilutive.~~Series A Preferred conversion value.

~~19.~~20. RISKS AND UNCERTAINTIES

~~Alto Maipo —~~ ~~As disclosed in Note 26—Risks and Uncertainties~~ ~~in Item 8.—Financial Statements and Supplementary Data~~ of the 2016 Form 10-K, as of December 31, 2016, the Company has 531 MW under construction at Alto Maipo. Increased project costs, or delays in construction, could have an adverse impact on the Company. Alto Maipo has experienced construction difficulties, which have resulted in an increase in projected cost for the project of up to 22% of the original $2 billion budget. These overages led to a series of negotiations with the intention of restructuring the project’s existing financial structure and obtaining additional funding. On March 17, 2017, AES Gener completed the legal and financial restructuring of Alto Maipo, and through the Company’s 67% ownership interest in AES Gener, AES now has an effective 62% indirect economic interest in Alto Maipo. See Note 11—~~Equity~~ ~~for additional information regarding the restructuring.~~

Construction at the project is continuing and Alto Maipo is working to resolve the challenges described above. Alto Maipo is seeking a permanent replacement contractor to complete CNM’s work, and continues to negotiate with lenders and other parties. However, there can be no assurance that Alto Maipo will succeed in these efforts and if there are further delays or cost overruns, or if Alto Maipo is unable to reach an agreement with the non-recourse lenders, there is a risk that these lenders may seek to exercise remedies available as a result of the default noted above, or that Alto Maipo may not be able to meet its contractual or other obligations and may be unable to continue with the project. If any of the above occur, there could be a material impairment for the Company.

The carrying value of the long-lived assets and deferred tax assets of Alto Maipo as of September 30, 2017 was approximately $1.4 billion and $60 million, respectively. Through its 67% ownership interest in Gener, the Parent Company has invested approximately $360 million in Alto Maipo and has an additional equity commitment of $55 million to be funded as part of the March 2017 restructuring described above. Even though certain of the construction difficulties have not been formally resolved, construction costs continue to be capitalized as management believes the project is probable of completion. Management believes the carrying value of the long-lived asset group is recoverable and was not impaired as of September 30, 2017. In addition, management believes it is more likely than not that the deferred tax assets will be realized, they could be reduced if estimates of future taxable income are decreased.

Puerto Rico — ~~In September 2017, Puerto Rico was severely impacted by Hurricanes Irma and Maria, disrupting the operations of~~Earlier this year, AES Puerto Rico ~~and~~took certain measures to address identified liquidity challenges. On July 6, 2023, PREPA agreed to the release of funds in the escrow account guaranteeing AES ~~Ilumina.~~ Puerto Rico’s ~~infrastructure was severely damaged, including electric infrastructure~~obligations under the Power Purchase and ~~transmission lines. The extensive structural damage caused by hurricane winds and flooding is expected~~Operating Agreement (“PPOA”) in order to ~~take considerable time to repair. Although a more detailed assessment of~~provide additional liquidity for the ~~damage to its facilities is still ongoing, the Company sustained modest damage to its 24 MW AES Ilumina solar plant, resulting in an estimated $6 million loss, and minor damage to its 524 MW~~business. Additionally, AES Puerto Rico ~~thermal plants.~~

~~Our subsidiaries in Puerto Rico have long-term PPAs~~entered into a standstill and forbearance agreement with ~~state-owned PREPA. As a result~~its noteholders because of the ~~Hurricanes, PREPA has declared an event~~insufficiency of ~~Force Majeure. However, both units of~~funds to meet the principal and interest obligations on its Series A Bond Loans due and payable on June 1, 2023, and going forward. AES Puerto Rico continues to work with PREPA and ~~approximately 75% of AES Ilumina are available to generate electricity which, in accordance with the PPAs, will allow AES Puerto Rico to invoice capacity, even under Force Majeure.~~its noteholders on these liquidity challenges.

~~Starting prior to the hurricanes, PREPA has been facing economic~~Despite these challenges ~~that could impact the Company,~~ and ~~on July 2, 2017, filed for bankruptcy under Title III. As a result of the bankruptcy filing, AES Puerto Rico and~~

AES Ilumina’s non-recourse debt of $365 million and $36 million, respectively, are in default and have been classified as current as of September 30, 2017. In addition, the Company's receivable balances in Puerto Rico as of September 30, 2017 totaled $63 million, of which $30 million was overdue. After the filing of Title III protection, and up until the disruption caused by the hurricanes, AES in Puerto Rico was collecting the overdue amounts from PREPA in line with historic payment patterns.

~~Considering~~considering the information available as of the filing date, ~~Management~~management believes the carrying amount of our long-lived assets inat AES Puerto Rico of ~~$622~~$63 million is recoverable as of September 30, ~~2017.~~2023. However, it is reasonably possible that the estimate of undiscounted cash flows may change in the near term resulting in the need to write down our long-lived assets in Puerto Rico to fair value.

~~20.~~

36 | Notes to Condensed Consolidated Financial Statements—(Continued) | September 30, 2023 and 2022

21. SUBSEQUENT EVENTS

~~Kazakhstan Hydroelectric~~TEG and TEP — On October 3, 2023, AES Mexico Generation Holdings failed to comply with a covenant on its debt at TEG and TEP, resulting in a technical default. See Note 7—Debt for further information. TEG and TEP are reported in the Energy Infrastructure SBU reportable segment.

AES Clean Energy Development — On October 2, ~~2017,~~2023, the Company ~~transferred 100%~~completed the acquisition of ~~shares~~a construction stage solar and BESS project in ~~Shulbinsk HPP and Ust-Kamenogorsk HPP to the Republic of Kazakhstan in accordance with the termination of the concession agreement.~~Tulare County, CA. The Company ~~expects~~agreed to ~~record~~make total cash payments, including reimbursement of development and equipment costs, of approximately $253 million, a ~~loss on disposal~~portion of ~~at least $37 million~~which is contingent upon future milestones and price adjustments. The transaction is expected to be accounted for as an asset acquisition of variable interest entities that did not meet the definition of a business and will be reported in the ~~fourth quarter of 2017. See Note 16—Held-for-Sale Businesses and Dispositions~~ ~~for further discussion.~~Renewables SBU reportable segment.

~~Eletropaulo —~~ In September 2017, the majority of Eletropaulo’s shareholders approved the transfer of Eletropaulo’s shares to the Novo Mercado. However, shareholders holding approximately 3 million shares, representing 2.7% of the total preferred shares, have indicated their preference to exercise withdrawal rights, which allows them to redeem their shares and receive a cash payment at book value for tendering their shares to Eletropaulo. Eletropaulo has now received all third party approvals to migrate to the Novo Mercado.

37 | The migration will be submitted to the Eletropaulo Board for confirmation that the costs associated with the exercise of the withdrawal rights are not significant enough to prevent migration. Once confirmed and the preferred shares are converted into ordinary shares, AES ~~will no longer control Eletropaulo. Losing control will result in deconsolidation of Eletropaulo and the recording of an equity method investment for the remaining interest held in Eletropaulo. As of~~Corporation | September 30, 2017, Eletropaulo had cumulative translation losses attributable to AES of $452 million and pension losses attributable to AES in other comprehensive income of $243 million, both of which will be recognized in earnings if Eletropaulo is deconsolidated. See Note 15—~~Discontinued Operations~~ ~~for further discussion.~~2023 Form 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The condensed consolidated financial statements included in Item 1.—Financial Statements of this Form 10-Q and the discussions contained herein should be read in conjunction with our ~~2016~~2022 Form 10-K.

~~FORWARD-LOOKING INFORMATION~~Forward-Looking Information

The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations, that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. These statements include, but are not limited to, statements regarding management’s intents, beliefs, and current expectations and typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “forecast,” “target,” “will,” “would,” “intend,” “believe,” “project,” “estimate,” “plan,” and similar words. Forward-looking statements are not intended to be a guarantee of future results, but instead constitute current expectations based on reasonable assumptions. Factors that could cause or contribute to such differences include, but are not limited to, those described in Item 1A.—Risk Factorsof this Form 10-Q, Item 1A.—Risk Factors and Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations of our ~~2016~~2022 Form 10-K and subsequent filings with the SEC.

Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business.

Overview of Our Business—

We are a diversified power generation and utility company organized into the following ~~five market-oriented SBUs:~~ US ~~(United States);~~ ~~Andes~~ ~~(Chile, Colombia~~four SBUs, mainly organized by technology: Renewables (solar, wind, energy storage, and ~~Argentina);~~ ~~Brazil~~; ~~MCAC~~ ~~(Mexico, Central America~~hydro), Utilities (AES Indiana, AES Ohio, and AES El Salvador), Energy Infrastructure (natural gas, LNG, coal, pet coke, diesel, and oil), and New Energy Technologies (green hydrogen, Fluence, Uplight, and 5B). Our businesses in Chile, which have a mix of generation sources, including renewables, are also included within the Energy Infrastructure SBU, as the generation from all sources is pooled to service our existing PPAs. In our 2022 Form 10-K, the management reporting structure and the ~~Caribbean);~~Company’s reportable segments were mainly organized by geographic regions. In March 2023, we announced internal management changes as a part of our ongoing strategy to align our business to meet our customers’ needs and ~~Eurasia~~ ~~(Europe and Asia). During the third quarter~~deliver on our major strategic objectives. The results of ~~2017, the Europe and Asia SBUs were merged in order to leverage scale and~~our operations are now reported ~~as part of the Eurasia SBU.~~along our four newly formed technology-based SBUs. For additional information regarding our business, see Item 1.—Business of our ~~2016~~2022 Form 10-K.

~~Within our five SBUs, we~~We have two lines of ~~business. The~~business: generation and utilities. Our Renewables, Utilities and Energy Infrastructure SBUs participate in our first business line, is generation, ~~where~~in which we own and/or operate power plants to generate and sell power to customers, such as utilities, industrial users, and other intermediaries. ~~The~~Our Utilities SBU participates in our second business line, is utilities, ~~where~~in which we own and/or operate utilities to generate or purchase, distribute, transmit, and sell electricity to end-user customers in the residential, commercial, industrial, and governmental sectors within a defined service area. In certain circumstances, our utilities also generate and sell electricity on the wholesale market. Our New Energy Technologies SBU includes investments in new and innovative technologies to support leading-edge greener energy solutions.

Executive Summary

Compared with last year, third quarter net income decreased $155 million, from $446 million to $291 million. This decrease is the ~~results for~~result of lower contributions from LNG transactions versus 2022 at the ~~three~~Energy Infrastructure SBU, partially offset by favorable contributions at the Utilities, Renewables, and ~~nine months ended September 30, 2017 reflect~~New Energy Technologies SBUs.

Adjusted EBITDA, a non-GAAP measure, increased $59 million, from $931 million to $990 million, mainly driven by higher ~~margins resulting~~contributions at the Utilities SBU, favorable weather conditions and new businesses at the Renewables SBU, higher revenues under a PPA termination agreement at the Energy Infrastructure SBU, and lower losses from ~~increased tariffs, lower fixed costs, and revenue associated with a favorable opinion on~~affiliates at the ~~basis calculation for PIS and COFINS taxes from prior years at Eletropaulo. In addition, operating margins increased~~New Energy Technologies SBU due to ~~higher contract capacity and the commencement of the Los Mina combined cycle operations at the MCAC SBU.~~

~~Net cash provided~~improved margins on a new product line; partially offset by ~~operating activities decreased for the three months ended September 30, 2017compared to~~favorable LNG transactions in the prior year at the Energy Infrastructure SBU.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, increased $17 million, from $991 million to $1,008

38 | The AES Corporation | September 30, 2023 Form 10-Q

million primarily due to the drivers above, partially offset by lower realized tax attributes driven by fewer projects placed in service.

Compared with last year, third quarter diluted earnings per share from continuing operations decreased $0.27, from $0.59 to $0.32. This decrease is mainly driven by higher long-lived asset impairments in the current year and lower earnings at the Energy Infrastructure SBU mainly due to unrealized foreign currency losses and prior year favorable LNG transactions; partially offset by higher contributions at the Utilities SBU due to the deferral of power purchase costs, and favorable weather conditions and new businesses at the Renewables SBU.

Adjusted EPS, a non-GAAP measure, decreased $0.03 from $0.63 to $0.60, mainly driven by lower ~~collections of~~contributions from the Energy Infrastructure SBU, higher Parent Company interest, and a higher adjusted tax rate, partially offset by higher contributions at the Utilities SBU.

Compared with last year, net regulatory assets and current year sales at Eletropaulo, and the absence of Sul’s operating cash flow in 2017. In addition to the quarterly drivers, net cash provided by operating activities decreasedincome for the nine months ended September 30, ~~2017~~2023 decreased $20 million, from $481 million to $461 million. This decrease is the result of lower contributions from LNG transactions versus 2022 at the Energy Infrastructure SBU, partially offset by favorable contributions at the Renewables, Utilities, and New Energy Technologies SBUs.

Adjusted EBITDA, a non-GAAP measure, decreased $51 million, from $2,238 million to $2,187 million, mainly driven by favorable LNG transactions in the prior year and higher cost of sales at the Energy Infrastructure SBU; partially offset by favorable weather conditions and new businesses at the Renewables SBU, higher contributions at the Utilities SBU, higher revenues under a PPA termination agreement at the Energy Infrastructure SBU, and lower losses from affiliates at the New Energy Technologies SBU due to improved margins on a new product line.

Adjusted EBITDA with Tax Attributes, a non-GAAP measure, decreased $91 million, from $2,347 million to $2,256 million, primarily due to the ~~collection~~drivers above and lower realized tax attributes driven by fewer projects placed in service.

Compared with last year, diluted earnings per share from continuing operations for the nine months ended September 30, 2023 decreased $0.02, from $0.50 to $0.48. This decrease is mainly driven by favorable LNG transactions in the prior year, higher unrealized foreign currency losses and higher cost of ~~overdue receivables~~sales at ~~Maritza~~the Energy Infrastructure SBU; partially offset by lower long-lived asset impairments in ~~Bulgaria in 2016.~~the current year, higher contributions at the Utilities SBU due to the deferral of power purchase costs, and lower losses of affiliates at the New Energy Technologies SBU.

~~Overview~~Adjusted EPS, a non-GAAP measure, decreased $0.15 from $1.18 to $1.03, mainly driven by lower contributions from the Energy Infrastructure SBU, higher Parent Company interest, and a higher adjusted tax rate, partially offset by higher contributions at the Utilities SBU and lower losses of ~~Q3 2017 Results and Strategic Performance~~

~~Strategic Priorities~~ ~~— We continue to make progress towards meeting our strategic goals to maximize value for our shareholders.~~affiliates at the New Energy Technologies SBU.

39 | The AES Corporation | September 30, 2023 Form 10-Q





~~Leveraging Our Platforms~~
~~Focusing our growth in markets where we already operate and have a competitive advantage to realize attractive risk-adjusted returns~~

●	~~4,795 MW currently under construction~~
	○	~~Represents $8.7 billion in total capital expenditures~~
	○	~~Majority of AES’ $1.5 billion in equity already funded~~
	○	~~Expected to come on-line through 2021~~
●	~~Completed 122 MW conversion at DPP in the Dominican Republic~~
●	~~Completed $2.0 billion non-recourse financing for 1,384 MW Southland re-powering project in California~~
●	~~Will continue to advance select projects from our development pipeline~~



~~Reducing Complexity~~
~~Exiting businesses and markets where we do not have a competitive advantage, simplifying our portfolio and reducing risk~~

●	~~Announced the sale or shutdown of 3,737 MW of merchant coal-fired generation in Ohio and Kazakhstan~~



~~Performance Excellence~~
~~Striving to be the low-cost manager of a portfolio of assets and deriving synergies and scale from our businesses~~
●	~~Expect to achieve a total of $400 million in savings through 2020~~
	○	~~Includes overhead reductions, procurement efficiencies and operational improvements~~



~~Expanding Access to Capital~~
~~Optimizing risk-adjusted returns in existing businesses and growth projects~~
●	~~Building strategic partnerships at the project and business level with an aim to optimize our risk-adjusted returns in our business and growth projects~~
●	~~Adjust our global exposure to commodity, fuel, country and other macroeconomic risks~~



~~Allocating Capital in a Disciplined Manner~~
~~Maximizing risk-adjusted returns to our shareholders by investing our free cash flow to strengthen our credit and deliver attractive growth in cash flow and earnings~~
●	~~Prepaid $300 million and refinanced $1 billion of Parent Company bonds~~
●	~~Closed the acquisition of sPower, the largest independent solar developer in the United States~~

~~Q3 2017 Strategic Performance~~

~~Earnings Per Share and Free Cash Flow Results in Q3 2017 (in millions, except per share amounts):~~

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change % Change 2017 2016 $ Change % Change
Diluted earnings per share from continuing operations $ 0.23
$ 0.26
$ (0.03 ) -12 % $ 0.27
$ 0.31
$ (0.04 ) -13 %
Adjusted EPS (a non-GAAP measure) ⁽¹⁾
0.24
0.32
(0.08 ) -25 % 0.66
0.64
0.02
3 %
Net cash provided by operating activities 735
819
(84 ) -10 % 1,689
2,182
(493 ) -23 %
Free Cash Flow (a non-GAAP measure) ⁽¹⁾
601
665
(64 ) -10 % 1,253
1,709
(456 ) -27 %

~~_____________________________~~


⁽¹⁾						Non-GAAP measure. See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis—Non-GAAP Measures for reconciliation and definition.
(2) GWh sold in 2022.

~~Three Months Ended~~

40 | The AES Corporation | September 30, ~~2017~~2023 Form 10-Q

~~Diluted earnings per share from continuing operations decreased $0.03,~~Overview of Strategic Performance

AES is leading the industry's transition to clean energy by investing in renewables, utilities, and technology businesses.

•As of today, the Company’s backlog, which consists of projects with signed contracts, but which are not yet operational, is 13,138 MW, including 5,761 MW under construction.

•In year-to-date 2023, the Company completed the construction or ~~12%~~acquisition of 1,314 MW of wind, solar and energy storage and expects to ~~income~~complete a total of ~~$0.23. This was primarily driven~~3.5 GW by ~~lower margin at our Andes SBU, higher losses on extinguishment~~year-end 2023.

•In year-to-date 2023, the Company has signed 3,740 MW of ~~debt, higher income tax expense, unfavorable impact at Andes SBU from~~contracts for renewables.

•In September 2023, the ~~full recognition~~Company agreed to minority sell-downs of its businesses in the Dominican Republic and Panama, for a ~~non-trade receivable allowance and the write-off~~total of water rights related to a business development project that is no longer pursued, and losses due to damages caused by hurricanes Irma and Maria. These decreases were partially offset by prior year impairments at Buffalo Gap I, unrealized foreign currency transaction gains and higher margin at our MCAC SBU.

~~Adjusted EPS, a non-GAAP measure, decreased $0.08, or 25%, to $0.24, primarily driven by lower margin at~~

our Andes SBU, higher income tax expense, unfavorable impact at Andes SBU from the full recognition of a non-trade receivable allowance and the write-off water rights related to a business development project that is no longer pursued, and losses due to the damages caused by hurricanes Irma and Maria. These decreases were partially offset by higher margins at our MCAC SBU.

Net cash provided by operating activities decreased by $84 million, or 10%, to $735 million, primarily driven by lower collections of net regulatory assets and current year sales at Eletropaulo, delay in collections at Gener, and the absence of Sul’s operating cash flow in 2017. These decreases were partially offset by the timing of payments for energy purchases at Eletropaulo.

Free cash flow, a non-GAAP measure, decreased by $64 million, or 10%, to $601 million, primarily driven by an $84 million decrease in net cash provided by operating activities, which was partially offset by a decrease of $18$190 million in ~~maintenance (net of reinsurance proceeds) and non-recoverable environmental expenditures.~~asset sale proceeds.

~~Nine Months Ended September 30, 2017~~

Diluted earnings per share from continuing operations decreased $0.04, or 13%, to $0.27. This was primarily driven by impairments at DPL and Kazakhstan CHPs and hydroelectric plants, losses incurred for the disposition of the Kazakhstan CHPs and higher income tax expense. These decreases were partially offset by prior year impairments at DPL and Buffalo Gap I and II, higher margins at our MCAC, Eurasia and Brazil SBUs and the favorable impact of the YPF legal settlement at AES Uruguaiana in 2017.

Adjusted EPS, a non-GAAP measure, increased $0.02, or 3%, to $0.66, primarily driven by higher margins at our MCAC, Eurasia and Brazil SBUs, the favorable impact of the YPF legal settlement at AES Uruguaiana, which was partially offset by higher income tax expense.

Net cash provided by operating activities decreased by $493 million, or 23%, to $1,689 million, primarily driven by lower collections of net regulatory assets and current year sales at Eletropaulo, the 2016 collection of overdue receivables at Maritza, and the absence of Sul’s operating cash flow in 2017. These decreases were partially offset by the timing of payments for energy purchases at Eletropaulo.

Free cash flow, a non-GAAP measure, decreased by $456 million, or 27%, to $1,253 million, primarily driven by a $493 million decrease in net cash provided by operating activities (exclusive of lower service concession asset expenditures of $22 million), which was partially offset by a decrease of $59 million in maintenance (net of reinsurance proceeds) and non-recoverable environmental expenditures.

Review of Consolidated Results of Operations (Unaudited)


	Three Months Ended September 30,								Nine Months Ended September 30,
(in millions, except per share amounts)	2023		2022		$ change		% change		2023		2022		$ change		% change
Revenue:
Renewables SBU	$	708	$	532	$	176	33	%	$	1,744	$	1,407	$	337	24	%
Utilities SBU	880		994		(114)		-11	%	2,703		2,674		29		1	%
Energy Infrastructure SBU	1,861		2,126		(265)		-12	%	5,239		5,553		(314)		-6	%
New Energy Technologies SBU	—		—		—		—	%	75		2		73		NM
Corporate and Other	29		24		5		21	%	96		81		15		19	%
Eliminations	(44)		(49)		5		10	%	(157)		(160)		3		2	%
Total Revenue	3,434		3,627		(193)		-5	%	9,700		9,557		143		1	%
Operating Margin:
Renewables SBU	222		188		34		18	%	428		387		41		11	%
Utilities SBU	160		79		81		NM		351		280		71		25	%
Energy Infrastructure SBU	504		588		(84)		-14	%	1,120		1,211		(91)		-8	%
New Energy Technologies SBU	(2)		(2)		—		—	%	(8)		(5)		(3)		60	%
Corporate and Other	58		55		3		5	%	189		143		46		32	%
Eliminations	(24)		(16)		(8)		-50	%	(70)		(31)		(39)		NM
Total Operating Margin	918		892		26		3	%	2,010		1,985		25		1	%
General and administrative expenses	(64)		(51)		(13)		25	%	(191)		(149)		(42)		28	%
Interest expense	(326)		(276)		(50)		18	%	(966)		(813)		(153)		19	%
Interest income	144		100		44		44	%	398		270		128		47	%
Loss on extinguishment of debt	—		(1)		1		-100	%	(1)		(8)		7		-88	%
Other expense	(12)		(10)		(2)		20	%	(38)		(51)		13		-25	%
Other income	12		4		8		NM		36		80		(44)		-55	%
Gain (loss) on disposal and sale of business interests	—		1		(1)		-100	%	(4)		—		(4)		NM

Asset impairment expense	(158)		(50)		(108)		NM		(352)		(533)		181		-34	%
Foreign currency transaction gains (losses)	(100)		8		(108)		NM		(209)		(60)		(149)		NM

Income tax expense	(109)		(145)		36		-25	%	(179)		(186)		7		-4	%
Net equity in losses of affiliates	(14)		(26)		12		-46	%	(43)		(54)		11		-20	%



NET INCOME	291		446		(155)		-35	%	461		481		(20)		-4	%
Less: Income from continuing operations attributable to noncontrolling interests and redeemable stock of subsidiaries	(60)		(25)		(35)		NM		(118)		(124)		6		-5	%


NET INCOME ATTRIBUTABLE TO THE AES CORPORATION	$	231	$	421	$	(190)	-45	%	$	343	$	357	$	(14)	-4	%




Net cash provided by operating activities	$	1,122	$	784	$	338	43	%	$	2,309	$	1,649	$	660	40	%

Three Months Ended September 30, Nine Months Ended September 30,
(in millions, except per share amounts) 2017 2016 $ change % change 2017 2016 $ change % change
Revenue:
US SBU $ 852
$ 916
$ (64 ) -7 % $ 2,445
$ 2,582
$ (137 ) -5 %
Andes SBU 689
667
22
3 % 1,979
1,864
115
6 %
Brazil SBU 1,085
1,027
58
6 % 3,106
2,761
345
12 %
MCAC SBU 630
547
83
15 % 1,851
1,596
255
16 %
Eurasia SBU 380
386
(6 ) -2 % 1,204
1,249
(45 ) -4 %
Corporate and Other 9
6
3
50 % 29
8
21
NM
Intersegment eliminations (13 ) (7 ) (6 ) -86 % (20 ) (18 ) (2 ) -11 %
Total Revenue 3,632
3,542
90
3 % 10,594
10,042
552
5 %
Operating Margin:

US SBU 184
189
(5 ) -3 % 421
436
(15 ) -3 %
Andes SBU 151
203
(52 ) -26 % 452
466
(14 ) -3 %
Brazil SBU 107
53
54
NM
311
174
137
79 %
MCAC SBU 165
140
25
18 % 430
370
60
16 %
Eurasia SBU 102
95
7
7 % 343
308
35
11 %
Corporate and Other 2
7
(5 ) -71 % 17
11
6
55 %
Intersegment eliminations —
1
(1 ) 100 % —
6
(6 ) 100 %
Total Operating Margin 711
688
23
3 % 1,974
1,771
203
11 %
General and administrative expenses (52 ) (40 ) (12 ) 30 % (155 ) (135 ) (20 ) 15 %
Interest expense (353 ) (354 ) 1
— % (1,034 ) (1,086 ) 52
-5 %
Interest income 101
110
(9 ) -8 % 291
365
(74 ) -20 %
Loss on extinguishment of debt (49 ) (16 ) (33 ) NM
(44 ) (12 ) (32 ) NM
Other expense (47 ) (13 ) (34 ) NM
(95 ) (42 ) (53 ) NM
Other income 18
18
—
— % 105
43
62
NM
Gain (loss) on disposal and sale of businesses (1 ) —
(1 ) NM
(49 ) 30
(79 ) NM
Asset impairment expense (2 ) (79 ) 77
-97 % (260 ) (473 ) 213
-45 %
Foreign currency transaction gains (losses) 21
(20 ) 41
NM
13
(16 ) 29
NM
Income tax expense (110 ) (75 ) (35 ) 47 % (270 ) (165 ) (105 ) 64 %
Net equity in earnings of affiliates 24
11
13
NM
33
25
8
32 %
INCOME FROM CONTINUING OPERATIONS 261
230
31
13 % 509
305
204
67 %
Loss from operations of discontinued businesses, net of income tax benefit of $4 for the nine months ended September 30, 2016 —
(1 ) 1
-100 % —
(7 ) 7
-100 %
Net loss from disposal and impairments of discontinued businesses, net of income tax benefit of $401 for the nine months ended September 30, 2016 —
—
—
— % —
(382 ) 382
-100 %
NET INCOME (LOSS) 261
229
32
14 % 509
(84 ) 593
NM
Less: Net income attributable to noncontrolling interests and redeemable stock of subsidiaries (109 ) (54 ) (55 ) NM
(328 ) (97 ) (231 ) NM
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION $ 152
$ 175
$ (23 ) -13 % $ 181
$ (181 ) $ 362
NM
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:

Income from continuing operations, net of tax $ 152
$ 176
$ (24 ) -14 % $ 181
$ 208
$ (27 ) -13 %
Loss from discontinued operations, net of tax —
(1 ) 1
-100 % —
(389 ) 389
-100 %
NET INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION $ 152
$ 175
$ (23 ) -13 % $ 181
$ (181 ) $ 362
NM
Net cash provided by operating activities $ 735
$ 819
$ (84 ) -10 % $ 1,689
$ 2,182
$ (493 ) -23 %
DIVIDENDS DECLARED PER COMMON SHARE $ 0.12
$ 0.11
$ 0.01
9 % $ 0.24
$ 0.22
$ 0.02
9 %

Components of Revenue, Cost of Sales, and Operating Margin ~~and Operating Cash Flow~~ — Revenue includes revenue earned from the sale of energy from our utilities and the production and sale of energy from our generation plants, which are classified as regulated and non-regulated, respectively, on the Condensed Consolidated Statements of Operations. Revenue also includes the gains or losses on derivatives associated with the sale of electricity.

Cost of sales includes costs incurred directly by the businesses in the ordinary course of business. Examples include electricity and fuel purchases, operations and maintenance costs, depreciation and amortization ~~expense,~~expenses, bad debt expense and recoveries, and general administrative and support costs (including employee-related costs directly associated with the operations of the business). Cost of sales also includes the gains or losses on

41 | The AES Corporation | September 30, 2023 Form 10-Q

derivatives (including embedded derivatives other than foreign currency embedded derivatives) associated with the purchase of electricity or fuel.

Operating margin is defined as revenue less cost of sales.

Consolidated Revenue and Operating Margin

Three Months Ended September 30, 2023

~~Three~~Revenue

(in millions)

Consolidated Revenue— Revenue decreased $193 million, or 5%, for the three months ended September 30, ~~2017~~2023, compared to the three months ended September 30, 2022, driven by:

•$265 million at Energy Infrastructure driven by prior year favorable LNG transactions, lower regulated contract sales and prices, lower CO2 purchases passed through due to lower production, lower generation, and the impact of the depreciation of the Argentine peso; partially offset by realized and unrealized derivative gains, and higher revenues due to a PPA termination agreement; and

•$114 million at Utilities mainly driven by lower volumes as a result of lower demand due to unfavorable weather, and lower fuel and purchase rider revenues; partially offset by higher TDSIC rider and transmission revenues.

These unfavorable impacts were partially offset by an increase of:

•$176 million at Renewables mainly driven by higher spot sales at higher prices, new businesses operating in our portfolio, resulting in higher renewable energy generation, and the impact of the appreciation of the Colombian peso; partially offset by unrealized commodity derivative losses.

Operating Margin

(in millions)

Consolidated ~~Revenue~~Operating Margin— ~~Revenue~~Operating margin increased ~~$90~~$26 million, or 3%, for the three months ended September 30, ~~2017, as~~2023, compared to the three months ended September 30, ~~2016. This increase was~~2022, driven by:

~~The favorable FX impact of $37 million, primarily in Brazil of $31 million.~~

~~Excluding the FX impact mentioned above:~~

•$81 million at Utilities mainly driven by the deferral of power purchase costs in ~~MCAC primarily due to~~the current year, which were recognized in the prior year, associated with the ESP 4 approval, and a regulatory settlement in the prior year; and

42 | The AES Corporation | September 30, 2023 Form 10-Q

•$34 million at Renewables mainly driven by better hydrology, new businesses operating in our portfolio, resulting in higher ~~contract~~renewable energy ~~sales resulting from~~generation and the ~~commencement~~impact of the ~~combined cycle operations at Los Mina in June 2017, higher rates in the Dominican Republic, as well as higher pass through costs in El Salvador; and~~

~~$28 million in Brazil primarily due to the acquisition~~appreciation of the Alto Sertão II wind farm in Tietê, and the one time recognition of revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years as well as higher tariffs,Colombian peso; partially offset by unrealized derivative losses, higher fixed costs due to an accelerated growth plan, and lower ~~demand at Eletropaulo.~~contracted energy sales.

These ~~positive~~favorable impacts were partially offset by a decrease ~~of $64~~of:

•$84 million ~~in the U.S.~~at Energy Infrastructure mainly ~~due to lower wholesale volume and price, lower tariffs, and the unfavorable impact of mild weather at DPL.~~

~~Consolidated Operating Margin— Operating margin increased $23 million, or 3%, for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016. This increase was~~ driven ~~by:~~

~~The~~by prior year favorable ~~FX impact of $10 million, primarily in Andes and in Brazil.~~

~~Excluding the FX impact mentioned above:~~

$52 million in Brazil primarily due to the one time recognition of revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years, lower fixed cost, and higher tariffs,LNG transactions; partially offset by ~~lower demand at Eletropaulo, as well as the acquisition of the Alto Sertão II wind farm, partially offset by net unfavorable impact of volume and prices at Tietê; and~~

~~$25 million in MCAC primarily~~higher revenues due to ~~the commencement~~a PPA termination agreement, and realized and unrealized derivative gains as part of ~~the combined cycle operations at Los Mina in June 2017, and higher availability in the Dominican Republic.~~our commercial hedging strategy.

These positive impacts were partially offset by a decrease of $56 million in Andes,primarily at Gener, driven by lower availability and higher fixed costs due to major maintenance at Ventanas, the unfavorable impact of new regulation on emissions, and lower contract margin in the SING market, partially offset by start of operations of Cochrane Units I and II in July and October 2016, respectively.Nine Months Ended September 30, 2023

Revenue

(in millions)

~~Nine months ended September 30, 2017~~

Consolidated Revenue— Revenue increased ~~$552~~$143 million, or 5%1%, for the nine months ended September 30, ~~2017, as~~2023, compared to the nine months ended September 30, ~~2016. This increase was~~2022, driven by:

~~The favorable FX impact of $293~~•$337 million ~~primarily in Brazil of $312 million,~~at Renewables mainly driven by higher spot sales at higher prices and new projects placed into service; partially offset by the ~~unfavorable FX~~ impact of ~~$19~~the depreciation of the Colombian peso and unrealized derivative losses;

•$73 million at New Energy Technologies mainly driven by the sale of the Fallbrook project in ~~Eurasia.~~March 2023;

~~Excluding the FX impact mentioned above:~~

•$~~262~~29 million ~~in MCAC primarily~~at Utilities mainly driven by higher fuel and purchase rider revenues, higher TDSIC rider and transmission revenues, and higher demand due to higher LNG sales, higher contract rates, and higher contract energy sales resulting from the commencement of the combined cycle operations at Los Mina in June 2017, as well as higher pass through costsextreme heat in El Salvador; ~~and~~

~~$109 million in Andes primarily due to the start of commercial operations at Cochrane as well as higher availability in Argentina,~~ partially offset by lower ~~spot~~retail sales volume as a result of lower demand due to unfavorable weather at ~~Chivor.~~Indiana and Ohio.

These ~~positive~~favorable impacts were partially offset by a decrease ~~of $137~~of:

•$314 million ~~in the U.S. mainly~~at Energy Infrastructure primarily driven by prior year favorable LNG transactions, lower CO2 purchases passed through due to lower ~~tariffs,~~production, the impact of the depreciation of the Argentine peso, lower ~~wholesale volume and price,~~generation, and the ~~unfavorable impact~~recognition of ~~mild weather at DPL.~~unrealized losses due to a PPA termination agreement; partially offset by higher revenues due to a PPA termination agreement, and realized and unrealized derivative gains resulting mainly from new derivatives as part of our commercial hedging strategy.

Operating Margin

(in millions)

Consolidated Operating Margin— Operating margin increased ~~$203~~$25 million, or ~~11%~~1%, for the nine months ended

43 | The AES Corporation | September 30, ~~2017, as~~2023 Form 10-Q

September 30, 2023, compared to the nine months ended September 30, ~~2016. This~~2022, driven by:

•$71 million at Utilities mainly driven by the deferral of power purchase costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval, a regulatory settlement in the prior year, an increase ~~was driven by:~~

~~The favorable impact of FX of $42 million, primarily~~ in ~~Brazil of $29 million~~transmission and ~~in Andes of $15 million.~~

~~Excluding the FX impact mentioned above:~~

~~$108 million in Brazil primarily~~TDSIC rider revenues, and higher demand due to ~~higher tariffs, lower fixed costs, and the one time recognition of revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years,~~extreme heat in El Salvador; partially offset by ~~lower demand~~the impact of milder weather in Indiana and Ohio and higher fixed costs; and

•$41 million at ~~Eletropaulo;~~

~~$59 million~~Renewables mainly driven by better hydrology, new projects placed into service, and higher wind availability, resulting in ~~MCAC~~higher renewable energy generation; partially offset by unrealized derivative losses, and higher fixed costs due to ~~higher contract capacity and the commencement of the Los Mina combined cycle operations in June 2017 in the Dominican Republic as well as higher availability and lower maintenance in Mexico; and~~

~~$39 million in Eurasia primarily due to higher derivative valuation adjustments and higher capacity income in Northern Ireland.~~an accelerated growth plan.

These ~~positive~~favorable impacts were partially offset by a decrease ~~of $28~~of:

•$91 million ~~in Andes, primarily~~ at ~~Gener,~~Energy Infrastructure mainly driven by ~~the impact~~prior year favorable LNG transactions, higher cost of ~~new regulation on emissions,~~sales, lower ~~availability~~thermal dispatch substituted with renewable sources, and ~~higher fixed costs due to maintenance activities, and lower contract margin~~a prior year one-time revenue recognition driven by a reduction in ~~the SING market,~~a project's expected completion costs; partially offset by ~~start~~unrealized gains resulting mainly from new derivatives as part of ~~operations of Cochrane Units I~~our commercial hedging strategy, lower outages and IIlower depreciation expense due to impairments recognized in ~~July and October 2016, respectively, as well as higher availability at Argentina.~~the prior year.

See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—SBU Performance Analysis of this Form 10-Q for additional discussion and analysis of operating results for each SBU.

Consolidated Results of Operations — Other

General and administrative expenses

General and administrative expenses increased ~~$12~~$13 million, or ~~30%~~25%, to $64 million for the three months ended September 30, 2023, compared to $51 million for the three months ended September 30, 2022, primarily due to increased business development activity.

General and administrative expenses increased $42 million, or 28%, to $191 million for the nine months ended September 30, 2023 compared to $149 million for the nine months ended September 30, 2022, primarily due to increased business development activity and people costs.

Interest expense

Interest expense increased $50 million, or 18%, to $326 million for the three months ended September 30, 2023, compared to $276 million for the three months ended September 30, 2022. This increase is primarily due to new debt issued at the Renewables SBU and a higher weighted average interest rate and debt balance at the Parent Company; partially offset by higher capitalized interest at the Renewables SBU and the deferral of carrying costs at the Utilities SBU.

Interest expense increased $153 million, or 19%, to $966 million for the nine months ended September 30, 2023, compared to $813 million for the nine months ended September 30, 2022, primarily due to new debt issued at the Renewables and Utilities SBUs and a higher weighted average interest rate and debt balance at the Parent Company; partially offset by higher capitalized interest at the Renewables and Energy Infrastructure SBUs and the deferral of carrying costs at the Utilities SBU.

Interest capitalized during development and construction increased $97 million to $149 million for the three months ended September 30, 2023, compared to $52 million for the three months ended September 30, ~~2017, as~~2022, primarily due to more projects in development at the Renewables SBU and higher interest rates.

Interest capitalized during development and construction increased $254 million to $396 million for the nine months ended September 30, 2023, compared to ~~$40~~$142 million for the nine months ended September 30, 2022, primarily due to more projects in development at the Renewables and Energy Infrastructure SBUs and higher interest rates.

Interest income

Interest income increased $44 million, or 44%, to $144 million for the three months ended September 30, ~~2016,~~2023, compared to $100 million for the three months ended September 30, 2022, primarily due to higher average interest rates and short-term investments at the Energy Infrastructure and Renewables SBUs.

~~business development activity and~~Interest income increased ~~people costs.~~

~~General and administrative expenses increased $20~~$128 million, or ~~15%~~47%, to ~~$155~~$398 million for the nine months ended September 30, ~~2017, as~~2023, compared to ~~$135~~$270 million for the nine months ended September 30, ~~2016,~~2022, primarily due to higher average

44 | The AES Corporation | September 30, 2023 Form 10-Q

interest rates and short-term investments at the Energy Infrastructure and Renewables SBUs, partially offset by the prior year sales-type lease receivable adjustment at the Alamitos Energy Center.

Other income and expense

Other income increased ~~professional fees and business development activity.~~

~~Interest expense~~

~~Interest expense decreased $1~~$8 million to ~~$353~~$12 million for the three months ended September 30, ~~2017, as~~2023, compared to ~~$354~~$4 million for the three months ended September 30, ~~2016,~~2022, with no ~~significant~~material drivers.

~~Interest expense~~Other income decreased ~~$52~~$44 million, or 5%55%, to ~~$1,034~~$36 million for the nine months ended September 30, ~~2017, as~~2023, compared to ~~$1,086~~$80 million for the nine months ended September 30, ~~2016. This decrease was~~2022, primarily due to ~~a $61 million decrease~~the prior year gain on remeasurement of our existing investment in 5B, which is accounted for using the measurement alternative, and prior year insurance proceeds primarily associated with property damage at Eletropaulo attributable to lower debt balances, interest rates and regulatory liabilities, and a $23 million decrease at the Parent Company due to lower average debt balances. These decreases were partially offset by a $28 million increase at Cochrane primarily due to lower capitalized interest in 2017 as a result of the plant starting commercial operations in the second half of 2016.TermoAndes.

~~Interest income~~

~~Interest income decreased $9~~Other expense increased $2 million, or 8%20%, to ~~$101~~$12 million for the three months ended September 30, ~~2017, as~~2023, compared to ~~$110~~$10 million for the three months ended September 30, ~~2016. This decrease was primarily due to lower regulatory assets and interest rates at Eletropaulo.~~2022, with no material drivers.

~~Interest income~~Other expense decreased ~~$74~~$13 million, or ~~20%~~25%, to ~~$291~~$38 million for the nine months ended September 30, ~~2017, as~~2023, compared to ~~$365~~$51 million for the nine months ended September 30, ~~2016. This decrease was~~2022, primarily due to ~~lower regulatory assets~~the prior year recognition of an allowance on a sales-type receivable at AES Gilbert due to a fire incident in April 2022.

See Note 14—Other Income and ~~interest rates at Eletropaulo.~~Expense included in Item 1.—Financial Statements of this Form 10-Q for further information.

~~Loss on extinguishment of debt~~

~~Loss on extinguishment of debt~~Asset impairment expense

Asset impairment expense increased ~~$33~~$108 million to ~~$49~~$158 million for the three months ended September 30, ~~2017, as~~2023, compared to ~~$16~~$50 million for the three months ended September 30, ~~2016.~~2022. This increase was ~~primarily~~due to the $77 million and $59 million impairments at TEG and TEP in Mexico due to a ~~$36~~reduction in expected cash flows after expiration of the current PPAs, partially offset by higher impairments in the prior year of Amman East and IPP4 in Jordan due to the delay in closing the sale transaction.

Asset impairment expense decreased $181 million, ~~loss at the Parent Company resulting from the redemption and repurchase of senior notes in 2017.~~

~~Loss on extinguishment of debt increased $32 million~~or 34%, to ~~$44~~$352 million for the nine months ended September 30, ~~2017, as~~2023, compared to ~~$12~~$533 million for the nine months ended September 30, ~~2016.~~2022. This ~~increase~~decrease was primarily due to ~~losses~~the $468 million prior year impairment of ~~$92 million at the Parent Company,~~Maritza’s coal-fired plant due to Bulgaria’s commitment to cease electricity generation using coal as a ~~result of the redemption and repurchase of senior notes,~~fuel-source beyond 2038, partially offset by ~~a gain of $65~~the $137 million ~~at Alicura, as a result~~impairment associated with the commitment to accelerate the retirement of the ~~prepayment of non-recourse debt related to~~Norgener coal-fired plant in Chile, and the ~~construction of the San Nicolas Plant, in the current period.~~$77 million and $59 million impairments at TEG and TEP as discussed above.

See Note 7—~~Debt~~15—Asset Impairment Expense included in Item 1.—Financial Statements of this Form 10-Q for further information.

~~Other income~~Foreign currency transaction gains (losses)


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2023		2022		2023		2022
Argentina	$	(79)	$	(7)	$	(151)	$	(62)


Chile	(24)		11		(69)		—
Brazil	(1)		1		12		(6)





Other	4		3		(1)		8
Total (1)	$	(100)	$	8	$	(209)	$	(60)

(1)Includes gains of $15 million and ~~expense~~

~~Other income remained flat at $18~~gains of $33 million on foreign currency derivative contracts for the three months ended September 30, ~~2017, as compared to the three months ended September 30, 2016.~~

~~Other income increased $62~~2023 and 2022, respectively, and losses of $23 million ~~to $105~~and $16 million on foreign currency derivative contracts for the nine months ended September 30, 2017, as compared to $43 million for the nine months ended September 30, 2016. This increase was primarily due to the favorable settlement of legal proceeding at Uruguaiana related to YPF's breach of the parties’ gas supply agreement.

Other expense increased $34 million to $47 million for the three months ended September 30, 2017, as compared to $13 million for the three months ended September 30, 2016, primarily due to the write-off of water rights in the Andes SBU for projects that are no longer being pursued,2023 and ~~the recognition of a full allowance on a non-trade receivable in Andes SBU.~~

Other expense increased $53 million to $95 million for the nine months ended September 30, 2017, as compared to $42 million for the nine months ended September 30, 2016. This increase was primarily due to the loss on disposal of assets at DPL as a result of the decision made in 2017 to close the coal-fired and diesel-fired generating units at Stuart and Killen on or before June 1, 2018, higher assets write-off at Brazil SBU, the write-off of water rights in the Andes SBU for projects that are no longer being pursued, and the recognition of a full allowance on a non-trade receivable in Andes SBU.

~~See Note 13—Other Income and Expense~~ ~~included in Item 1.—Financial Statements~~ ~~of this Form 10-Q for further information.~~

~~Gain (loss) on disposal and sale of businesses~~

~~Loss on disposal and sale of businesses was $1 million for the three months ended September 30, 2017, with no loss in the comparative three months ended September 30, 2016.~~

Loss on disposal and sale of businesses was $49 million for the nine months ended September 30, 2017, as compared to a gain of $30 million for the nine months ended September 30, 2016. The 2017 negative impact was due to a $49 million loss on sale of Kazakhstan CHPs in 2017. The 2016 positive impact was primarily due to the $49 million gain on sale of DPLER, partially offset by the $20 million loss on deconsolidation of UK Wind in 2016.

~~See Note 16—Held-for-Sale Businesses and Dispositions~~ ~~included in Item 1.—Financial Statements~~ ~~of this Form 10-Q for further information.~~

~~Asset impairment expense~~

Asset impairment expense decreased $77 million, or 97%, to $2 million for the three months ended September 30, 2017, as compared to $79 million for the three months ended September 30, 2016. This was due to the prior year impairment at Buffalo Gap I, resulting from lower forecasted revenues due to decreases in wind production.

~~Asset impairment expense decreased $213 million, or 45%, to $260 million for the nine months ended~~ September 30, 2017, as compared to $473 million for the nine months ended September 30, 2016. This was primarily due to the prior year impairments at Buffalo Gap I, resulting from lower forecasted revenues due to decreases in wind production, DPL, resulting from lower forecasted revenues from the PJM capacity auction and higher anticipated environmental compliance costs, and Buffalo Gap II, due to a decline in forward power curves. These were partially offset by impairments in the current year at Kazakhstan, resulting from the sale of the CHPs and the expiration of the HPPs concession agreement on October 2017 and their classification as held-for-sale, and at DPL as a result of the decision to close the coal-fired and diesel-fired generating units at Stuart and Killen on or before June 1, 2018.

~~See Note 14—Asset Impairment Expense~~ ~~included in Item 1.—Financial Statements~~ ~~of this Form 10-Q for further information.~~

~~Foreign currency transaction gains (losses)~~

Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2017 2016 2017 2016
Corporate $ 4
$ (23 ) $ (1 ) $ (29 )
Argentina 9
8
4
9
Colombia (15 ) (3 ) (26 ) (4 )
United Kingdom —
1
(3 ) 10
Chile 9
(2 ) 4
(4 )
Bulgaria 5
—
1
12
(3 )
Philippines 4
—
10
8
Other 5
(2 ) 13
(3 )
Total ⁽¹⁾
$ 21
$ (20 ) $ 13
$ (16 )


⁽¹⁾	Foreign currency derivative contracts gains and losses had no net impact for the 3 months ended September 30, 2017. Includes $15 million of losses on foreign currency derivative contracts for the 3 months ended September 30, 2016, and $37 million of losses and $8 million of gains on foreign currency derivative contracts for the nine months ended September 30, 2017 and 2016, respectively.

The Company recognized net foreign currency transaction gains of $21 million for the three months ended September 30, 2017, primarily due to appreciation of the peso at Chile, and foreign currency derivatives related to government receivables at Argentina, partially offset foreign currency derivatives losses at Colombia due to a change in functional currency.2022, respectively.

The Company recognized net foreign currency transaction losses of ~~$20~~$100 million for the three months ended September 30, ~~2016,~~2023 primarily atdriven by the ~~Parent company due~~depreciation of the Argentine peso and by unrealized losses related to an intercompany loan denominated in the Colombian peso.

The Company recognized net foreign currency ~~swaps~~transaction losses of $209 million for the nine months ended September 30, 2023 primarily driven by the depreciation of the Argentine peso and ~~options,~~unrealized losses related to an intercompany loan denominated in the Colombian peso; partially offset by ~~remeasurement~~unrealized gains on ~~intercompany notes.~~debt in Brazil.

The Company recognized net foreign currency transaction gains of ~~$13~~$8 million for the ~~nine~~three months ended September 30, ~~2017,~~2022 primarily due to unrealized and realized derivative gains on foreign currency derivatives in South America due to the ~~amortization of frozen embedded derivatives at Philippines, and appreciation of the euro at Bulgaria,~~depreciating Colombian peso, partially offset by ~~foreign currency derivatives~~realized and unrealized losses ~~at Columbia~~ due to ~~change a in functional currency.~~the depreciating Argentine peso.

45 | The AES Corporation | September 30, 2023 Form 10-Q

The Company recognized net foreign currency transaction losses of ~~$16~~$60 million for the nine months ended September 30, ~~2016,~~2022 primarily ~~at the Parent company~~ due to ~~foreign currency swaps and options, partially offset by remeasurement gains on intercompany notes and remeasurement gains on intercompany debt at United Kingdom.~~

the depreciating Argentine peso.

Income tax expense

Income tax expense ~~increased $35~~decreased $36 million, or ~~47%~~25%, to ~~$110~~$109 million for the three months ended September 30, ~~2017,~~2023, compared to ~~$75~~$145 million for the three months ended September 30, ~~2016.~~2022. The Company’s effective tax rates were ~~32%~~26% and ~~26%~~24% for the three months ended September 30, ~~2017~~2023 and ~~2016,~~2022, respectively. ~~This net increase~~The current and prior year effective tax rates were benefited by inflationary and foreign currency impacts at certain Argentine businesses. Additionally, the current year effective tax rate was ~~due, in part, due~~impacted by the recognition of valuation allowance against certain Argentine deferred tax assets. See Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties of this Form 10-Q for further information on our exposure to foreign exchange rate risk related to the prior year resolution of an audit settlement at certain of our operating subsidiaries in the Dominican Republic as well as the prior year devaluation of the Peso impacting certain of our Mexican subsidiaries.Argentine peso.

Income tax expense ~~increased $105~~decreased $7 million, or ~~64%~~4%, to ~~$270~~$179 million for the nine months ended September 30, ~~2017,~~2023, compared to ~~$165~~$186 million for the nine months ended September 30, ~~2016.~~2022. The Company’s effective tax ~~rates were 36% and 37%~~rate was 26% for both the nine months ended September 30, ~~2017~~2023 and ~~2016,~~2022, respectively. ~~This net decrease~~The current and prior year effective tax rates were benefited by the aforementioned inflationary and foreign currency impacts. The current year effective tax rate was ~~principally due to~~also impacted by the ~~unfavorable impact~~recognition of ~~Chilean income~~valuation allowance, while the prior year effective tax ~~law reform enacted during~~rate was impacted by favorable LNG transactions at the ~~first quarter of 2016 and the 2016 asset impairments recorded at Buffalo Gap I, Buffalo Gap II, and DPL partially~~Energy Infrastructure SBU, offset by the ~~tax impacts~~impact of the ~~2017 appreciation~~asset impairment of the ~~Mexican Peso compared to the 2016 depreciation~~Maritza coal-fired plant. See Note 15—Asset Impairment Expense included in Item 1.—Financial Statements of this Form 10-Q for details of the ~~Peso.~~Maritza asset impairment.

Our effective tax rate reflects the tax effect of significant operations outside the U.S., which are generally taxed at ~~lower~~ rates different than the U.S. statutory rate of ~~35%~~21%. Furthermore, our foreign earnings may be subjected to incremental U.S. taxation under the GILTI rules. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate. ~~In certain periods, however, our effective tax rate may be higher than 35% due to various discrete tax expense impacts.~~

~~Net equity in earnings of affiliates~~

Net equity in ~~earnings~~losses of affiliates ~~increased $13~~

Net equity in losses of affiliates decreased $12 million, or 46%, to ~~$24~~$14 million for the three months ended September 30, ~~2017,~~2023, compared to ~~$11~~$26 million for the three months ended September 30, ~~2016.~~2022. This ~~increase~~decrease was primarily ~~due~~driven by lower losses from Fluence, mainly attributable to ~~the purchase of the sPower equity method investment in July 2017.~~improved margins on a new product line.

Net equity in ~~earnings~~losses of affiliates ~~increased $8~~decreased $11 million, or ~~32%~~20%, to ~~$33~~$43 million for the nine months ended September 30, ~~2017,~~2023, compared to ~~$25~~$54 million for the nine months ended September 30, ~~2016.~~2022. This ~~increase~~decrease was primarily driven by an increase in earnings from Mesa La Paz, primarily due the termination of unrealized derivatives due to ~~the purchase of the sPower equity method investment,~~a contract amendment, and by a decrease in losses from Fluence, mainly attributable to improved margins on a new product line and reduced shipping constraints and costs. This decrease in losses was partially offset by ~~a fixed asset impairment at Distributed Energy~~lower earnings from sPower, mainly due to lower earnings from renewable projects that came online.

See Note 6—Investments in ~~2017.~~and Advances to Affiliates included in Item 1.—Financial Statements of this Form 10-Q for further information.

Net income attributable to noncontrolling interests and redeemable stock of subsidiaries

Net income attributable to ~~NCI~~noncontrolling interests and redeemable stock of subsidiaries increased ~~$55~~$35 million to ~~$109~~$60 million for the three months ended September 30, ~~2017, as~~2023, compared to ~~$54~~$25 million for the three months ended September 30, ~~2016.~~2022. This increase was primarily due to:

•Lower allocation of losses to ~~asset impairment expense~~tax equity investors and increased costs associated with the growing business at ~~Buffalo Gap I~~the Renewables SBU; and

•Lower impairments in ~~2016 and higher operating margin~~Jordan at ~~Eletropaulo~~the Energy Infrastructure SBU.

These increases were partially offset by:

•Lower earnings in Panama due to the one time recognition of revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years, lower fixed cost, and higher tariffs, partially offset by lower demand, partially offset by lower operating margin at Tietê.drier hydrology.

Net income attributable to ~~NCI increased $231~~noncontrolling interests and redeemable stock of subsidiaries decreased $6 million, or 5%, to ~~$328~~$118 million for the nine months ended September 30, ~~2017, as~~2023, compared to ~~$97~~$124 million for the nine months ended September 30, ~~2016.~~2022. This ~~increase~~decrease was primarily due ~~to asset impairment~~to:

•Increased costs associated with growing business at ~~Buffalo Gap I~~the Renewables SBU; and II

46 | The AES Corporation | September 30, 2023 Form 10-Q

•Prior year one-time revenue recognition driven by a reduction in ~~2016, higher operating margin~~a project's expected completion costs at ~~Eletropaulo primarily~~the Energy Infrastructure SBU.

These decreases were partially offset by:

•Higher earnings from the Renewables SBU due to ~~higher tariffs, lower fixed costs,~~favorable weather conditions; and ~~the one time recognition~~

•Higher allocation of ~~revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years, partially offset by lower demand, and favorable YPF legal settlement~~earnings at ~~AES Uruguaiana.~~Southland Energy to noncontrolling interests.

~~Discontinued operations~~

Net loss from discontinued operations was $1 million and $389 million for the three and nine months ended September 30, 2016, respectively, due to the operations from Sul being classified as discontinued operations starting in the second quarter of 2016. The sale of Sul closed in the fourth quarter of 2016. See Note 15—~~Discontinued Operations~~ ~~included in Item 1.—Financial Statements~~ ~~of this Form 10-Q for further information regarding the Sul discontinued operations.~~

Net income ~~(loss)~~ attributable to The AES Corporation

Net income attributable to The AES Corporation decreased ~~$23~~$190 million, or 45%, to ~~$152~~$231 million for the three months ended September 30, ~~2017, as~~2023, compared to ~~$175~~$421 million for the three months ended September 30, ~~2016. Key drivers of~~2022. This decrease was primarily due to:

•Higher long-lived asset impairments in the ~~decrease were:~~current year;

•Higher unrealized foreign currency losses at the Energy Infrastructure SBU; and

•Lower ~~margin at our Andes SBU;~~

~~Higher loss on extinguishment debt;~~

~~Higher income tax expense;~~

~~Unfavorable impact at Andes SBU~~earnings from the ~~full recognition of a non-trade receivable allowance and the write-off of water rights to a business development project that is no longer pursued; and~~

~~Losses~~Energy Infrastructure SBU due to ~~damages caused by hurricanes Irma and Maria.~~prior year favorable LNG transactions.

These decreases were partially offset by:

~~Prior~~•Higher earnings from the Utilities SBU due to the deferral of previously recognized power purchase costs and a prior year ~~impairments at Buffalo Gap I;~~charge resulting from a regulatory settlement; and

~~Unrealized foreign currency transaction gains;~~•Higher earnings from the Renewables SBU due to favorable weather conditions and

~~Higher margin at~~ new businesses operating in our ~~MCAC SBU.~~portfolio.

Net income attributable to The AES Corporation ~~was $181~~decreased $14 million, or 4%, to $343 million for the nine months ended September 30, ~~2017,~~2023, compared to ~~a net loss attributable to The AES Corporation of $181~~$357 million for the nine months ended September 30, ~~2016. The $362 million positive impact~~2022. This decrease was primarily ~~driven by~~due to:

•Higher unrealized foreign currency losses at the ~~following increases:~~Energy Infrastructure SBU;

~~Prior~~•Lower earnings from the Energy Infrastructure SBU due to prior year ~~loss from discontinued operations~~favorable LNG transactions, lower thermal dispatch, and higher cost of ~~$389 million as~~sales; and

•Increase in interest expense due to higher interest rates and new debt issued at the Energy Infrastructure SBU and a ~~result of the sale of Sul (See Note 15. Discontinued Operations included in Item 1.—~~ ~~Financial Statements~~ ~~of this Form 10-Q for further information.)~~

~~Prior year impairments at DPL and Buffalo Gap I and II;~~

~~Higher margins at our MCAC, Eurasia and Brazil SBUs in the current year; and~~

~~The favorable impact of the YPF legal settlement at AES Uruguaiana.~~higher Parent Company weighted average interest rate.

These ~~increases~~decreases were partially offset by:

~~Current~~•Lower long-lived asset impairments in the current year;

•Increase in interest income due to higher average interest rates and short term investments at the Energy Infrastructure and Renewables SBUs;

•Higher earnings from the Utilities SBU due to the deferral of previously recognized power purchase costs and a prior year ~~impairments~~charge resulting from a regulatory settlement; and

•Lower losses from affiliates at ~~Kazakhstan CHPs and hydroelectric plants, and DPL;~~the New Energy Technologies SBU.

~~Higher income tax expense; and~~

~~Current year loss on sale of Kazakhstan CHPs.~~

SBU Performance Analysis

Non-GAAP Measures

EBITDA, Adjusted ~~Operating Margin,~~EBITDA, Adjusted EBITDA with Tax Attributes, Adjusted PTC, and Adjusted EPS ~~and Consolidated Free Cash Flow (“Free Cash Flow”)~~ are non-GAAP supplemental measures that are used by management and external users of our condensed consolidated financial statements such as investors, industry analysts, and lenders.

During the first quarter of 2023, management began assessing operational performance and making resource allocation decisions using Adjusted EBITDA. Therefore, the Company uses Adjusted EBITDA as its primary segment performance measure. EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes are new non-GAAP supplemental measures reported beginning in the first quarter of 2023.

47 | The ~~Adjusted Operating Margin, Adjusted PTC, and Consolidated Free Cash Flow by SBU for the three and nine months ended~~AES Corporation | September 30, ~~2017 and September 30, 2016, are shown below. The percentages represent the contribution by each SBU to the gross metric, excluding Corporate.~~2023 Form 10-Q

~~For the year beginning January 1, 2017, the Company changed the definition of~~EBITDA, Adjusted ~~PTC~~EBITDA and Adjusted ~~EPS~~EBITDA with Tax Attributes

We define EBITDA as earnings before interest income and expense, taxes, depreciation, and amortization. We define Adjusted EBITDA as EBITDA excluding the impact of NCI and interest, taxes, depreciation, and amortization of our equity affiliates, adding back interest income recognized under service concession arrangements, and excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to ~~exclude~~(a) unrealized gains or losses related to derivative transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, losses, benefits and costs associated ~~benefits~~with dispositions and acquisitions of business interests, including early plant closures, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; (e) gains, losses and costs due to ~~acquisitions, dispositions,~~the early retirement of debt; and (f) net gains at Angamos, one of our businesses in the Energy Infrastructure SBU, associated with the early ~~plant closures; including~~contract terminations with Minera Escondida and Minera Spence.

In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted EBITDA includes the other components of our Consolidated Statement of Operations, such as general and administrative expenses in Corporate and Other as well as business development costs, other expense and other income,realized foreign currency transaction gains and losses, and net equity in earnings of affiliates.

We further define Adjusted EBITDA with Tax Attributes as Adjusted EBITDA, adding back the pre-tax effect of Production Tax Credits (“PTCs”), Investment Tax Credits (“ITCs”), and depreciation tax ~~impact of decisions made at the time of sale~~expense allocated to ~~repatriate sales proceeds.~~tax equity investors.

The GAAP measure most comparable to EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes is Net income. We believe ~~excluding these benefits~~that EBITDA, Adjusted EBITDA, and ~~costs~~Adjusted EBITDA with Tax Attributes better reflect the underlying business performance ~~by removing~~of the Company. Adjusted EBITDA is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Factors in this determination include the variability ~~caused by~~due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, strategic decisions to dispose of or acquire business interests or ~~close plants early. The Company has also reflected these changes in~~retire debt, the ~~comparative periods ending September 30, 2016.~~

~~Adjusted Operating Margin~~

~~Operating Margin is defined as revenue less cost~~non-recurring nature of ~~sales. We define Adjusted Operating Margin as Operating Margin, adjusted for~~ the impact of ~~NCI, excluding unrealized gains~~the early contract terminations at Angamos, and the variability of allocations of earnings to tax equity investors, which affect results in a given period or ~~losses related to derivative transactions.~~

~~The GAAP measure most comparable to Adjusted Operating Margin is Operating Margin. We believe that Adjusted Operating Margin better reflects~~periods. In addition, each of these metrics represent the ~~underlying~~ business performance of the ~~Company. Factors~~Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in ~~this determination include the impact of NCI, where AES consolidates the results of a subsidiary that is not wholly owned by~~which the Company ~~as well as~~operates. Given its large number of businesses and overall complexity, the ~~variability due to unrealized derivatives gains or losses.~~Company concluded that Adjusted ~~Operating Margin~~EBITDA is a more transparent measure than Net income that better assists investors in determining which businesses have the greatest impact on the Company’s results.

EBITDA, Adjusted EBITDA, and Adjusted EBITDA with Tax Attributes should not be construed as ~~an alternative~~alternatives to ~~Operating Margin,~~Net income, which is determined in accordance with GAAP.


	Three Months Ended September 30,				Nine Months Ended September 30,
Reconciliation of Adjusted EBITDA and Adjusted EBITDA with Tax Attributes (in millions)	2023		2022		2023		2022
Net income	$	291	$	446	$	461	$	481
Income tax expense	109		145		179		186
Interest expense	326		276		966		813
Interest income	(144)		(100)		(398)		(270)
Depreciation and amortization	286		266		836		800
EBITDA	$	868	$	1,033	$	2,044	$	2,010

Less: Adjustment for noncontrolling interests and redeemable stock of subsidiaries (1)	(183)		(174)		(508)		(486)
Less: Income tax expense (benefit), interest expense (income) and depreciation and amortization from equity affiliates	27		36		93		93
Interest income recognized under service concession arrangements	18		19		54		58
Unrealized derivative and equity securities losses (gains)	10		(8)		3		—
Unrealized foreign currency losses	97		3		161		23
Disposition/acquisition losses	8		4		21		36
Impairment losses	145		17		318		497
Loss on extinguishment of debt	—		1		1		7

Adjusted EBITDA (1)	$	990	$	931	$	2,187	$	2,238
Tax attributes allocated to tax equity investors	18		60		69		109
Adjusted EBITDA with Tax Attributes (2)	$	1,008	$	991	$	2,256	$	2,347

Reconciliation of Adjusted Operating Margin (in millions) Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Operating Margin $ 711
$ 688
$ 1,974
$ 1,771
Noncontrolling interests adjustment (222 ) (187 ) (630 ) (502 )
Derivatives adjustment (6 ) (10 ) (16 ) 4
Total Adjusted Operating Margin $ 483
$ 491
$ 1,328
$ 1,273

48 | The AES Corporation | September 30, 2023 Form 10-Q

(1) The allocation of earnings to tax equity investors from both consolidated entities and equity affiliates is removed from Adjusted EBITDA.

(2) Adjusted EBITDA with Tax Attributes includes the impact of the share of the ITCs, PTCs, and depreciation expense allocated to tax equity investors under the HLBV accounting method and recognized as Net loss attributable to noncontrolling interests and redeemable stock of subsidiaries on the Condensed Consolidated Statements of Operations. All of the tax attributes are related to the Renewables SBU.

Adjusted PTC

We define Adjusted PTC as ~~pretax~~pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative ~~transactions;~~transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, or losses, ~~and associated~~ benefits, and costs ~~due to~~associated with dispositions and acquisitions of business interests, including early plant closures, and ~~the tax impact from the repatriation~~gains and losses recognized at commencement of ~~sales proceeds;~~sales-type leases; (d) losses due to impairments; ~~and~~ (e) gains, losses, and costs due to the early retirement of ~~debt.~~debt; and (f) net gains at Angamos, one of our businesses in the Energy Infrastructure SBU, associated with the early contract terminations with Minera Escondida and Minera Spence. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities.

Adjusted PTC reflects the impact of NCI and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in Operating Margin, Adjusted PTC includes the other components of our ~~income statement,~~Consolidated Statement of Operations, such as general and administrative expenses in ~~the corporate segment,~~Corporate and Other as

49 | The AES Corporation | September 30, 2023 Form 10-Q

well as business development costs, interest expense and interest income,other expense and other income,realized foreign currency transaction gains and losses, and net equity in earnings of affiliates.

The GAAP measure most comparable to Adjusted PTC is ~~income~~Income from continuing operations attributable to The AES Corporation. We believe that Adjusted PTC better reflects the underlying business performance of the Company and is ~~the most~~a relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, ~~and~~ strategic decisions to dispose of or acquire business interests or retire debt, and the non-recurring nature of the impact of the early contract terminations at Angamos, which affect results in a given period or periods. In addition, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure than Income from continuing operations attributable to The AES Corporation that better assists investors in determining which businesses have the greatest impact on the Company’s results.

Adjusted PTC should not be construed as an alternative to ~~income~~Income from continuing operations attributable to The AES Corporation, which is determined in accordance with GAAP.


	Three Months Ended September 30,				Nine Months Ended September 30,
Reconciliation of Adjusted PTC (in millions)	2023		2022		2023		2022
Income from continuing operations, net of tax, attributable to The AES Corporation	$	231	$	421	$	343	$	357
Income tax expense from continuing operations attributable to The AES Corporation	101		128		136		149
Pre-tax contribution	332		549		479		506
Unrealized derivative and equity securities losses (gains)	9		(8)		3		(2)
Unrealized foreign currency losses	96		3		160		23
Disposition/acquisition losses	8		4		21		36
Impairment losses	145		17		318		497
Loss on extinguishment of debt	3		4		7		20


Adjusted PTC	$	593	$	569	$	988	$	1,080

50 | The AES Corporation | September 30, 2023 Form 10-Q

Reconciliation of Adjusted PTC (in millions) Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Income from continuing operations, net of tax, attributable to The AES Corporation $ 152
$ 176
$ 181
$ 208
Income tax expense attributable to The AES Corporation 71
47
144
66
Pretax contribution 223
223
325
274
Unrealized derivative losses (gains) (8 ) 5
(7 ) 1
Unrealized foreign currency transaction losses (gains) (21 ) 3
(54 ) 12
Disposition/acquisition losses (gains) 1
(3 ) 107
(5 )
Impairment expense 2
24
264
309
Losses on extinguishment of debt 48
20
43
26
Total Adjusted PTC $ 245
$ 272
$ 678
$ 617
7740

Adjusted EPS

We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of both consolidated entities and entities accounted for under the equity method due to (a) unrealized gains or losses related to derivative ~~transactions;~~transactions and equity securities; (b) unrealized foreign currency gains or losses; (c) gains, or losses, ~~and associated~~ benefits and costs ~~due to~~associated with dispositions and acquisitions of business interests, including early plant closures, and the tax impact from the repatriation of sales ~~proceeds;~~proceeds, and gains and losses recognized at commencement of sales-type leases; (d) losses due to impairments; ~~and~~ (e) gains, losses and costs due to the early retirement of ~~debt.~~debt; (f) net gains at Angamos, one of our businesses in the Energy Infrastructure SBU, associated with the early contract terminations with Minera Escondida and Minera Spence; and (g) tax benefit or expense related to the enactment effects of 2017 U.S. tax law reform and related regulations and any subsequent period adjustments related to enactment effects, including the 2021 tax benefit on reversal of uncertain tax positions effectively settled upon the closure of the Company's U.S. tax return exam.

The GAAP measure most comparable to Adjusted EPS is ~~diluted~~Diluted earnings per share from continuing ~~operations.~~operations. We believe 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 unrealized gains or losses related to derivative transactions or equity securities remeasurement, unrealized foreign currency gains or losses, losses due to impairments, ~~and~~ strategic decisions to dispose of or acquire business interests or retire debt, the one-time impact of the 2017 U.S. tax law reform and subsequent period adjustments related to enactment effects, and the non-recurring nature of the impact of the early contract terminations at Angamos, which affect results in a given period or periods.

Adjusted EPS should not be construed as an alternative to ~~diluted~~Diluted earnings per share from continuing operations, which is determined in accordance with GAAP.

Reconciliation of Adjusted EPS Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Diluted earnings per share from continuing operations $ 0.23
$ 0.26
$ 0.27
$ 0.31

Unrealized derivative gains (0.01 ) —
(0.01 ) —

Unrealized foreign currency transaction losses (gains) (0.03 ) 0.01
(0.07 ) 0.01

Disposition/acquisition losses (gains) —
—
0.16
⁽¹⁾
—
⁽²⁾
Impairment expense —
0.03
⁽³⁾
0.40
⁽⁴⁾
0.47
⁽⁵⁾
Losses on extinguishment of debt 0.07
⁽⁶⁾
0.04
⁽⁷⁾
0.06
⁽⁸⁾
0.05
⁽⁹⁾
Less: Net income tax benefit (0.02 )
⁽¹⁰⁾
(0.02 ) (0.15 )
⁽¹¹⁾
(0.20 )
⁽¹¹⁾
Adjusted EPS $ 0.24
$ 0.32
$ 0.66
$ 0.64


	Three Months Ended September 30,						Nine Months Ended September 30,
Reconciliation of Adjusted EPS	2023			2022			2023			2022
Diluted earnings per share from continuing operations	$	0.32		$	0.59		$	0.48		$	0.50
Unrealized derivative and equity securities losses (gains)	0.01			(0.01)			—		(1)	—
Unrealized foreign currency losses	0.14		(2)	—			0.22		(3)	0.03		(4)
Disposition/acquisition losses	0.01			0.01			0.03			0.05		(5)
Impairment losses	0.21		(6)	0.02		(7)	0.45		(8)	0.70		(9)
Loss on extinguishment of debt	—			0.01			0.01			0.03



Less: Net income tax expense (benefit)	(0.09)		(10)	0.01			(0.16)		(11)	(0.13)		(12)
Adjusted EPS	$	0.60		$	0.63		$	1.03		$	1.18

_____________________________


⁽¹⁾	Amount primarily relates to loss on sale of Kazakhstan CHPs of $48 million, or $0.07 per share, realized derivative losses associated with the sale of Sul of $38 million, or $0.06 per share; costs associated with early plant closure of DPL of $20 million, or $0.03 per share.


⁽²⁾	~~Net impact of zero relates to the gain on sale of DPLER of $22 million, or $0.03 per share; offset by the loss on deconsolidation of UK Wind of $20 million, or $0.03 per share.~~


⁽³⁾	~~Amount primarily relates to the asset impairment at Buffalo Gap I of $78 million ($23 million, or $0.03 per share, net of NCI).~~


⁽⁴⁾	Amount primarily relates to asset impairment at Kazakhstan hydroelectric plants of $92 million, or $0.14 per share, at Kazakhstan CHPs of $94 million, or $0.14 per share, and DPL of $66 million, or $0.10 per share.


⁽⁵⁾	Amount primarily relates to asset impairments at DPL of $235 million, or $0.36 per share; $159 million at Buffalo Gap II ($49 million, or $0.07 per share, net of NCI); and $78 million at Buffalo Gap I ($23 million, or $0.03 per share, net of NCI).


⁽⁶⁾	~~Amount primarily relates to the losses on early retirement of debt at the Parent Company of $38 million, or $0.06 per share~~


⁽⁷⁾	Amount primarily relates to losses on early retirement of debt at the Parent Company of $17 million, or $0.02 per share; and an adjustment of $5 million, or $0.01 per share to record the DP&L redeemable preferred stock at its redemption value.


⁽⁸⁾	Amount primarily relates to losses on early retirement of debt at the Parent Company of $92 million, or $0.14 per share, partially offset by the the gain on early retirement of debt at Alicura of $65 million, or $0.10 per share.


⁽⁹⁾	Amount primarily relates to losses on early retirement of debt at the Parent Company of $19 million, or $0.03 per share; and an adjustment of $5 million, or $0.01 per share, to record the DP&L redeemable preferred stock at its redemption value.


⁽¹⁰⁾	~~Amount primarily relates to the income tax benefit associated with losses on early retirement of debt of $16 million, or $0.02 per share in the three months ended September 30, 2017.~~


⁽¹¹⁾	Amount primarily relates to the income tax benefit associated with asset impairment losses of $82 million, or $0.12 per share and $123 million, or $0.19 per share in the nine months ended September 30, 2017 and 2016, respectively.

(1)Amount primarily relates to unrealized derivative losses due to the termination of a PPA of $72 million, or $0.10 per share and unrealized derivative losses at AES Clean Energy of $20 million, or $0.03 per share, offset by unrealized derivative gains at the Energy Infrastructure SBU of $108 million, or $0.15 per share.

~~Free Cash Flow~~

We define Free Cash Flow as net cash from operating activities (adjusted for service concession asset capital expenditures) less maintenance capital expenditures (including non-recoverable environmental capital expenditures), net(2)Amount primarily relates to unrealized foreign currency losses mainly associated with the devaluation of ~~reinsurance proceeds from third parties.~~

~~We also exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual~~long-term receivables denominated in Argentine pesos of $60 million, or ~~other mechanisms. An example~~$0.08 per share, unrealized foreign currency losses at AES Andes of ~~recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1.—US SBU—IPL—Environmental Matters~~ ~~included in our 2016 Form 10-K for details of these investments.~~

The GAAP measure most comparable to Free Cash Flow is net cash provided by operating activities. We believe that Free Cash Flow is a useful measure for evaluating our financial condition because it represents the amount of cash generated by the business after the funding of maintenance capital expenditures that may be available for investing in growth opportunities$21 million, or ~~for repaying debt.~~

The presentation of Free Cash Flow has material limitations. Free Cash Flow should not be construed as an alternative to net cash from operating activities, which is determined in accordance with GAAP. Free Cash Flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements$0.03 per share, and ~~dividend payments. Our definition of Free Cash Flow may not be comparable to similarly titled measures presented by other companies.~~unrealized foreign currency losses on

51 | The AES Corporation | September 30, 2023 Form 10-Q

Calculation of Free Cash Flow (in millions) Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Net Cash provided by operating activities $ 735
$ 819
$ 1,689
$ 2,182
Add: capital expenditures related to service concession assets ⁽¹⁾
3
1
5
27
Less: maintenance capital expenditures, net of reinsurance proceeds (129 ) (144 ) (423 ) (464 )
Less: non-recoverable environmental capital expenditures ⁽²⁾
(8 ) (11 ) (18 ) (36 )
Free Cash Flow $ 601
$ 665
$ 1,253
$ 1,709
debt in Brazil of $10 million, or $0.01 per share.

~~_____________________________~~


⁽¹⁾	~~Service concession asset expenditures are included in net cash provided by operating activities, but are excluded from the free cash flow non-GAAP metric.~~


⁽²⁾	Excludes IPL's recoverable environmental capital expenditures of $10 million and $32 million for the three months ended September 30, 2017 and 2016, as well as, $39 million and $162 million for the nine months ended September 30, 2017 and 2016, respectively.

(3)Amount primarily relates to unrealized foreign currency losses mainly associated with the devaluation of long-term receivables denominated in Argentine pesos of $109 million, or $0.15 per share, and unrealized foreign currency losses at AES Andes of $54 million, or $0.08 per share.

(4)Amount primarily relates to unrealized foreign currency losses mainly associated with the devaluation of long-term receivables denominated in Argentine pesos of $19 million, or $0.03 per share.

(5)Amount primarily relates to the recognition of an allowance on the AES Gilbert sales-type lease receivable as a cost of disposition of a business interest of $20 million, or $0.03 per share.

(6)Amount primarily relates to asset impairments at TEG and TEP of $76 million and $58 million, respectively, or $0.19 per share.

(7)Amount primarily relates to asset impairment at Jordan of $19 million, or $0.03 per share.

(8)Amount primarily relates to asset impairments at the Norgener coal-fired plant in Chile of $136 million, or $0.19 per share, at TEG and TEP of $76 million and $58 million, respectively, or $0.19 per share, the GAF Projects at AES Renewable Holdings of $18 million, or $0.03 per share, and at Jordan of $16 million, or $0.02 per share.

(9)Amount primarily relates to asset impairment at Maritza of $468 million, or $0.66 per share, and at Jordan of $19 million, or $0.03 per share.

(10)Amount primarily relates to income tax benefits associated with the asset impairments at TEG and TEP of $34 million, or $0.05 per share and income tax benefits associated with unrealized foreign currency losses at AES Andes of $6 million, or $0.01 per share.

US(11)Amount primarily relates to income tax benefits associated with the asset impairments at the Norgener coal fired plant in Chile of $35 million, or $0.05 per share and at TEG and TEP of $34 million, or $0.05 per share, income tax benefits associated with the recognition of unrealized losses due to the termination of a PPA of $18 million, or $0.02 per share, and income tax benefits associated with unrealized foreign currency losses at AES Andes of $14 million, or $0.02 per share.

(12)Amount primarily relates to income tax benefits associated with the impairment at Maritza of $73 million, or $0.10 per share, and at Jordan of $8 million, or $0.01 per share.

Renewables SBU

The following table summarizes Operating Margin, Adjusted ~~Operating Margin,~~EBITDA, and Adjusted ~~PTC, and Free Cash Flow~~EBITDA with Tax Attributes (in millions) for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change % Change 2017 2016 $ Change % Change
Operating Margin $ 184
$ 189
$ (5 ) -3 % $ 421
$ 436
$ (15 ) -3 %
Noncontrolling Interests Adjustment ⁽¹⁾
(23 ) (26 ) (56 ) (59 )
Derivatives Adjustment (3 ) 1
—
5

Adjusted Operating Margin $ 158
$ 164
$ (6 ) -4 % $ 365
$ 382
$ (17 ) -4 %
Adjusted PTC $ 129
$ 114
$ 15
13 % $ 240
$ 257
$ (17 ) -7 %
Free Cash Flow $ 211
$ 246
$ (35 ) -14 % $ 407
$ 512
$ (105 ) -21 %
Free Cash Flow Attributable to NCI $ 18
$ 27
$ (9 ) -33 % $ 32
$ 43
$ (11 ) -26 %


	Three Months Ended September 30,								Nine Months Ended September 30,
	2023		2022		$ Change		% Change		2023		2022		$ Change		% Change
Operating Margin	$	222	$	188	$	34	18	%	$	428	$	387	$	41	11	%

Adjusted EBITDA (1)	267		195		72		37	%	557		476		81		17	%
Adjusted EBITDA with Tax Attributes (1)	285		255		30		12	%	626		585		41		7	%

_____________________________


⁽¹⁾ (1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition.	~~See Item 1.—Business~~ ~~included in our 2016 Form 10-K for the respective ownership interest for key businesses.~~

Operating Margin for the three months ended September 30, ~~2017, decreased by $5~~2023 increased $34 million ~~or 3%, which was~~ driven primarily by better hydrology, new businesses operating in our portfolio, resulting in higher renewable energy generation, and the ~~following (in millions):~~

IPL
Lower retail margin primarily due to weather $ (10 )
Other (3 )
Total IPL Decrease (13 )
US Generation
Warrior Run primarily due to higher availability and lower maintenance cost due to major outages in 2016 6
Other 4
Total US Generation Increase 10
Other Business Drivers (2 )
Total US SBU Operating Margin Decrease $ (5 )
impact of the appreciation of the Colombian peso. This increase was partially offset by unrealized derivative losses, higher fixed costs due to an accelerated growth plan, and lower contracted energy sales.

Adjusted ~~Operating Margin decreased by $6 million~~EBITDA for the ~~US SBU~~three months ended September 30, 2023 increased $72 million primarily due to the drivers mentioned above, adjusted for NCI, unrealized derivatives, and ~~excluding unrealized gains and losses on derivatives.~~depreciation expense.

Adjusted ~~PTC~~EBITDA with Tax Attributes for the three months ended September 30, 2023 increased by $15 million, driven by earnings from equity affiliates due to the 2017 acquisition of sPower and an increase in insurance recoveries at DPL, partially offset by the $6 million decrease in Adjusted Operating Margin described above.

~~Free Cash Flow decreased by $35 million, of which $9 million was attributable to NCI. The decrease in Free Cash Flow was primarily driven by:~~

~~Additional inventory purchases of $20~~$30 million primarily due to ~~inventory optimization efforts at DPL and IPL that occurred~~the increase in ~~2016;~~

~~Higher payments of $13 million for general accounts payable at DPL due to timing;~~

~~Higher interest payments of $13 million primarily at DPL and IPL due to timing; and~~

~~$9 million decrease in Operating Margin (net of lower depreciation of $4 million).~~

~~These negative impacts were~~Adjusted EBITDA, partially offset by ~~an increase of $12~~lower realized tax attributes driven by fewer projects being placed into service. During the three months ended September 30, 2023 and 2022, we realized $18 million ~~in insurance proceeds at DPL.~~and $60 million, respectively, from Tax Attributes earned by our U.S. renewables business.

Operating Margin for the nine months ended September 30, ~~2017, decreased by $15~~2023 increased $41 million ~~or 3%, which was~~ driven primarily by ~~the following (in millions):~~

IPL
Decrease due to implementation of new base rates in Q2 2016 which resulted in a favorable change in accrual $ (18 )
Other (1 )
Total IPL Decrease (19 )
DPL
Lower retail margin due to lower regulated rates (26 )
Lower depreciation expense driven by lower PP&E carrying values from impairments in 2016 and 2017 19
Total DPL Decrease (7 )
US Generation
Warrior Run primarily due to higher availability and lower maintenance cost due to major outages in 2016, partially offset by a decrease in energy price under the PPA 4
Other 7
Total US Generation Increase 11
Total US SBU Operating Margin Decrease $ (15 )
better hydrology, new businesses operating in our portfolio, and higher wind availability, resulting in higher renewable energy generation. This increase was partially offset by unrealized derivatives losses and higher fixed costs due to an accelerated growth plan.

Adjusted ~~Operating Margin decreased by $17 million~~EBITDA for the ~~US SBU due to the drivers above, adjusted for NCI and excluding unrealized gains and losses on derivatives.~~

Adjusted PTC decreased by $17 million, driven by the $17 million decrease in Adjusted Operating Margin described above as well as a 2016 gain on contract termination at DP&L, offset by the Company's share of earnings under the HLBV allocation of noncontrolling interest at Distributed Energy due to new project growth, earnings from equity affiliates due to the 2017 acquisition of sPower, and an increase in insurance recoveries at DPL.

~~Free Cash Flow decreased by $105 million, of which $11 million was attributable to NCI. The decrease in Free Cash Flow was primarily driven by:~~

~~Additional inventory purchases of $66 million primarily due to inventory optimization efforts in 2016 at DPL and IPL;~~

~~Timing of payments for purchased power and general accounts payable of $42 million at DPL;~~

~~$41 million decrease in Operating Margin (net of lower depreciation of $26 million);~~

~~Higher interest payments of $19 million primarily at DPL and IPL due to timing; and~~

~~Lower collections at DPL of $11~~nine months ended September 30, 2023 increased $81 million primarily due to the ~~settlement of DPLER’s receivable balances resulting from its sale~~drivers mentioned above, adjusted for NCI, unrealized derivatives, and depreciation expense.

Adjusted EBITDA with Tax Attributes for the nine months ended September 30, 2023 increased $41 million primarily due to the increase in ~~2016.~~

~~These negative impacts were~~Adjusted EBITDA, partially offset ~~by:~~by lower realized tax attributes driven by fewer projects being placed into service. During the nine months ended September 30, 2023 and 2022, we realized $69 million and $109 million, respectively, from Tax Attributes earned by our U.S. renewables business.

~~Higher collections at IPL of $32 million due to higher receivable balances in December 2016 resulting from favorable weather and the impacts from the 2016 rate order;~~

52 | The AES Corporation | September 30, ~~million of lower maintenance and non-recoverable environmental capital expenditures; and~~2023 Form 10-Q

~~Increase of $12 million in insurance proceeds at DPL.~~

~~ANDES~~Utilities SBU

The following table summarizes Operating Margin, Adjusted ~~Operating Margin,~~EBITDA, and Adjusted PTC ~~and Free Cash Flow~~ (in millions) for the periods indicated:


	Three Months Ended September 30,								Nine Months Ended September 30,
	2023		2022		$ Change		% Change		2023		2022		$ Change		% Change
Operating Margin	$	160	$	79	$	81	NM		$	351	$	280	$	71	25	%

Adjusted EBITDA (1)	216		137		79		58	%	526		456		70		15	%
Adjusted PTC (1) (2)	101		15		86		NM		160		100		60		60	%

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change % Change 2017 2016 $ Change % Change
Operating Margin $ 151
$ 203
$ (52 ) -26 % $ 452
$ 466
$ (14 ) -3 %
Noncontrolling Interests Adjustment ⁽¹⁾
(46 ) (59 ) (144 ) (140 )
Derivatives Adjustment 1
—
—
—

Adjusted Operating Margin $ 106
$ 144
$ (38 ) -26 % $ 308
$ 326
$ (18 ) -6 %
Adjusted PTC $ 62
$ 134
$ (72 ) -54 % $ 232
$ 279
$ (47 ) -17 %
Free Cash Flow $ 91
$ 137
$ (46 ) -34 % $ 277
$ 234
$ 43
18 %
Free Cash Flow Attributable to NCI $ 33
$ 45
$ (12 ) -27 % $ 98
$ 82
$ 16
20 %
____________________________

~~_____________________________~~


⁽¹⁾	~~See Item 1.—Business~~ ~~included in our 2016 Form 10-K for the respective ownership interest for key businesses.~~

~~Including favorable FX and remeasurement impacts of $5 million, Operating Margin~~(1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for ~~the three months ended September 30, 2017, decreased by $52 million, or 26%, which was driven primarily by the following (in millions):~~definition.

Gener
Lower availability of efficient generation resulting in higher replacement energy and fixed costs mainly associated with major maintenance at Ventanas Complex $ (29 )
Negative impact of new regulation on emissions (green taxes) (13 )
Lower margin at the SING market primarily associated with lower contract sales and increase in coal prices at Norgener (8 )
Start of operations at Cochrane Units I and II in July and October 2016, respectively 17
Other (3 )
Total Gener Decrease (36 )
Chivor
Lower spot sales mainly associated to lower generation and lower prices (16 )
Other 1
Total Chivor Decrease (15 )
Other Business Drivers (1 )
Total Andes SBU Operating Margin Decrease $ (52 )

~~Adjusted Operating Margin decreased by $38 million due to the drivers above, adjusted for the impact of NCI and excluding unrealized gains and losses on derivatives.~~

(2) Adjusted PTC ~~decreased~~remains a key metric used by ~~$72 million, mainly driven by~~management for analyzing our businesses in the full allowance of a non-trade receivable in Argentina due to collection uncertainties, higher interest expense primarily associated with the issuance of debt in February 2017 at Argentina, and the write-off of water rights at Gener resulting from a business development project that is no longer pursued.

~~Free Cash Flow decreased by $46 million, of which $12 million was attributable to NCI. The decrease in Free Cash Flow was primarily driven by:~~

~~Higher working capital requirements of $59 million primarily due to delay in collections at Gener; and~~

~~$32 million decrease in Operating Margin (net of higher depreciation of $7 million and $13 million of environmental tax accruals in Chile impacting margin but not free cash flow)~~utilities industry.

These negative impacts were offset by higher collections of $44 million from account receivables in Argentina due to the impact of major maintenance performed in Q2 2016 and from financing receivables due to the commencement of operations of the Guillermo Brown Plant in October 2016.

Including favorable FX and remeasurement impacts of $15 million, Operating Margin for the nine months ended September 30, 2017, decreased by $14 million, or 3%, which was driven primarily by the following (in millions):

Gener
Negative impact of new regulation on Emissions (Green Taxes) $ (37 )
Lower availability of efficient generation resulting in higher replacement energy and fixed costs mainly associated with major maintenance at Ventanas Complex (50 )
Lower margin at the SING market primarily associated with lower contract sales and increase in coal prices at Norgener partially offset by higher spot sales (25 )
Start of operations at Cochrane Units I and II in July and October 2016, respectively 64
Other (6 )
Total Gener Decrease (54 )
Argentina
Higher capacity payments primarily associated to changes in regulation in 2017 32
Higher fixed costs mainly associated with higher people costs driven by inflation (9 )
Other 3
Total Argentina Increase 26
Chivor
Higher contract sales primarily associated to an increase in contracted capacity 20
Lower spot sales mainly associated to lower generation (12 )
Favorable FX impact 7
Other (1 )
Total Chivor Increase 14
Total Andes SBU Operating Margin Decrease $ (14 )

~~Adjusted Operating Margin decreased by $18 million due to the drivers above, adjusted for the impact of NCI.~~

Adjusted PTC decreased by $47 million, driven by the decrease of $18 million in Adjusted Operating Margin plus the full allowance of a non-trade receivable in Argentina due to collection uncertainties, higher interest expenses mainly associated to lower interest capitalization on construction projects and the issuance of debt at Argentina, and the write-off of water rights at Gener resulting from a business development project that is no longer pursued. These negative impacts were partially offset by foreign currency gains in Argentina associated with collections of financing receivables and lower foreign currency losses associated with the sale of Argentina’s sovereign bonds at Termoandes and prepayment of financial debt denominated in U.S. dollars in 2017 at Argentina.

~~Free Cash Flow increased by $43 million, of which $16 million was attributable to NCI. The increase in Free Cash Flow was primarily driven by:~~

~~Lower tax payments of $57 million primarily at Chivor and Argentina;~~

~~$55 million increase in Operating Margin (net of higher depreciation of $32 million and $37 million of environmental tax accruals in Chile impacting margin but not free cash flow);~~

~~Higher collections of $50 million from financing receivables in Argentina due to the commencement of operations of the Guillermo Brown Plant in October 2016; and~~

~~$5 million of lower maintenance and non-recoverable environmental capital expenditures.~~

~~These positive impacts were partially offset by:~~

~~Higher working capital requirements of $60 million primarily due to delay in collections at Gener and Argentina;~~

~~Lower collections of prior period sales of $35 million at Chivor primarily due to higher receivables in Q1 2016 related to higher sales in Q4 2015;~~

~~Higher interest payments of $14 million primarily associated with interest at Cochrane which is no longer capitalized; and~~

~~Lower VAT refunds of $14 million at Alto Maipo and Cochrane due to the timing of construction activities.~~

~~BRAZIL SBU~~

~~The following table summarizes Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Free Cash Flow (in millions) for the periods indicated:~~

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change % Change 2017 2016 $ Change % Change
Operating Margin $ 107
$ 53
$ 54
NM
$ 311
$ 174
$ 137
79 %
Noncontrolling Interests Adjustment⁽¹⁾
(87 ) (41 ) (254 ) (137 )
Adjusted Operating Margin $ 20
$ 12
$ 8
67 % $ 57
$ 37
$ 20
54 %
Adjusted PTC $ 12
$ 6
$ 6
100 % $ 64
$ 18
$ 46
NM
Free Cash Flow $ 142
$ 125
$ 17
14 % $ 307
$ 446
$ (139 ) -31 %
Free Cash Flow Attributable to NCI $ 116
$ 101
$ 15
15 % $ 233
$ 340
$ (107 ) -31 %

~~_____________________________~~


⁽¹⁾	~~See Item 1.—Business~~ ~~included in our 2016 Form 10-K for the respective ownership interest for key businesses.~~

~~Including favorable FX impacts of $3 million, Operating Margin for the three months ended September 30, 2017, increased by $54 million, which was driven primarily by the following (in millions):~~

Eletropaulo
Revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years $ 50
Lower fixed costs mainly due to lower bad debt and regulatory penalties 34
Higher tariffs due to annual tariff reset 20
Lower volume mainly due to lower demand resulting from economic decline and migration to free market (30 )
Other (2 )
Total Eletropaulo Increase 72
Tietê
Net impact of volume and prices of bilateral contracts due to higher energy purchased (45 )
Net impact of volume and prices of lower energy purchased in spot market 13
Higher volume due to acquisition of new wind entities - Alto Sertão II 12
Other 2
Total Tietê Decrease (18 )
Total Brazil SBU Operating Margin Increase $ 54

~~Adjusted Operating Margin increased by $8 million, primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests.~~

Adjusted PTC increased by $6 million, mainly driven by the increase of $8 million in Adjusted Operating Margin as described above, partially offset by $2 million due to higher interest expense from debt issued to acquire new wind entities at Tietê.

~~Free Cash Flow increased by $17 million, of which $15 million was attributable to NCI. The increase in Free Cash Flow was primarily driven by:~~

•~~$166 million of lower payments for energy purchases at Eletropaulo due to lower energy costs and lower regulatory charges;~~

~~$65 million increase in Operating Margin (net of increased depreciation of $11 million); and~~

~~Favorable timing of $24 million in higher energy purchased for resale at Tietê.~~

~~These positive impacts were partially offset by:~~

~~$181 million in lower collections of costs deferred in net regulatory assets at Eletropaulo due to higher energy costs in Q3 2017;~~

~~$22 million in lower collections of energy sales at Eletropaulo due primarily to higher tariffs in 2017;~~

~~$15 million of higher maintenance capital expenditures at Eletropaulo;~~

~~$7 million in lower collections on energy sales at Tietê; and~~

~~$6 million of higher interest payments resulting from the assumption of debt for the acquisition of Alto Sertão II.~~

~~Including favorable FX impacts of $29 million, Operating Margin for the nine months ended September 30, 2017, increased by $137 million, which was driven primarily by the following (in millions):~~

Eletropaulo
Higher tariffs due to annual tariff reset $ 84
Lower volume mainly due to lower demand resulting from slow economic growth and migration to free market (61 )
Lower fixed costs mainly due to lower bad debt and lower regulatory penalties 54
Revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years 50
Total Eletropaulo Increase 127
Tietê
Net impact of volume and prices of bilateral contracts due to higher energy purchased (70 )
Net impact of volume and prices of lower energy purchased in spot market 57
Favorable FX impacts 20
Higher volume due to acquisition of new wind entities - Alto Sertão II 12
Other (3 )
Total Tietê Increase 16
Other Business Drivers (6 )
Total Brazil SBU Operating Margin Increase $ 137

~~Adjusted Operating Margin increased by $20 million, primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests.~~

Adjusted PTC increased by $46 million, driven by the increase of $20 million in Adjusted Operating Margin as described above, as well as a $28 million increase from the settlement of a legal dispute with YPF at Uruguaiana.

~~Free Cash Flow decreased by $139 million, of which $107 million was attributable to NCI. The decrease in Free Cash Flow was primarily driven by:~~

~~$556 million of higher collections in 2016 of costs deferred in net regulatory assets at Eletropaulo, as a result of unfavorable hydrology in prior periods;~~

~~$193 million in lower collections on energy sales at Eletropaulo due primarily to higher tariff flags in 2016;~~

~~$55 million higher maintenance capital expenditures at Eletropaulo;~~

~~$32 million decrease due to the sale of Sul in October 2016;~~

~~$20 million in lower collections on energy sales at Tietê;~~

~~$13 million of higher pension payments in 2017 driven by the debt renegotiation in prior year at Eletropaulo; and~~

~~$6 million of higher interest payments at Alto Sertão II.~~

~~These negative impacts were partially offset by:~~

~~Favorable timing of $401 million in payments for energy purchases at Eletropaulo due to lower energy costs and lower regulatory charges;~~

~~$167 million increase in Operating Margin (net of increased depreciation of $30 million);~~

~~$60 million collected from a legal dispute settlement with YPF at Uruguaiana;~~

~~$58 million of lower tax payments at Tietê ;~~

~~Favorable timing of $32 million in higher energy purchased for resale at Tietê; and~~

~~$11 million of lower interest payments at Tietê.~~

~~MCAC SBU~~

~~The following table summarizes Operating Margin, Adjusted Operating Margin, Adjusted PTC, and Free Cash Flow (in millions) for the periods indicated:~~

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change % Change 2017 2016 $ Change % Change
Operating Margin $ 165
$ 140
$ 25
18 % $ 430
$ 370
$ 60
16 %
Noncontrolling Interests Adjustment ⁽¹⁾
(35 ) (31 ) (82 ) (77 )
Derivatives Adjustment (1 ) (2 ) (1 ) (3 )
Adjusted Operating Margin $ 129
$ 107
$ 22
21 % $ 347
$ 290
$ 57
20 %
Adjusted PTC $ 98
$ 74
$ 24
32 % $ 256
$ 197
$ 59
30 %
Free Cash Flow $ 118
$ 118
$ —
— % $ 211
$ 131
$ 80
61 %
Free Cash Flow Attributable to NCI $ 14
$ 27
$ (13 ) -48 % $ 20
$ 33
$ (13 ) -39 %

~~_____________________________~~


⁽¹⁾	~~See Item 1.—Business~~ ~~included in our 2016 Form 10-K for the respective ownership interest for key businesses.~~

Operating Margin for the three months ended September 30, ~~2017,~~2023 increased ~~by $25~~$81 million ~~or 18%, which was~~mainly driven ~~primarily~~ by the ~~following (in millions):~~

Dominican Republic
Higher contracted energy sales mainly driven by Los Mina combined cycle commencement of operations in June 2017 $ 14
Higher availability driven by Los Mina combined cycle interconnection in 2016 5
Other 6
Total Dominican Republic Increase 25
Total MCAC SBU Operating Margin Increase $ 25
deferral of power purchase costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval and a regulatory settlement in the prior year.

Adjusted ~~Operating Margin~~EBITDA for the three months ended September 30, 2023 increased ~~by $22~~$79 million primarily due to the drivers above, adjusted for ~~the impact of NCI and excluding unrealized gains and losses on derivatives.~~NCI.

Adjusted PTC for the three months ended September 30, 2023 increased ~~by $24~~$86 million ~~driven by the increase of $22 million in Adjusted Operating Margin as described above.~~

~~Free Cash Flow is aligned in both periods, driven by $28 million increase in Operating Margin (net of increased depreciation of $3 million), offset by higher working capital requirements~~ due to ~~unfavorable timing~~the drivers above and the deferral of ~~collections, mainly~~carrying costs associated with the ESP 4 approval in the ~~Dominican Republic.~~current year.

~~Including favorable FX impacts of $1 million,~~ Operating Margin for the nine months ended September 30, ~~2017,~~2023 increased ~~by $60~~$71 million ~~or 16%, which was~~mainly driven ~~primarily~~ by the ~~following (in millions):~~

Dominican Republic
Higher energy sales mainly driven by higher contracted capacity $ 32
Higher availability driven by greater major maintenance scope in 2016 13
Other (7 )
Total Dominican Republic Increase 38
Mexico
Lower maintenance and higher availability 17
Other 4
Total Mexico Increase 21
Other Business Drivers 1
Total MCAC SBU Operating Margin Increase $ 60
deferral of power purchase costs in the current year, which were recognized in the prior year, associated with the ESP 4 approval, a regulatory settlement in the prior year, an increase in transmission and TDSIC rider revenues and higher demand due to extreme heat in El Salvador, partially offset by the impact of milder weather in Indiana and Ohio and higher fixed costs.

Adjusted ~~Operating Margin~~EBITDA for the nine months ended September 30, 2023 increased ~~by $57~~$70 million primarily due to the drivers above, adjusted for ~~the impact of NCI and excluding unrealized gains and losses on derivatives.~~NCI.

Adjusted PTC for the nine months ended September 30, 2023 increased ~~by $59~~$60 million ~~driven by the increase of $57 million in Adjusted Operating Margin as described above.~~

~~Free Cash Flow increased by $80 million, of which a $13 million decrease was attributable to NCI. The increase in Free Cash Flow was driven by:~~

~~$68 million increase in Operating Margin (net of increased depreciation of $8 million);~~

~~Lower working capital requirements of $36 million in AES Puerto Rico primarily~~ due to ~~higher collections~~the drivers above and the deferral of ~~energy sales;~~

~~Lower tax payments of $10 million~~carrying costs associated with the ESP 4 approval in the ~~Dominican Republic primarily~~current year, partially offset by higher interest expense due to ~~lower withholding taxes on dividends paid~~new debt transactions and increases in ~~2016 to AES Affiliates;~~defined benefit plan costs.

~~Lower tax payments of $16 million in El Salvador; and~~

~~$7 million of lower maintenance and non-recoverable environmental capital expenditures.~~

~~These positive impacts were partially offset by:~~

~~Higher working capital requirements of $42 million in the Dominican Republic primarily due to lower collections of energy sales at Itabo; and~~

~~$13 million of higher interest payments in the Dominican Republic primarily due to an increase in net debt and average interest rates.~~

~~EURASIA~~Energy Infrastructure SBU

The following table summarizes Operating Margin and Adjusted ~~Operating Margin, Adjusted PTC, and Free Cash Flow~~EBITDA (in millions) for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change % Change 2017 2016 $ Change % Change
Operating Margin $ 102
$ 95
$ 7
7 % $ 343
$ 308
$ 35
11 %
Noncontrolling Interests Adjustment ⁽¹⁾
(30 ) (30 ) (94 ) (89 )
Derivatives Adjustment (4 ) (10 ) (13 ) (5 )
Adjusted Operating Margin $ 68
$ 55
$ 13
24 % $ 236
$ 214
$ 22
10 %
Adjusted PTC $ 61
$ 46
$ 15
33 % $ 218
$ 197
$ 21
11 %
Free Cash Flow $ 180
$ 156
$ 24
15 % $ 459
$ 714
$ (255 ) -36 %
Free Cash Flow Attributable to NCI $ 56
$ 65
$ (9 ) -14 % $ 145
$ 142
$ 3
2 %


	Three Months Ended September 30,								Nine Months Ended September 30,
	2023		2022		$ Change		% Change		2023		2022		$ Change		% Change
Operating Margin	$	504	$	588	$	(84)	-14	%	$	1,120	$	1,211	$	(91)	-8	%

Adjusted EBITDA (1)	520		620		(100)		-16	%	1,165		1,353		(188)		-14	%

_____________________________


(1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition. ⁽¹⁾	~~See Item 1.—Business~~ ~~included in our 2016 Form 10-K for the respective ownership interest for key businesses.~~

~~Including favorable FX impacts of $2 million,~~ Operating Margin for the three months ended September 30, ~~2017, increased by $7~~2023 decreased $84 million ~~or 7%, which was~~ driven primarily by ~~the following (in millions):~~prior year favorable LNG transactions, lower contract energy sales due to lower prices, and higher cost of sales.

Ballylumford
Higher energy and capacity prices $ 4
Other 4
Total Ballylumford Increase 8
Other Business Drivers (1 )
Total Eurasia SBU Operating Margin Increase $ 7
These losses were partially offset by higher revenues due to a PPA termination agreement and realized and unrealized gains resulting mainly from new derivatives as part of our commercial hedging strategy.

Adjusted ~~Operating Margin increased by $13~~EBITDA for the three months ended September 30, 2023 decreased $100 million primarily due to the drivers above, adjusted for NCI, ~~and excluding~~ unrealized derivative gains, and ~~losses on derivatives.~~depreciation.

~~Adjusted PTC increased by $15 million, mainly driven by the increase of $13 million in Adjusted Operating Margin described above.~~

~~Free Cash Flow increased by $24 million, of which a $9 million decrease was attributable to NCI. The increase in Free Cash Flow was primarily driven by:~~


•	~~Increase in CO~~₂ ~~allowances of $9 million at Maritza due to decreased prices in 2016;~~

~~Lower working capital requirements of $8 million at Kilroot primarily due to a decrease in rates and VAT received in 2017; and~~

~~$5 million of lower maintenance and non-recoverable environmental capital expenditures.~~

~~Including unfavorable FX impacts of $3 million,~~ Operating Margin for the nine months ended September 30, ~~2017 increased by $35~~2023 decreased $91 million ~~or 11%, which was~~ driven primarily by prior year favorable LNG transactions, higher cost of sales, lower thermal dispatch substituted with renewable sources, the ~~following (in millions):~~recognition of unrealized losses due to a PPA termination agreement, and a prior year one-time revenue recognition driven by a reduction in a project's expected completion costs.

Kilroot
Higher fair value adjustments of commodity swaps $ 10
Favorable capacity prices due to fixed EUR/GBP rate set by the Regulator 9
Unfavorable clean-dark spread leading to lower dispatch (6 )
Other (3 )
Total Kilroot Increase 10
Ballylumford
Higher energy and capacity prices 7
Settlement with offtaker on previous gas transportation charges billed in April 2017 4
Lower maintenance costs due to outages in 2016 3
Other 6
Total Ballylumford Increase 20
Other Business Drivers 5
Total Eurasia SBU Operating Margin Increase $ 35
These losses were partially offset by unrealized gains resulting mainly from new derivatives as part of our commercial hedging strategy, higher revenues due to a PPA termination agreement, lower outages, and lower depreciation expense due to impairments recognized in the prior year.

Adjusted ~~Operating Margin increased by $22~~EBITDA for the nine months ended September 30, 2023 decreased $188 million primarily due to the

53 | The AES Corporation | September 30, 2023 Form 10-Q

drivers above, adjusted for NCI, unrealized derivatives gains, depreciation, higher realized foreign currency losses, and ~~excluding unrealized gains~~lower insurance recovery.

New Energy Technologies SBU

The following table summarizes Operating Margin and Adjusted EBITDA (in millions) for the periods indicated:


	Three Months Ended September 30,								Nine Months Ended September 30,
	2023		2022		$ Change		% Change		2023		2022		$ Change		% Change
Operating Margin	$	(2)	$	(2)	$	—	—	%	$	(8)	$	(5)	$	(3)	-60	%

Adjusted EBITDA (1)	(22)		(27)		5		-19	%	(61)		(88)		27		31	%

_____________________________

(1) A non-GAAP financial measure. See SBU Performance Analysis—Non-GAAP Measures for definition.

Operating Margin for the three months ended September 30, 2023 remained flat, with no material drivers.

Adjusted EBITDA for the three months ended September 30, 2023 increased $5 million primarily driven by lower losses at Fluence, whose results are reported as Net equity in losses of affiliateson ~~derivatives.~~our Condensed Consolidated Statements of Operations, mainly attributable to improved margins on a new product line.

Operating Margin for the nine months ended September 30, 2023 decreased $3 million, with no material drivers.

Adjusted ~~PTC~~EBITDA for the nine months ended September 30, 2023 increased ~~by $21~~$27 million ~~mainly driven by the increase of $22 million in Adjusted Operating Margin described above.~~

~~Free Cash Flow decreased by $255 million, of which a $3 million increase was attributable to NCI. The decrease in Free Cash Flow was primarily driven by:~~

~~Lower collections of $376 million at Maritza,~~ primarily due to improved margins on a new product line, the ~~collection~~issuance of ~~overdue receivables from NEK in April 2016;~~

~~$9 million of higher non-cash mark-to-market valuation adjustments to commodity swaps at Kilroot impacting margin but not free cash flow; and~~

~~Lower coal purchases of $9 million at Mong Duong due to~~price increase change orders during the ~~reserve shutdown in 2017.~~

~~These negative impacts were partially offset by:~~

~~The~~period, the settlement of ~~$73 million~~contractual claims with a battery module vendor, and incremental costs incurred in ~~payables to Maritza’s fuel supplier;~~the prior year as a result of COVID-19. These increases were partly offset by higher costs for research and development, sales and marketing, and general and administrative expenses.

~~$21 million of lower maintenance and non-recoverable environmental capital expenditures;~~

~~$19 million increase in operating margin (net of $16 million of lower depreciation);~~

~~Lower working capital requirements of $19 million at Masinloc due to the timing of payments for coal purchases; and~~


•	~~Increase in CO~~₂ ~~allowances of $17 million at Maritza due to decreased prices in 2016.~~

Key Trends and Uncertainties

During ~~the remainder of 2017~~2023 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses, and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation, and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1.—Business and Item 1A.—Risk Factors of our 2022 Form 10-K.

~~Hurricanes Irma~~Operational

Trade Restrictions and ~~Maria~~

~~In September 2017, Puerto Rico and~~Supply Chain — On March 29, 2022, the U.S. ~~Virgin Islands were severely impacted by Hurricanes Irma~~Department of Commerce (“Commerce”) announced the initiation of an investigation into whether imports into the U.S. of solar cells and ~~Maria, disrupting~~panels imported from Cambodia, Malaysia, Thailand, and Vietnam are circumventing antidumping and countervailing duty orders on solar cells and panels from China. This investigation resulted in significant systemic disruptions to the ~~operations~~import of ~~AES Puerto Rico, AES Ilumina,~~solar cells and ~~certain Distributed Energy assets. Puerto Rico’s infrastructure was severely damaged, including electric infrastructure~~panels from Southeast Asia. On June 6, 2022, President Biden issued a Proclamation waiving any tariffs that result from this investigation for a 24-month period. Since President Biden’s Proclamation, suppliers in Southeast Asia have imported cells and ~~transmission lines. The extensive structural damage caused by hurricane winds and flooding is expected~~panels again to ~~take significant time to repair.~~the U.S.

On ~~October 24, 2017,~~December 2, 2022, Commerce issued country-wide affirmative preliminary determinations that circumvention had occurred in each of the four Southeast Asian countries. Commerce also evaluated numerous individual companies and issued preliminary determinations that circumvention had occurred with respect to many but not all of these companies. Additionally, Commerce issued a preliminary determination that circumvention would not be deemed to occur for any solar cells and panels imported from the four countries if the wafers were manufactured outside of China or if no more than two out of six specifically identified components were produced in China. On August 18, 2023, Commerce issued its final determination on the matter and affirmed its preliminary findings in most respects. Additionally, Commerce found that three of the specific companies it investigated were not circumventing.

We have contracted and secured our expected requirements for solar panels for U.S. projects targeted to achieve commercial operations in 2023 and 2024.

54 | The AES Corporation | September 30, 2023 Form 10-Q

Additionally, the Uyghur Forced Labor Prevention Act (“UFLPA”) seeks to block the import of products made with forced labor in certain areas of China and may lead to certain suppliers being blocked from importing solar cells and panels to the U.S. While this has impacted the U.S. ~~Congress approved~~market, AES has managed this issue without significant impact to our projects. Further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements or to continue to supply cells or panels into the U.S. market on terms that we deem satisfactory.

The impact of any additional adverse Commerce determinations or other tariff disputes or litigation, the impact of the UFLPA, potential future disruptions to the solar panel supply chain and their effect on AES’ U.S. solar project development and construction activities remain uncertain. AES will continue to monitor developments and take prudent steps towards maintaining a ~~$37 billion emergency disaster relief bill which will allow the US Government~~robust supply chain for our renewable projects.

Operational Sensitivity to ~~help victims from the hurricanes and assist with the infrastructure rebuild~~Dry Hydrological Conditions — Our hydroelectric generation facilities are sensitive to changes in the ~~affected areas through~~weather, particularly the ~~Federal Emergency Management Agency. This supplemental appropriation includes an allocation~~level of ~~$5 billion~~water inflows into generation facilities. In the past, dry hydrological conditions in Panama, Brazil, Colombia and Chile have presented challenges for ~~the Disaster Assistance Direct Loan Program~~our businesses in these markets. Low rainfall and water inflows have caused reservoir levels to ~~assist local governments, like Puerto Rico, in providing essential services, such as reestablishing~~be below historical levels, reduced generation output, and increased prices for electricity.

~~Although a more detailed assessment of the damage~~ If our hydroelectric generation facilities cannot generate sufficient energy to ~~its facilities is still ongoing, the Company sustained modest damage~~meet contractual arrangements, we may need to ~~its 24 MW AES Ilumina solar plant, resulting in an estimated $6 million loss, and minor damage~~purchase energy to its 524 MW AES Puerto Rico thermal plants, both located in Puerto Rico. The Company’s 5 MW solar plant in the U.S. Virgin Islands has been materially damaged, resulting in an estimated $9 million loss, and is not available to generate electricity.

~~As a result of the Hurricanes, PREPA has declared an event of Force Majeure. However, both units of AES Puerto Rico and approximately 75% of AES Ilumina are available to generate electricity~~fulfill our obligations, which ~~in accordance with the PPAs, will allow AES Puerto Rico to invoice capacity, even under Force Majeure.~~

The Company maintains an insurance program, subject to an annual cap, which provides coverage for property damage, business interruption, and costs associated with clean-up and recovery. However, it is possible that any losses not covered by insurance could have a material adverse ~~effect~~impact on our ~~financial condition,~~ results of operations. As a mitigation measure, AES has invested in thermal, wind, and solar generation assets, which have a complementary profile to hydroelectrics. These plants are expected to have a higher generation in low hydrology scenarios, which allows them to generate additional revenues from the spot that offset purchases on the hydroelectric side.

According to the National Oceanic and Atmospheric Administration ("NOAA"), El Niño conditions are observed and forecasted through the beginning of U.S. spring of 2024, with a 60% probability of extending into mid-2024. In Panama, the El Niño phenomenon typically means drier conditions than average, although local system impacts may vary due to other factors. Lower hydrology may result in increased energy purchases to cover contracted positions, or less energy available to sell in the spot market after fulfilling contract obligations. Consistent with expected El Niño impacts, local hydrological forecasts in Panama indicate below historical average inflows persisting through the beginning of the rainy season, which could impact our results of operations. AES reduced its total generation exposure in Panama to dry hydrological conditions through investments in such complementary assets as the Colon LNG power facility, which commenced operations in 2018, the Penonome Wind Farm, and solar projects, providing a stable and independent diversified energy supply during periods of drought or ~~cash flows.~~when hydroelectric generation is limited.

In Brazil, El Niño generally means more rainfall in the southern region of the country, where system reservoir levels are currently high, mitigating El Niño risk. In Colombia, El Niño is characterized by drought and may result in higher spot prices. Lower overall AES Chivor hydrology may result in increased spot price energy exposure to cover contracted positions. The basin where AES Chivor is located typically experiences dry conditions that are less severe than the broader system within periods of El Niño from June through September, which can result in additional energy available to sell in the spot market after fulfilling contract obligations. In the case of Chile, the primary driver for AES’ hydro assets is snowpack volumes. Lower snowpack, together with reduced rainfall in the system, could increase both spot prices and energy purchase volumes required to meet contracted positions.

The exact behavior pattern and strength of El Niño cannot be definitively known at this time and therefore the impacts could vary from those described above, and may include impacts to our businesses beyond hydrology, including with respect to power generation from other renewable sources of energy and demand. Even if rainfall and water inflows return to historical averages, in some cases high market prices and low generation could persist until reservoir levels are fully recovered. Further, investments made in thermal, wind, and solar power generation may benefit from uncontracted spot sales at higher market prices. Impacts may be material to our results of operations.

Macroeconomic and Political

During the past few years, ~~economic conditions~~some countries where our subsidiaries conduct business have experienced macroeconomic and political changes. In the event these trends continue, there could be an adverse impact on our businesses.

Inflation Reduction Act and U.S. Renewable Energy Tax Credits— The Inflation Reduction Act (the “IRA”) was signed into law in the United States in 2022. The IRA includes provisions that are expected to benefit the U.S. clean energy industry, including increases, extensions and/or new tax credits for onshore and offshore wind, solar, storage and hydrogen projects. We expect that the extension of the current solar investment tax credits (“ITCs”), as well as higher credits available for projects that satisfy wage and apprenticeship requirements, will increase demand for our renewables products.

55 | The AES Corporation | September 30, 2023 Form 10-Q

Our U.S. renewables business has a 51 GW pipeline that we intend to utilize to continue to grow our business, and these changes in tax policy are supportive of this strategy. We account for U.S. renewables projects according to U.S. GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity partners at the time of its creation, which for projects utilizing the investment tax credit is in the quarter the project begins commercial operation. For projects utilizing the production tax credit, this value is recognized over 10 years as the facility produces energy. In 2022, we realized $267 million of earnings from Tax Attributes. In 2023, we expect an increase in Tax Attributes earned by our U.S. renewables business in line with the growth of that business. Based on construction schedules, a significant portion of these earnings will be realized in the fourth quarter.

The implementation of the IRA is expected to require substantial guidance from the U.S. Department of Treasury and other government agencies. While that guidance is pending, there will be uncertainty with respect to the implementation of certain provisions of the IRA.

Global Tax — The macroeconomic and political environments in the U.S. and in some countries where our subsidiaries conduct business have ~~destabilized. Changes~~changed during 2022 and 2023. This could result in significant impacts to tax law.

In the U.S., the IRA includes a 15% corporate alternative minimum tax based on adjusted financial statement income. Additional guidance is expected to be issued in 2023.

In the fourth quarter of 2022, the European Commission adopted an amended Directive on Pillar 2 establishing a global ~~economic conditions~~minimum tax at a 15% rate. The adoption requires EU Member States to transpose the Directive into their respective national laws by December 31, 2023 for the rules to come into effect as of January 1, 2024. We will continue to monitor the issuance of draft legislation in Bulgaria, the Netherlands, as well as other non-EU countries where the Company operates that are considering Pillar 2 amendments. The impact to the Company remains unknown but may be material.

Inflation — In the markets in which we operate, there have been higher rates of inflation recently. While most of our contracts in our international businesses are indexed to inflation, in general, our U.S.-based generation contracts are not indexed to inflation. If inflation continues to increase in our markets, it may increase our expenses that we may not be able to pass through to customers. It may also increase the costs of some of our development projects that could negatively impact their competitiveness. Our utility businesses do allow for recovering of operations and maintenance costs through the regulatory process, which may have timing impacts on recovery.

Interest Rates — In the U.S. and other markets in which we operate, there has been a rise in interest rates recently. From July 1 to September 30, 2023, the yield on 10-year U.S. Treasury Notes rose from 3.84% to 4.57%.

As discussed in Item 3—Quantitative and Qualitative Disclosures about Market Risk, although most of our existing corporate and subsidiary debt is at fixed rates, an ~~adverse impact~~increase in interest rates can have several impacts on our ~~businesses~~business. For any existing debt under floating rate structures and any future debt refinancings, rising interest rates will increase future financing costs. In most cases in which we have floating rate debt, our revenues serving this debt are indexed to inflation which helps mitigate the ~~event these recent trends continue.~~impact of rising rates. For future debt refinancings, AES actively manages a hedging program to reduce uncertainty and exposure to future interest rates. For new business, higher interest rates increase the financing costs for new projects under development and which have not yet secured financing.

AES typically seeks to incorporate expected financing costs into our new PPA pricing such that we maintain our target investment returns, but higher financing costs may negatively impact our returns or the competitiveness of some of our development projects. Additionally, we typically seek to enter into interest rate hedges shortly after signing PPAs to mitigate the risk of rising interest rates prior to securing long-term financing.

Puerto Rico— As discussed in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties of the ~~2016~~2022 Form 10-K, our subsidiaries in Puerto Rico have

~~long- term~~ long-term PPAs with state-owned PREPA, which has been facing economic challenges that could ~~impact~~result in a material adverse effect on our business in Puerto Rico.Despite the ~~Company.~~Title III protection, PREPA has been making substantially all of its payments to the generators in line with historical payment patterns.

~~In order to address these challenges, on June 30, 2016, the~~The Puerto Rico Oversight, Management, and Economic Stability Act (“PROMESA”) was ~~signed into law. PROMESA created~~enacted to create a structure for exercising federal oversight over the fiscal affairs of U.S. territories and created procedures for adjusting debt accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). PROMESA also expedites the approval of key energy projects and other critical projects in Puerto Rico.

56 | The AES Corporation | September 30, 2023 Form 10-Q

PROMESA allowed for the establishment of an Oversight Board with broad powers of budgetary and financial control over Puerto Rico. PROMESA also created procedures for adjusting debts accumulated by the Puerto Rico government and, potentially, other territories (“Title III”). Finally, PROMESA expedites the approval of key energy projects and other critical projects in Puerto Rico.

PREPA entered into preliminary Restructuring Support Agreements (“RSAs”) with their lenders. Under PROMESEA, PREPA submitted the RSA to the Oversight Board for approval on April 28, 2017, which the board denied on June 28, 2017. As a consequence, on July 2, 2017, theThe Oversight Board filed for bankruptcy on behalf of PREPA under Title ~~III.~~

III in July 2017. As a result of the bankruptcy filing, AES Puerto Rico and AES Ilumina’s non-recourse debt of ~~$365~~$143 million and ~~$36~~$25 million, respectively, ~~are~~continue to be in technical default and ~~have been~~are classified as current as of September 30, 2017. In addition, the Company's receivable balances in Puerto Rico as of September 30, 2017 totaled $63 million, of which $30 million was overdue. After the filing of Title III protection, and up until the disruption caused by the hurricanes, AES in Puerto Rico was collecting the overdue amounts from PREPA in line with historic payment patterns.

~~Additionally, on July 18, 2017, Moody's downgraded~~2023. The non-recourse debt at AES Puerto Rico is also in payment default.

On April 12, 2022, a mediation team was appointed to ~~Caa1 from B3 due~~prepare the plan to resolve the ~~heightened default risk~~PREPA Title III case and related proceedings. A disclosure statement hearing was held on April 28, 2023. The mediation was extended through August 4, 2023. The judge presiding over the case entered an order setting the confirmation schedule for PREPA’s third amended Plan of Adjustment as March 4, 2024 through March 15, 2024. The next hearing on PREPA’s disclosure statement is scheduled for November 14, 2023.

Earlier this year, AES Puerto Rico ~~as a result~~took certain measures to address identified liquidity challenges. On July 6, 2023, PREPA agreed to the release of ~~PREPA's bankruptcy protection. This protection gives PREPA~~funds in the ~~ability~~escrow account guaranteeing AES Puerto Rico’s obligations under the Power Purchase and Operating Agreement (“PPOA”) in order to ~~renegotiate contracts, which could impact~~provide additional liquidity for the ~~value of our assets in~~business. Additionally, AES Puerto Rico ~~or otherwise have~~entered into a ~~material impact on the Company. In this regard, PREPA had requested the Company to renegotiate~~standstill and forbearance agreement with its ~~24 MW AES Ilumina’s PPA. After the event~~noteholders because of the ~~hurricanes Maria~~insufficiency of funds to meet the principal and ~~Irma,~~interest obligations on its Series A Bond Loans due and payable on June 1, 2023, and going forward. AES Puerto Rico continues to work with PREPA and its noteholders on these ~~negotiations were put on hold.~~liquidity challenges.

~~Considering~~Despite these challenges and considering the information available as of the filing date, ~~Management~~management believes the carrying amount of our long-lived assets inat AES Puerto Rico of ~~$622~~$63 million is recoverable as of September 30, ~~2017.~~

~~Brazil~~ ~~— The political landscape in Brazil remains uncertain. As disclosed~~2023. However, it is reasonably possible that the estimate of undiscounted cash flows may change in the Company’s Form 10-K for the year ended December 31, 2016, Brazilian President Michael Temer was seeking to implement economic reforms in Brazil that would improve the economic outlook in Brazil, which may benefit our businessesnear term resulting in the ~~country. During 2017, corruption investigations were formally started against President Temer. These investigations could delay the reform plans which may have benefited~~need to write down our ~~businesses~~long-lived assets in ~~Brazil.~~Puerto Rico to fair value.

~~Regulatory~~Decarbonization Initiatives

~~DP&L ESP Rate Case~~ ~~— On October 20, 2017, PUCO issued a final decision approving the DP&L ESP rate case. The ESP establishes DP&L’s framework for providing retail service on a go forward basis~~Our strategy involves shifting towards clean energy platforms, including ~~rate structures, non-bypassable charges~~renewable energy, energy storage, LNG, and other specific rate recovery true-up mechanisms. The agreement establishes a six-year settlement that provides a framework for energy rates and defines components which include, but are not limited to, the following:

~~Bypassable standard offer energy rates for DP&L’s customers based on competitive bid auctions;~~

~~The establishment of a three-year non-bypassable Distribution Modernization Rider~~modernized grids. It is designed to ~~collect $105 million~~position us for continued growth while reducing our carbon intensity and in revenue per year which could be extended by PUCO for an additional two years. The Distribution Modernization Rider will be used for debt repayments as well as modernization and maintenance of transmission and distribution infrastructure;

The establishment of a non-bypassable Distribution Investment Rider to recover incremental distribution capital investments, the amount of which is to be established in a separate DP&L distribution rate case;

A non-bypassable Reconciliation Rider permitting DP&L to defer, recover, or credit the net proceeds from selling energy and capacity received as part of DP&L’s investment in the Ohio Valley Electric Corporation;

Implementation by DP&L of a Smart Grid Rider, Economic Development Rider, Economic Development Fund, Regulatory Compliance Rider and certain other new or modified rates, riders and competitive retail market enhancements, with tariffs consistent with the order to be effective November 1, 2017;

A commitment to commence the sale process of the Company’s ownership interests in the Zimmer, Miami Fort and Conesville coal-fired generation plants with all sales proceeds used to pay debt of DPL and DP&L; and

~~Restrictions on DPL making dividend or tax sharing payments.~~

~~In connection with the sale or closure~~support of our mission of accelerating the future of energy, together. We have made significant progress on our exit of coal generation, ~~plants as contemplated~~and we intend to exit the substantial majority of our remaining coal facilities by ~~the ESP settlement or otherwise, DPL~~year-end 2025 and ~~DP&L may incur certain cash and non-cash charges, which could be material~~intend to ~~the Company.~~

~~Proposed U.S. Market Reforms~~ — The U.S. Department of Energy (“DOE”) issued a Notice of Proposed Rule Making (“NOPR”) on September 29, 2017, which directed the FERC to exercise its authority to set just and reasonable rates that recognize the “resiliency” value provided by generation plants with certain characteristics, including having 90-days or more of on-site fuel and operating in markets where they do not receive rate base treatment through state ratemaking. Nuclear and coal-fired generation plants are most likely to be able to meet the requirements. As proposed, the DOE would value resiliency through rates that recover “compensable costs” that are defined to include the recovery of operating and fuel expenses, debt service and a fair return on equity. The FERC is proceeding on an expedited basis, as requested by the DOE, but the timing and outcome of the proposed rule, including effects on wholesale energy markets, remains uncertain.

~~International Trade Commission~~ — In April 2017, Suniva, a bankrupt solar photovoltaic panel manufacturer with a factory in Georgia filed a petition with the U.S. International Trade Commission (“ITC”) asserting that solar panels imported into the U.S. were causing substantial injury to domestic manufacturers. Subsequent to filing, SolarWorld Americas, a large U.S. manufacturer of solar panels, joined as a co-petitioner. The ITC accepted the petition and on September 22, 2107 determined that serious injury has been caused by foreign solar photovoltaic panels. On October 31, 2017, the ITC announced its proposed recommendations for remedies. These proposed recommendations include tariffs at various levels, a quota system and licensing fees. The ITC's final recommendations will be provided to the U.S. President by November 13, 2017. A final decision, either to accept, revise or reject some orexit all of the ~~ITC's recommendations, will be made~~coal facilities by ~~the U.S. President~~year-end 2027, subject to necessary approvals.

In addition, initiatives have been announced by regulators, including in ~~late 2017 or early 2018. AES is still evaluating the impact these recommended remedies will have, but they will likely increase the cost of solar photovoltaic panels~~Chile, Puerto Rico, and ~~may impact the value of future solar development projects~~Bulgaria, and offtakers in the U.S., including those of our solar businesses. In the absence of the U.S. President's final decision, it is difficult to predict the outcome of the recommended remedies, but the impact on our solar businesses and AES could be material.

~~Alto Maipo~~

As disclosed in the Company’s Form 10-Q for the period ended March 31, 2017, Alto Maipo has experienced construction difficulties which have resulted in an increase in projected cost for the project of up to 22% of the original $2 billion budget. These overages led to a series of negotiationsrecent years, with the intention of ~~restructuring~~reducing GHG emissions generated by the ~~project’s existing~~energy industry. In parallel, the shift towards renewables has caused certain customers to migrate to other low-carbon energy solutions and this trend may continue.

Although we cannot currently estimate the financial ~~structure~~impact of these decarbonization initiatives, new legislative or regulatory programs further restricting carbon emissions or other initiatives to voluntarily exit coal generation could require material capital expenditures, resulting in a reduction of the estimated useful life of certain coal facilities, or have other material adverse effects on our financial results.

For further information about the risks associated with decarbonization initiatives, see Item 1A.—Risk Factors—Concerns about GHG emissions and ~~obtaining additional funding.~~the potential risks associated with climate change have led to increased regulation and other actions that could impact our businesses included in the 2022 Form 10-K.

AES Warrior Run PPA Termination — On March ~~17, 2017, AES Gener completed a legal~~23, 2023, the Company entered into an agreement to terminate the PPA for its 205 MW Warrior Run coal-fired power plant. The agreement was approved by the Maryland Public Service Commission in June and ~~financial restructuring of Alto Maipo.~~became effective on June 28, 2023. As a part of this restructuring, AES Gener simultaneously acquired a 40% ownership interest from Minera Los Pelambres (“MLP”), a noncontrolling shareholder, for a nominal consideration, and sold a 6.7% interest to one of the ~~construction contractors. Through~~effective date, Warrior Run will no longer sell its 67% ownership interest in AES Gener, the Company now has an effective 62% indirect economic interest in Alto Maipo. Additionally, certain construction milestones were amended and if Alto Maipo is unable to meet these milestones, there could be a material impactelectricity to the ~~financing and value~~offtaker, Potomac Edison, but will continue to provide capacity through May 31, 2024 in exchange for total proceeds of $357 million to be received in equal installments through January 2030. The previous expiration for the Warrior Run PPA was 2030. The Company is currently evaluating possible alternative uses for the facility once the PPA term expires on May 31, 2024. As of the ~~project. For additional information on risks regarding construction and development, refer to Item 1A.—Risk Factors~~—~~Our Business~~filing date, management believes the carrying amount of our long-lived assets at Warrior Run of $200 million is ~~Subject to Substantial Development Uncertainties~~ ~~of the 2016 Form 10-K.~~

Following the restructuring described above, the project continued to face construction difficulties including greater than expected costs and slower than anticipated productivity by construction contractors towards agreed-upon milestones. Furthermore, during the second quarter of 2017, as a result of the failure to perform by one of its construction contractors, Constructora Nuevo Maipo S.A. (“CNM”), Alto Maipo terminated CNM’s contract. Alto Maipo has hired a temporary replacement contractor to complete a portion of CNM’s work while the search for a permanent replacement contractor continues. Alto Maipo is currently a party to legal proceedings concerning the termination of CNM and related matters, including, but not limited to, Alto Maipo’s draws on letters of credit securing CNM’s performance under the parties’ construction contract totaling $73 million (the “LC Funds”). The LC Funds were collected by Alto Maipo and are available to be utilized for on-going construction costs, but CNM may require Alto Maipo to escrow the LC Funds. The Company cannot anticipate the outcome of the legal proceedings. As a result of the termination of CNM, Alto Maipo’s construction debt of $623 million and derivative liabilities of $139 million are in technical default and presented as current in the balance sheetrecoverable as of September 30, ~~2017.~~2023. However, it is reasonably possible that the estimate of undiscounted cash flows may no longer support the carrying value of our long-lived assets at Warrior Run in the near term resulting in the need to write down these assets to fair value.

~~Construction at~~

Regulatory

AES Maritza PPA Review — DG Comp is conducting a preliminary review of whether AES Maritza’s PPA with NEK is compliant with the ~~project is continuing~~European Union's State Aid rules. No formal investigation has been launched by DG

57 | The AES Corporation | September 30, 2023 Form 10-Q

Comp to date. However, AES Maritza has been engaging in discussions with the DG Comp case team and ~~Alto Maipo is working~~the Government of Bulgaria (“GoB”) to ~~resolve~~attempt to reach a negotiated resolution of the ~~challenges described above. Alto Maipo is seeking a permanent replacement contractor to complete CNM’s work,~~DG Comp’s review (“PPA Discussions”). The PPA Discussions are ongoing and the PPA continues to ~~maintain negotiations with lenders and other parties.~~remain in place. However, there can be no assurance that, ~~Alto Maipo~~in the context of the PPA Discussions, the other parties will ~~succeed~~not seek a prompt termination of the PPA.

We do not believe termination of the PPA is justified. Nevertheless, the PPA Discussions will involve a range of potential outcomes, including but not limited to the termination of the PPA and payment of some level of compensation to AES Maritza. Any negotiated resolution would be subject to mutually acceptable terms, lender consent, and DG Comp approval. At this time, we cannot predict the outcome of the PPA Discussions or when those discussions will conclude. Nor can we predict how DG Comp might resolve its review if the PPA Discussions fail to result in ~~these efforts and if there are further delays or cost overruns, or if Alto Maipo is unable to reach~~ an agreement concerning the agency’s review. AES Maritza believes that its PPA is legal and in compliance with the non-recourse lenders or other parties, there is a risk these lenders may seek to exercise remedies available as a result of the default noted above, or Alto Maipo may not be able to meet its contractual or

~~other obligations and may be unable to continue with the project. If any of the above occur, there could be a material impairment for the Company.~~

The carrying value of long-lived assets and deferred tax assets of Alto Maipo as of September 30, 2017 was approximately $1.4 billion and $60 million, respectively. Through its 67% ownership interest in AES Gener, the Parent Company has invested approximately $360 million in Alto Maipo and has an additional equity funding commitment of $55 million required as part of the March 2017 restructuring described above. Even though certain construction difficulties have not been formally resolved, construction costs continue to be capitalized as management believes the project is probable of completion. Management believes the carrying value of the long-lived asset group is recoverable and was not impaired as of September 30, 2017. In addition, management believes it is more likely than not the deferred tax assets will be realized; however, they could be reduced if estimates of future taxable income are decreased.

~~Eletropaulo~~

AES is continuing to pursue strategic options for Eletropaulo to reduce the Company’s exposure to the Brazilian distribution market. In preparation for this strategic shift, the Company is pursuing the transfer of Eletropaulo’s shares to the Novo Mercado, a listing segment of the Brazilian stock exchange with the highest governance standards, including the requirement for the company to trade exclusively in ordinary shares. On September 12, 2017, the required majority of Eletropaulo’s shareholders approved the conversion of the current preferred shares into ordinary shares and the transfer to the Novo Mercado. However, shareholders holding approximately 3 million shares, representing 2.7% of the total preferred shares, have indicated their preference to exercise withdrawal rights, which allows them to redeem their shares and receive a cash payment at book value for tendering their shares to Eletropaulo. Eletropaulo has now received all third party approvals to migrate to the Novo Mercado. The migration will be submitted to the Eletropaulo Board for confirmation that the costs associated with the exercise of the withdrawal rights are not significant enough to prevent migration. Once confirmed, and the preferred shares are converted into ordinary shares, AES will no longer control Eletropaulo. Losing control will result in deconsolidation of Eletropaulo and the recording of an equity method investment for the remaining interest held in Eletropaulo. As of September 30, 2017, Eletropaulo had cumulative translation losses attributable to AES of $452 million and pension losses attributable to AES in other comprehensive income of $243 million, both of which will be recognized in earnings if Eletropaulo is deconsolidated.

~~Changuinola Tunnel Leak~~

Increased water levels were noted in a creek near the Changuinola power plant, a 223 MW hydroelectric power facility in Panama. After the completion of an assessment, the Company has confirmed loss of water in specific sections of the tunnel. The plant is in operation and can generate up to its maximum capacity. Repairs will be needed to ensure the long term performance of the facility, during which time the affected units of the plant will be out of service. Subject to final inspection, the repairs may take up to 10 months to completeapplicable laws, and it ~~is expected~~will take all actions necessary to ~~commence during the first quarter of 2019. The Company has notified~~protect its ~~insurers of a potential claim and is asserting claims against its construction contractor.~~interests, whether through negotiated agreement or otherwise. However, there can be no assurance that this matter will be resolved favorably; if it is not, there could be a material adverse effect on the Company’s financial condition, results of ~~collection. The Company has not identified any indicators~~operations, and cash flows. As of ~~impairment and believes~~September 30, 2023, the carrying value of our long-lived assets at Maritza is $333 million.

AES Ohio Distribution Rate Case — On December 14, 2022, the ~~long-lived asset group~~PUCO issued an order on AES Ohio’s application to increase its base rates for electric distribution service to address, in part, increased costs of materials and labor and substantial investments to improve distribution structures. Among other matters, the order establishes a revenue increase of $76 million for AES Ohio’s base rates for electric distribution service. This increase went into effect on September 1, 2023, following the approval of AES Ohio’s electric security plan on August 9, 2023.

AES Ohio Electric Security Plan — On September 26, 2022, AES Ohio filed its latest Electric Security Plan (ESP 4) with the PUCO, which is ~~recoverable~~a comprehensive plan to enhance and upgrade its network and improve service reliability, provide greater safeguards for price stability, and continue investments in local economic development.

On April 10, 2023, AES Ohio entered into a Stipulation and Recommendation with the PUCO Staff and seventeen parties (the “Settlement”) with respect to AES Ohio’s ESP 4 application, and, on August 9, 2023, the PUCO approved the Settlement without modification. The Settlement provides for a three-year ESP without a rate stability charge, and, in addition to other items, provides for the following:

•A Distribution Investment Rider for the term of the ESP allowing for the timely recovery of distribution investments by AES Ohio based on a 9.999% return on equity, subject to revenue caps;

•The recovery of $66 million related to past expenditures by AES Ohio plus future carrying costs and the recovery of incremental vegetation management expenses up to certain annual limits during the term of ESP 4. During the third quarter of 2023, AES Ohio deferred $28 million of previously recognized purchased power costs and an additional $11 million of carrying costs related to this recovery; and

•Funding of programs for assistance to low-income customers and for economic development.

In addition, with the approval of ESP 4, the new distribution rates, which were approved in the December 14, 2022 PUCO Order on AES Ohio's distribution rate case application, went into effect in September 2023.

AES Indiana Regulatory Rate Review — AES Indiana filed a petition with the IURC on June 28, 2023 for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in reliability and resiliency improvements, and enhancements to its customer systems. AES Indiana's proposed revenue increase was $134 million annually, or 8.9%. We expect to receive an order from the IURC by the end of the second quarter of 2024. Pending approval from the IURC, new rates are anticipated to go into effect in the summer of 2024.

Foreign Exchange Rates

We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the USD, and currencies of the countries in which we operate.

The overall economic climate in Argentina has deteriorated, resulting in volatility and increased the risk that a further significant devaluation of the Argentine peso against the USD, similar to the devaluations experienced by the country in 2018, 2019, and 2023, may occur. A continued trend of peso devaluation could result in increased inflation, a deterioration of the country’s risk profile, and other adverse macroeconomic effects that could

58 | The AES Corporation | September 30, ~~2017.~~2023 Form 10-Q

significantly impact our results of operations. For additional information, refer to Item 3.—Quantitative and Qualitative Disclosures About Market Risk.

Impairments

Long-lived Assets and Current Assets Held-for-Sale—During the nine months ended September 30, ~~2017,~~2023, the Company recognized asset impairment expense of ~~$186 million at the Kazakhstan CHP and Hydroelectric plants, $66 million at the Stuart and Killen Stations at DPL, and $8 million at Tait Energy Storage in the PJM market.~~$352 million. See Note ~~14—~~15—Asset Impairment Expenseincluded in Item 1.—Financial Statements of this Form 10-Q for further information. After recognizing ~~these asset~~this impairment ~~expenses,~~expense, the carrying value of ~~the~~ long-lived ~~asset groups, including those~~assets and current assets held-for-sale that were assessed ~~and not impaired, excluding Alto Maipo,~~for impairment totaled ~~$809~~$667 million at September 30, ~~2017.~~2023.

Events or changes in circumstances that may necessitate ~~further~~ recoverability tests and potential impairments of long-lived assets may include, but are not limited to, adverse changes in the regulatory environment, unfavorable changes in power prices or fuel costs, increased competition due to additional capacity in the grid, technological advancements, declining trends in demand, evolving industry expectations to transition away from fossil fuel sources for generation, or an expectation it is more likely than not the asset will be disposed of before the end of its estimated useful life.

~~Functional Currency~~

~~Argentina~~ — In February 2017, the Argentina Ministry of Energy issued Resolution 19/2017, which established changes to the energy price framework. As a result of this resolution, tariffs are priced in USD rather than Argentine Pesos, and the retention of unpaid amounts and accumulation of receivables with CAMMESA was eliminated. Concurrent with the establishment of the new price framework, AES Argentina issued $300 million of bonds denominated in USD. Given these significant changes in economic facts and circumstances, the Company changed

~~the functional currency of the Argentina businesses from the Argentine Peso to the USD effective February 2017. Changes to the energy framework could have a material impact on the Company.~~

~~Chivor~~ — In May 2017, the Company repaid its outstanding USD denominated debt held at Chivor. In addition, the Company updated Chivor’s future financing strategy to align with Colombian Peso denominated operational cash flows of the business. Given these changes, the Colombian Peso is now regarded as the currency of the economic environment in which Chivor primarily operates. Therefore, the Company changed the functional currency of the Chivor business from USD to the Columbian Peso effective May 2017.

~~Foreign Exchange and Commodities~~

Our businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal, and environmental credits, and FX rates. Volatility in these prices and FX rates could have a material impact on our results. For additional information, refer to Item 3.—~~Quantitative and Qualitative Disclosures About Market Risk~~.

Environmental

The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company faces certain risks and uncertainties related to these 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)~~residuals) and certain air emissions, such as SO₂, NO_x, particulate matter, mercury, and ~~mercury.~~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 U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A.—Risk Factors—Our operations are subject to significant government regulation and could be adversely affected by changes in the law or regulatory schemes; Several of our businesses are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR; Our businesses are subject to stringent environmental laws, rules 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~~ Concerns about ~~greenhouse gas, or~~ GHG emissions and the potential risks associated with climate change have led to increased regulation and ~~are taking~~other actions ~~which~~that could ~~have a material adverse~~ impact on our ~~consolidated results of operations, financial condition and cash flows~~businesses included in the ~~2016~~2022 Form 10-K.

CSAPR—CSAPR addresses the “good neighbor” provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. The ~~following discussion~~CSAPR required significant reductions in SO2 and NOx emissions from power plants in many states in which subsidiaries of the Company operate. The Company is required to comply with the CSAPR in certain states, including Indiana and Maryland. The CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. The Company complies with CSAPR through operation of existing controls and purchases of allowances on the open market, as needed.

In October 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). The CSAPR Update Rule found that NOx ozone season emissions in 22 states (including Indiana and Maryland) affected the ability of downwind states to attain and maintain the 2008 ozone NAAQS, and, accordingly, the EPA issued federal implementation plans that both updated existing CSAPR NOx ozone season emission budgets for electric generating units within these states and implemented these budgets through modifications to the CSAPR NOx ozone season allowance trading program. Implementation started in the 2017 ozone season (May-September 2017). Affected facilities receive fewer ozone season NOx allowances in 2017 and later, possibly resulting in the need to purchase additional allowances. Following legal challenges to the CSAPR Update Rule, on April 30, 2021, the EPA issued the Revised CSAPR Update Rule. The Revised CSAPR Update Rule required affected EGUs within certain states (including Indiana and Maryland) to participate in a new trading program, the CSAPR NOx Ozone Season Group 3 trading program. These affected EGUs received fewer NOx Ozone Season allowances beginning in 2021.

On June 5, 2023, the EPA published a final Federal Implementation Plan to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule establishes a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and Maryland, and became effective during 2023. The FIP also includes enhancements to the revised Group 3 trading program, which include a dynamic budget setting process beginning in 2026, annual recalibration of the allowance bank to reflect changes to affected sources, a daily backstop

59 | The AES Corporation | September 30, 2023 Form 10-Q

emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels. It is too early to determine the impact of ~~environmental laws~~this final rule, but it may result in the need to purchase additional allowances or make operational adjustments.

While the Company's additional CSAPR compliance costs to date have been immaterial, the future availability of and ~~regulations on~~cost to purchase allowances to meet the ~~Company updates~~emission reduction requirements is uncertain at this time, but it could be material.

Mercury and Air Toxics Standard — In April 2012, the ~~discussion provided in Item 1.—Business—Environmental~~EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and ~~Land Use Regulations~~oil-fired electric utilities, known as “MATS”, became effective and AES facilities implemented measures to comply, as applicable. In June 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the ~~2016 Form 10-K.~~

~~Update to Greenhouse Gas Emissions Discussion~~ ~~— We refer~~CAA and subsequently remanded MATS to the ~~discussion in Item 1.—Business~~—~~United States Environmental~~EPA without vacatur. On May 22, 2020, the EPA published a final finding that it is not “appropriate and ~~Land~~-~~Use Regulations~~—~~Greenhouse Gas Emissions~~ ~~in the Company’s 2016 Form 10-K for a discussion of certain recent developments, including the EPA’s CO~~₂necessary” to regulate hazardous air pollutant emissions ~~rules for new~~from coal- and oil-fired electric generating units (EGUs) (reversing its prior 2016 finding), but that the EPA would not remove the source category from the CAA Section 112(c) list of source categories and would not change the MATS requirements. On March 6, 2023, the EPA published a final rule to revoke its May 2020 finding and reaffirm its 2016 finding that it is appropriate and necessary to regulate these emissions. On April 24, 2023, the EPA published a proposed rule to lower certain emissions limits and revise certain other aspects of MATS. It is too early to determine the potential impacts of this proposal rule.

Further rulemakings and/or ~~GHG NSPS, as well as~~proceedings are possible; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of the regulatory or judicial process, or its impact, if any, on our MATS compliance planning or ultimate costs.

Climate Change Regulation—On July 8, 2019, the EPA published the final Affordable Clean Energy (“ACE”) Rule which would have established CO₂ ~~emissions~~ emission rules for existing power plants ~~called~~under CAA Section 111(d) and would have replaced the CPP. Both the GHG NSPS and the CPP are being challenged by several states and industry groups in the D.C. Circuit. The challenges to the CPP have been fully briefed and argued, but oral arguments have not yet taken placeEPA's 2015 Clean Power Plan Rule (“CPP”). However, on ~~the GHG NSPS. On March 28, 2017, the EPA filed a motion in~~January 19, 2021, the D.C. Circuit ~~to hold~~vacated and remanded the ~~challenges to both~~ACE Rule. Subsequently, on June 30, 2022, the Supreme Court reversed the judgment of the D.C. Circuit Court and remanded for further proceedings consistent with its opinion holding that the “generation shifting” approach in the CPP ~~and~~exceeded the ~~GHG NSPS in abeyance in light~~authority granted to the EPA by Congress under Section 111(d) of ~~an Executive Order signed~~ the ~~same day. On April 28, 2017,~~CAA. As a result of the June 30, 2022 Supreme Court decision, on October 27, 2022, the D.C. Circuit issued ~~orders~~a partial mandate, holding ~~the~~pending challenges to ~~both rules~~the ACE Rule in abeyance for 60 days, with subsequent extensions granted by the court. The most recent extension was set to expire on October 10, 2017. EPA filed a status report and requested that the court continue to hold the case in abeyance in light of EPA’s announcement that it would propose to repeal the CPP in accordance with an Executive Order that instructedwhile the EPA ~~Administrator to review the GHG NSPS and CPP and “if appropriate...as soon as practicable...publish for notice and comment proposed rules suspending, revising, or rescinding those rules.”~~developed a replacement rule. On ~~October 16, 2017, the~~May 23, 2023, EPA published ~~in the Federal Register~~ a proposed rule that would ~~rescind~~vacate the ~~CPP. Some~~ACE Rule, establish emissions guidelines in the form of CO2 emissions limitations for certain existing electric generating units (EGUs) and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operation to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s. We are still reviewing the proposed rule and the impact of the proposed rule, the results of further proceedings, and potential future greenhouse gas emissions regulations remain uncertain but could be material.

Waste Management — On October 19, 2015, an EPA rule regulating CCR under the Resource Conservation and Recovery Act as nonhazardous solid waste became effective. The rule established nationally applicable minimum criteria for the disposal of CCR in new and currently operating landfills and surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. The primary enforcement mechanisms under this regulation would be actions commenced by the states and private lawsuits. On December 16, 2016, the Water Infrastructure Improvements for the Nation Act ("WIN Act") was signed into law. This includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a possible federal permit program. If this rule is finalized before Indiana or Puerto Rico establishes a state-level CCR permit program, AES CCR units in those locations could eventually be required to apply for a federal CCR permit from the EPA. The EPA has indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. On August 28, 2020, the EPA published final amendments to the CCR Rule titled "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," that, among other amendments, required certain CCR units to cease waste receipt and initiate closure by April 11, 2021. The CCR Part A Rule also allowed for extensions of the April 11, 2021 deadline if the EPA determines certain criteria are met. Facilities seeking such an extension were required to submit a demonstration to the EPA by November 30, 2020. On January 11, 2022, the EPA released the first in a series of proposed determinations regarding CCR Part A Rule demonstrations and compliance-related letters notifying certain other facilities of their compliance obligations under the federal CCR regulations. The determinations and letters

60 | The AES Corporation | September 30, 2023 Form 10-Q

include interpretations regarding implementation of the CCR Rule. On April 8, 2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. It is too early to determine the direct or indirect impact of these letters or any determinations that may be made.

On May 18, 2023, EPA published a proposed rule that would expand the scope of CCR units regulated by the CCR Rule to include inactive surface impoundments at inactive generating facilities as well as additional inactive and closed landfills and certain other accumulations of CCR.We are still reviewing the proposal and it is too early to determine the potential impact.

The CCR rule, current or proposed amendments to or interpretations of the CCR rule, the results of groundwater monitoring data, or the outcome of CCR-related litigation could have a material impact on our business, financial condition, and results of operations. AES Indiana would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard.

Cooling Water Intake —The Company's facilities are subject to a variety of rules governing water use and discharge. In particular, the Company's U.S. facilities are subject to the CWA Section 316(b) rule issued by the EPA effective in 2014 that seeks to protect fish and other aquatic organisms drawn into cooling water systems at power plants and other facilities. These standards require affected facilities to choose among seven BTA options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible that this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility to increase generation capacity are required to reduce both impingement and entrainment. It is not yet possible to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.

AES Southland's current plan is to comply with the SWRCB OTC Policy by shutting down and permanently retiring all existing generating units at AES Alamitos, AES Huntington Beach, and AES Redondo Beach that utilize OTC by the compliance dates included in the OTC Policy. On August 15, 2023, the State Water Board considered the SACCWIS recommendation and adopted an amendment to the OTC Policy that established a final compliance date of December 31, 2026 for the Alamitos and Huntington Beach facilities. This extension is contingent upon the facilities participating in the Strategic Reserve established by AB 205.

The Company’s California subsidiaries have signed 20-year term PPAs with Southern California Edison for the new generating capacity, which have been approved by the California Public Utilities Commission. Construction of new generating capacity began in June 2017 at AES Huntington Beach and July 2017 at AES Alamitos. The new air-cooled combined cycle gas turbine generators and battery energy storage systems were constructed at the AES Alamitos and AES Huntington Beach generating stations. The new air-cooled combined cycle gas turbine generators at the AES Alamitos and AES Huntington Beach generating stations began commercial operation in early 2020 and there is currently no plan to replace the OTC generating units at the AES Redondo Beach generating station following the retirement. Certain OTC units were required to be retired in 2019 to provide interconnection capacity and/or emissions credits prior to startup of the new generating units, and the remaining AES OTC generating units in California will be shutdown and permanently retired by the OTC Policy compliance dates for these units. The SWRCB OTC Policy required the shutdown and permanent retirement of all remaining OTC generating units at AES Alamitos, AES Huntington Beach, and AES Redondo Beach by December 31, 2020. The initial amendment extended the deadline for shutdown and retirement of AES Alamitos and AES Huntington Beach’s remaining OTC generating units to December 31, 2023 and extended the deadline for shutdown and retirement of AES Redondo Beach’s remaining OTC generating units to December 31, 2021 (the “AES Redondo Beach Extension”). In October 2020, the cities of Redondo Beach and Hermosa Beach filed a state court lawsuit challenging the AES Redondo Beach Extension. AES opposed the action and the court granted an order dismissing the matter. The case remains open subject to the resolution of counter claims between parties other than AES. Plaintiffs have initiated an additional challenge to the permit, and the outcome of that lawsuit is unclear. On March 16, 2021 the SACCWIS released their draft 2021 report to SWRCB. The report summarizes the State of California’s current electrical grid reliability needs and recommended a two-year extension to the compliance schedule for AES Redondo Beach to address system-wide grid reliability needs. The SWRCB public hearing regarding the final decision on the amendment of the OTC policy was held on October 19, 2021 and the Board voted in favor of extending the compliance date for AES Redondo Beach to December 31, 2023. The AES Redondo Beach NPDES permit has been administratively extended. On September 30, 2022, the Statewide Advisory Committee on Cooling Water Intake Structures approved a recommendation to the SWRCB to consider an extension of the OTC compliance dates for AES Huntington Beach, LLC and AES Alamitos, LLC, to December 31, 2026, in support of grid

61 | The AES Corporation | September 30, 2023 Form 10-Q

reliability. SWRCB released a draft OTC Policy amendment early in 2023 to be heard by the SWRCB on March 7, 2023. The final decision from SWRCB is expected during the second half of 2023.

Power plants are required to comply with the more stringent of state or federal requirements. At present, the California state requirements are more stringent and have earlier compliance dates than the federal EPA requirements, and are therefore applicable to the Company's California assets.

Challenges to the federal EPA's rule were filed and consolidated in the U.S. Court of Appeals for the Second Circuit, although implementation of the rule was not stayed while the challenges proceeded. On July 23, 2018, the U.S. Court of Appeals for the Second Circuit upheld the rule. The Second Circuit later denied a petition by environmental groups for rehearing. The Company anticipates that compliance with CWA Section 316(b) regulations and associated costs could have ~~opposed EPA’s most recent request to continue to hold~~a material impact on our consolidated financial condition or results of operations.

Water Discharges — In June 2015, the ~~CPP appeals in abeyance~~EPA and the ~~D.C. Circuit has~~U.S. Army Corps of Engineers ("the Agencies") published a rule defining federal jurisdiction over waters of the U.S., known as the "Waters of the U.S." (“WOTUS”) rule. WOTUS defines the geographic reach and authority of the Agencies to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the proper standard for how to properly determine whether a wetland or stream that is not ~~yet acted upon EPA’s request.~~

~~By order of~~navigable is considered a WOTUS. On May 25, 2023, the U.S. Supreme Court rendered a decision (“Decision”) in the ~~CPP has been stayed pending resolution~~case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. This decision provides a clear standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not federally jurisdictional.

On September 8, 2023, the Agencies published final rule amendments in the Federal Register to amend the final “Revised Definition of ‘Waters of the ~~challenges~~United States’” rule. This final rule conforms the definition to the ~~rule. Due~~definition adopted in the Decision. The Agencies have amended key aspects of the regulatory text to conform the rule to the ~~future uncertainty~~Decision. It is too early to determine whether the outcome of ~~the CPP, we cannot at this time determine the impact on our operations~~litigation or ~~consolidated financial results, but we believe the cost to comply with the CPP, should it be upheld and implemented in its~~ current or a substantially similar form, could be material. The GHG NSPS remains in effect at this time, and, absent further action from the EPA that rescinds or substantively revises the NSPS, it could impact any Company plansfuture revisions to ~~construct and/or modify or reconstruct electric generating units in some locations, which~~rules interpreting federal jurisdiction over WOTUS may have a material impact on our business, financial condition, or results of operations.

~~Updates to Water Discharges Regulations Discussion~~ ~~— As further discussed in Item 1.—Business~~—~~United States Environmental and Land~~-~~Use Regulations~~—~~Water Discharges~~ ~~in the Company’s 2016 Form 10-K,~~In November 2015, the EPA published its final ~~effluent limitations guideline (“ELG”)~~ELG rule ~~in November 2015~~ to reduce toxic pollutants discharged

into waters of the ~~United States~~U.S. by steam-electric power ~~plants.~~plants through technology applications. These effluent limitations for existing and new sources include dry handling of fly ash, closed-loop or dry handling of bottom ash, and more stringent effluent limitations for flue gas desulfurization wastewater. ~~The required compliance time lines for existing sources was~~AES Indiana Petersburg has installed a dry bottom ash handling system in response to ~~be established between November 1, 2018~~the CCR rule and ~~December 31, 2023. On September 18, 2017,~~wastewater treatment systems in response to the ~~EPA published a final rule delaying certain compliance dates~~NPDES permits in advance of the ELG ~~rule for two years while it administratively reconsiders~~compliance date. Other U.S. businesses already include dry handling of fly ash and bottom ash and do not generate flue gas desulfurization wastewater. Following the rule. While we are still evaluating the effects of the rule, we anticipate that the implementation of its current requirements could have a material adverse effect on our results of operations, financial condition and cash flows, and a postponement or reconsideration of the rule that leads to less stringent requirements would likely offset some or all of the adverse effects of the rule.

~~As further discussed in Item 1.—Business~~—~~United States Environmental and Land~~-~~Use Regulations~~—~~Water Discharges~~ ~~in the Company’s 2016 Form 10-K and in Item 1.—Management’s Discussion and Analysis~~—~~Key Trends and Uncertainties~~—~~Updates to Water Discharge~~s ~~Discussion~~ in the Company’s Form 10-Q for the fiscal quarter ended March 31, 2017, the EPA published a final rule in June 2015 defining federal jurisdiction over waters of the U.S. This rule, which became effective on August 28, 2015, may expand or otherwise change the number and types of waters or features subject to federal permitting. On October 9, 2015, the2019 U.S. Court of Appeals ~~for the Sixth Circuit (the “Sixth Circuit”) issued an order to temporarily stay the “Waters~~vacatur and remand of portions of the ~~U.S.”~~2015 ELG rule ~~nationwide.~~related to leachate and legacy water, on March 29, 2023, EPA published a proposed rule revising the 2020 Reconsideration Rule. The ~~Sixth Circuit’s stay remains in place pending the~~proposed rule would establish new best available technology economically achievable effluent limits for flue gas desulfurization wastewater, bottom ash treatment water, and combustion residual leachate. It is too early to determine whether any outcome of ~~various legal challenges, including a challenge~~litigation or current or future revisions to the ~~U.S. Supreme Court that will determine whether the Sixth Circuit has jurisdiction over the rule. On June 27, 2017, the EPA proposed a~~ELG rule that would rescind the “Waters of the U.S.” rule and re-codify the definition of “Waters of the United States” that existed prior to the 2015 rule. We cannot predict the outcome of this judicial or regulatory process, but if the “Waters of the United States” rule is ultimately implemented in its current or substantially similar form and survives the legal challenges, it couldmight have a material impact on our business, financial condition, orand results of operations.

Capital Resources and Liquidity

Overview—

As of September 30, ~~2017,~~2023, the Company had unrestricted cash and cash equivalents of ~~$1.4~~$1.8 billion, of which ~~$81~~$51 million was held at the Parent Company and qualified holding companies. The Company ~~also~~ had ~~$563~~$538 million in short-term investments, held primarily at ~~subsidiaries. In addition, we had~~subsidiaries, and restricted cash and debt service reserves of ~~$1.2 billion.~~$570 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of ~~$17.1~~$21.6 billion and ~~$5.0~~$5.6 billion, respectively. Of the $3.1 billion of our current non-recourse debt, $2.7 billion was presented as such because it is due in the next twelve months and $332 million relates to debt considered in default. Defaults at AES Puerto Rico are covenant and payment defaults, for which forbearance and standstill agreements have been signed. See Item 2.—Management's Discussion and Analysis of Financial Condition and Results of Operations—Key Trends and Uncertainties—Macroeconomic and Political—Puerto Rico for additional detail. All other defaults are not payment defaults but are instead technical defaults triggered by failure to comply with covenants or other requirements contained in the non-recourse debt documents. As of September 30, 2023, the Company also had $775 million outstanding related to supplier financing arrangements, which are classified as Accrued and other

62 | The AES Corporation | September 30, 2023 Form 10-Q

liabilities.

We expect current maturities of non-recourse debt, recourse debt, and amounts due under supplier financing arrangements to be repaid from net cash provided by operating activities of the subsidiary to which the ~~debt~~liability relates, through opportunistic refinancing activity, or some combination thereof. We have $4$700 million ofin recourse debt which matures within the next twelve ~~months.~~months, as well as amounts due under supplier financing arrangements, of which $607 million has a Parent Company guarantee. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions, or otherwise when management believes that such securities are attractively priced. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, and other factors. The amounts involved in any such repurchases may be material.

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. 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.

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. Presently, the Parent Company’s only material unhedged exposure to variable interest rate debt relates to ~~indebtedness under its $522~~$700 million ~~outstanding secured~~in senior unsecured term ~~loan due 2022~~loans. Additionally, commercial paper issuances are short term in nature and ~~drawings~~subject the Parent Company to interest rate risk at the time of ~~$540 million under its senior secured credit facility.~~refinancing the paper. On a consolidated basis, of the Company’s ~~$22.0~~$27.5 billion of total gross debt outstanding as of September 30, ~~2017,~~2023, approximately ~~$4.1~~$7.2 billion bore interest at variable rates that were not

subject to a derivative instrument which fixed the interest rate. Brazil holds ~~$1.9~~$2.3 billion of our floating rate non-recourse exposure as ~~we have no ability to fix local debt interest rates efficiently.~~variable rate instruments act as a natural hedge against inflation in Brazil.

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. AtAs of September 30, ~~2017,~~2023, 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 ~~$833 million~~$2.4 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).

~~As a result of the Parent Company’s below investment grade rating,~~Some 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. AtAs of September 30, ~~2017,~~2023, we had ~~$125~~$248 million in letters of credit under bilateral agreements, $136 million in letters of credit outstanding provided under our unsecured credit ~~facility~~facilities, and $9$39 million in letters of credit outstanding provided under our ~~senior secured~~revolving credit facility. These letters of credit operate to guarantee performance relating to certain project development and construction activities and business operations. During the quarter ended September 30, ~~2017,~~2023, the Company paid letter of credit fees ranging from ~~0.25%~~1% to ~~2.25%~~3% per annum on the outstanding amounts.

63 | The AES Corporation | September 30, 2023 Form 10-Q

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. 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.

Long-Term Receivables—

As of September 30, ~~2017,~~2023, the Company had approximately ~~$238~~$118 million of gross accounts receivable classified as ~~Noncurrent assets—other, primarily related to certain of its generation businesses in Argentina and the United States, and its utility business in Brazil.~~Other noncurrent assets. These noncurrent receivables mostly consist of accounts receivable in ~~Argentina~~the U.S. and Chile that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond September 30, ~~2018,~~2024, or one year from the latest balance sheet date. ~~The majority~~Noncurrent receivables in the U.S. pertain to the sale of ~~Argentinian~~the Redondo Beach land. Noncurrent receivables ~~have been converted into long-term financing for~~in Chile pertain primarily to revenues recognized on regulated energy contracts that were impacted by the ~~construction of power plants.~~Stabilization Funds created by the Chilean government. See Note 5—Financing Receivables ~~included~~ in ~~Part I—~~Item 1.—Financial Statements of this Form 10-Q and Item 1.7.—~~Business—Argentina—Regulatory Framework~~Management's Discussion and Analysis of Financial Condition and Results of Operation—Key Trends and Uncertainties—Macroeconomic and Political—Chileincluded in our ~~2016~~2022 Form 10-K for further information.

As of September 30, 2023, the Company had approximately $1.1 billion of loans receivable primarily related to a facility constructed under a build, operate, and transfer contract in Vietnam. This loan receivable represents contract consideration related to the construction of the facility, which was substantially completed in 2015, and will be collected over the 25-year term of the plant’s PPA. As of September 30, 2023, $105 million of the loan receivable balance was classified as Other current assets and $990 million was classified as Loan receivable on the Condensed Consolidated Balance Sheets. See Note 13—Revenue in Item 1.—Financial Statements of this Form 10-Q for further information.

Cash Sources and Uses

The primary sources of cash for the Company in the nine months ended September 30, 2023 were debt financings, cash flows from operating activities, purchases under supplier financing arrangements, and sales of short-term investments. The primary uses of cash in the nine months ended September 30, 2023 were repayments of debt, capital expenditures, repayments of obligations under supplier financing arrangements, and purchases of short-term investments.

The primary sources of cash for the Company in the nine months ended September 30, 2022 were debt financings, cash flows from operating activities, and sales of short-term investments. The primary uses of cash in the nine months ended September 30, 2022 were repayments of debt, capital expenditures, purchases of short-term investments, acquisitions of noncontrolling interests, and purchases of emissions allowances.

64 | The AES Corporation | September 30, 2023 Form 10-Q

A summary of cash-based activities are as follows (in millions):


	Nine Months Ended September 30,
Cash Sources:	2023		2022
Borrowings under the revolving credit facilities and commercial paper program	$	33,981	$	4,214
Net cash provided by operating activities	2,309		1,649
Issuance of non-recourse debt	1,784		3,554
Issuance of recourse debt	1,400		200
Purchases under supplier financing arrangements	1,307		299
Sale of short-term investments	1,002		654
Sales to noncontrolling interests	371		336

Contributions from noncontrolling interests	63		122




Other	101		132
Total Cash Sources	$	42,318	$	11,160

Cash Uses:
Repayments under the revolving credit facilities and commercial paper program	$	(32,168)	$	(2,782)
Capital expenditures	(5,295)		(2,711)
Repayments of non-recourse debt	(1,262)		(1,772)
Repayments of obligations under supplier financing arrangements	(1,099)		(234)
Purchase of short-term investments	(764)		(1,091)
Dividends paid on AES common stock	(333)		(316)
Acquisitions of business interests, net of cash and restricted cash acquired	(311)		(114)
Distributions to noncontrolling interests	(173)		(129)
Purchase of emissions allowances	(161)		(415)

Contributions and loans to equity affiliates	(147)		(202)
Acquisitions of noncontrolling interests	(12)		(541)


Other	(345)		(303)
Total Cash Uses	$	(42,070)	$	(10,610)
Net increase in Cash, Cash Equivalents, and Restricted Cash	$	248	$	550

Consolidated Cash Flows

The following table reflects the changes in operating, investing, and financing cash flows for the comparative ~~three and~~ nine month ~~periods~~period (in millions):


	Nine Months Ended September 30,
Cash flows provided by (used in):	2023		2022		$ Change
Operating activities	$	2,309	$	1,649	$	660
Investing activities	(5,673)		(3,825)		(1,848)
Financing activities	3,740		2,863		877

Three Months Ended September 30, Nine Months Ended September 30,
Cash flows provided by (used in): 2017 2016 $ Change 2017 2016 $ Change
Operating activities $ 735
$ 819
$ (84 ) $ 1,689
$ 2,182
$ (493 )
Investing activities (1,174 ) (543 ) (631 ) (2,282 ) (1,869 ) (413 )
Financing activities 614
(215 ) 829
678
(258 ) 936

Operating Activities

~~The following table summarizes the key components of our consolidated~~Net cash provided by operating ~~cash flows (in millions):~~

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change 2017 2016 $ Change
Net income (loss) $ 261
$ 229
$ 32
$ 509
$ (84 ) $ 593
Depreciation and amortization 303
291
12
884
877
7
Impairment expenses 2
79
(77 ) 260
475
(215 )
Loss on extinguishment of debt 49
16
33
44
12
32
Other adjustments to net income 5
14
(9 ) 171
438
(267 )
Non-cash adjustments to net income (loss) 359
400
(41 ) 1,359
1,802
(443 )
Net income, adjusted for non-cash items $ 620
$ 629
$ (9 ) $ 1,868
$ 1,718
$ 150
Net change in operating assets and liabilities ⁽¹⁾
$ 115
$ 190
$ (75 ) $ (179 ) $ 464
$ (643 )
Net cash provided by operating activities⁽²⁾
$ 735
$ 819
$ (84 ) $ 1,689
$ 2,182
$ (493 )

~~_____________________________~~


⁽¹⁾	~~Refer to the table below for explanations of the variance in operating assets and liabilities (also generally referred to as “working capital” in the~~ ~~Segment Operating Cash Flow Analysis~~).


⁽²⁾	~~Amounts included in the table above include the results of discontinued operations, where applicable.~~

Net change in operating assets and liabilities decreased by $75 million for the three months ended September 30, 2017, compared to the three months ended September 30, 2016, which was primarily driven by (in millions):

Increases in:
Accounts receivable, primarily at Gener and Itabo $ (128 )
Prepaid expenses and other current assets, primarily short-term regulatory assets at Eletropaulo and Sul (213 )
Inventory, primarily at IPL, Eletropaulo, Itabo and Gener (47 )
Accounts payable and other current liabilities, primarily at Eletropaulo 306
Other 7
Total decrease in cash from changes in operating assets and liabilities $ (75 )

~~Net change in operating assets and liabilities decreased by $643~~activities increased $660 million for the nine months ended September 30, ~~2017,~~2023, compared to the nine months ended September 30, ~~2016, which was~~2022.

Operating Cash Flows

(in millions)

(1)The change in adjusted net income is defined as the variance in net income, net of the total adjustments to net income as shown on the Condensed Consolidated Statements of Cash Flows in Item 1—Financial Statements of this Form 10-Q.

(2)The change in working capital is defined as the variance in total changes in operating assets and liabilities as shown on the Condensed Consolidated Statements of Cash Flows in Item 1—Financial Statements of this Form 10-Q.

65 | The AES Corporation | September 30, 2023 Form 10-Q

•Adjusted net income decreased $106 million primarily ~~driven~~due to lower margins at our Energy Infrastructure SBU and an increase in interest expense; partially offset by ~~(in millions):~~higher margins at our Utilities and Renewables SBUs and an increase in interest income.

•Working capital requirements decreased $766 million, primarily due to a decrease in accounts receivable resulting from higher collections, decreases in inventory and accounts payable due to lower inventory purchases at lower prices, and a decrease in derivative assets; partially offset by the receivables under the Warrior Run PPA termination agreement and an increase in lease incentives.

Increases in:
Accounts receivable, primarily at Maritza and Eletropaulo $ (614 )
Prepaid expenses and other current assets, primarily short-term regulatory assets at Eletropaulo and Sul (530 )
Inventory, primarily at Gener, IPL and DPL (102 )
Accounts payable and other current liabilities, primarily at Eletropaulo, Maritza and Gener 729
Income taxes payable, net, and other taxes payable, primarily at Gener,Tietê and Eletropaulo 266
Decreases in:
Other liabilities, primarily due to higher deferrals into regulatory liabilities related to energy costs in 2016 compared to 2017 at Eletropaulo (363 )
Other (29 )
Total decrease in cash from changes in operating assets and liabilities $ (643 )

Investing Activities

Net cash used in investing activities increased ~~by $631 million for the three months ended September 30, 2017, compared to the three months ended September 30, 2016, which was primarily driven by (in millions):~~

Decreases In:
Capital expenditures ⁽¹⁾
$ 51
Short-term investments 221
Increases in:
Acquisitions of businesses, net of cash acquired, and equity method investees (related to the acquisitions of sPower and Alto Sertão II in 2017, partially offset by the acquisition of Distributed Energy in 2016) (554 )
Restricted cash, debt service and other assets (318 )
Other investing activities (31 )
Total increase in net cash used in investing activities $ (631 )

~~_____________________________~~


⁽¹⁾	~~Refer to the tables below for a breakout of capital expenditures by type and primary business driver.~~

~~Net cash used in investing activities increased by $413 million~~$1.8 billion for the nine months ended September 30, ~~2017,~~2023, compared to the nine months ended September 30, ~~2016, which was~~2022.

Investing Cash Flows

(in millions)

•Acquisitions of business interests increased $197 million, primarily due to the acquisitions of Bellefield and Bolero Solar Park at AES Clean Energy Development and AES Andes, respectively, partially offset by the prior year acquisition of Agua Clara in the Dominican Republic.

•Cash used for short-term investing activities decreased $675 million, primarily as a result of higher short-term investment sales in 2023 to fund the capital expenditures of our renewable projects.

•Purchases of emissions allowances decreased $254 million, primarily in Bulgaria as a result of lower CO2 purchases due to lower production.

•Capital expenditures increased $2.6 billion, discussed further below.

Capital Expenditures

(in millions)

66 | The AES Corporation | September 30, 2023 Form 10-Q

(1)Growth expenditures generally include expenditures related to development projects in construction, expenditures that increase capacity of a facility beyond the original design, and investments in general load growth or system modernization.

(2)Maintenance expenditures generally include expenditures that are necessary to maintain regular operations or net maximum capacity of a facility.

(3)Environmental expenditures generally include expenditures to comply with environmental laws and regulations, expenditures for safety programs and other expenditures to ensure a facility continues to operate in an environmentally responsible manner.

•Growth expenditures increased $2.3 billion, primarily driven by ~~(in millions):~~an increase in U.S. renewable projects.

Decreases in:
Capital expenditures ⁽¹⁾
$ 183
Proceeds from the sales of businesses, net of cash sold, and equity method investments (primarily related to the sales of DPLER, Kelanitissa and Jordan in 2016 and the receipt of contingent sales proceeds in 2016 from the sale of Cameroon, partially offset by the sale of Kazakhstan CHPs in 2017) (118 )
Short-term investments 319
Increases in:
Acquisitions of businesses, net of cash acquired, and equity method investees (related to the acquisitions of sPower and Alto Sertão II in 2017, partially offset by the acquisition of Distributed Energy in 2016) (545 )
Restricted cash, debt service and other assets (188 )
Other investing activities (64 )
Total increase in net cash used in investing activities $ (413 )

~~_____________________________~~


⁽¹⁾	~~Refer to the tables below for a breakout of capital expenditures by type and primary business driver.~~

~~Capital Expenditures~~

~~The following table summarizes the Company's capital~~•Maintenance expenditures increased $247 million, primarily due to higher transmission and distribution and renewable project investments at our Utilities SBU and increased expenditures for ~~growth investments, maintenance,~~hydro and ~~environmental reported in investing cash activities for the periods indicated (in millions):~~wind plants at our Renewables SBU.

•Environmental expenditures increased $1 million, with no material drivers.

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change 2017 2016 $ Change
Growth Investments $ (310 ) $ (339 ) $ 29
$ (1,109 ) $ (1,126 ) $ 17
Maintenance (137 ) (141 ) 4
(423 ) (458 ) 35
Environmental ⁽¹⁾
(17 ) (35 ) 18
(55 ) (186 ) 131
Total capital expenditures $ (464 ) $ (515 ) $ 51
$ (1,587 ) $ (1,770 ) $ 183

~~_____________________________~~


⁽¹⁾	~~Includes both recoverable and non-recoverable environmental capital expenditures. See~~ ~~Non-GAAP Measures~~—~~Free Cash Flow~~ ~~for more information.~~

Cash used for capital expenditures decreased by $51 million for the three months ended September 30, 2017, compared to the three months ended September 30, 2016, which was primarily driven by (in millions):

Decreases in:
Growth expenditures at the Andes SBU, primarily due to slower than anticipated productivity by construction contractors at Alto Maipo $ 137
Maintenance and environmental expenditures at the US SBU, primarily due to lower spending at IPALCO on the NPDES compliance and Harding Street refueling projects and decreased spending on CCR compliance 19
Growth expenditures at the Eurasia SBU, primarily due to timing of payments to contractors for Unit 3 expansion at Masinloc 18
Increases in:
Growth expenditures at the US SBU, primarily due to increased spending at Southland repowering (130 )
Other capital expenditures 7
Total decrease in net cash used for capital expenditures $ 51

Cash used for capital expenditures decreased by $183 million for the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016, which was primarily driven by (in millions):

Decreases in:
Growth expenditures at the Andes SBU, primarily due to the completion of the Cochrane project $ 85
Maintenance and environmental expenditures at the US SBU, primarily due to lower spending at IPALCO on the NPDES and MATS compliance and Harding Street refueling projects, decreased spending on CCR compliance and also, decreased spending at DPL on Stuart and Killen facilities due to planned plant closures 152
Increases in:
Growth expenditures at the US SBU, primarily due to increased spending at Southland repowering and various Distributed Energy projects, offset by lower spending related to CCGT at IPALCO (18 )
Growth, maintenance and environmental expenditures at the Brazil SBU, primarily due to the quality indicator recovery plan and increase in productivity commitments at Eletropaulo, offset by absence of spending at Sul due to its sale in 2016 (43 )
Other capital expenditures 7
Total decrease in net cash used for capital expenditures $ 183

Financing Activities

Net cash provided by financing activities increased ~~$829 million for the three months ended September 30, 2017, compared to the three months ended September 30, 2016, which was primarily driven by (in millions):~~

Increases in:
Borrowings under the revolving credit facilities, at the Parent Company $ 384
Issuance of recourse debt at the Parent Company ⁽¹⁾
204
Issuance of non-recourse debt, primarily at the US, MCAC, and Brazil SBUs ⁽¹⁾
204
Proceeds from sale of noncontrolling interests related to the sell down of Dominican Republic business in 2017 60
Other financing activities (23 )
Total increase in net cash provided by financing activities $ 829

~~_____________________________~~


⁽¹⁾	~~See Note 7—Debtin Item 1—Financial Statements~~ ~~of this Form 10-Q for more information regarding significant non-recourse debt transactions.~~

~~Net cash provided by financing activities increased $936~~$877 million for the nine months ended September 30, ~~2017,~~2023, compared to the nine months ended September 30, ~~2016, which was~~2022.

Financing Cash Flows

(in millions)

See Notes 7—Debt and 11—Equityin Item 1—Financial Statements of this Form 10-Q for more information regarding significant debt and equity transactions.

•The $1.2 billion impact from recourse debt is primarily ~~driven by (in millions):~~

Decreases in:
Proceeds from the sale of redeemable stock of subsidiaries at IPALCO $ (134 )
Increases in:
Borrowings under the revolving credit facilities, primarily at the Parent Company and net decrease in repayment at the US SBU 415
Issuance of non-recourse debt, primarily at the Brazil, MCAC, and US SBUs⁽¹⁾
574
Proceeds from sale of noncontrolling interests related to the sell down of Dominican Republic business in 2017 60
Other financing activities 21
Total increase in net cash provided by financing activities $ 936

~~_____________________________~~


⁽¹⁾	~~See Note 7—Debtin Item 1—Financial Statements~~ ~~of this Form 10-Q for more information regarding significant non-recourse debt transactions.~~

~~Segment Operating Cash Flow Analysis~~

~~Operating Cash Flow by SBU~~ ⁽¹⁾

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 $ Change 2017 2016 $ Change
US SBU $ 241
$ 291
$ (50 ) $ 544
$ 691
$ (147 )
Andes SBU 110
157
(47 ) 338
300
38
Brazil SBU 194
173
21
463
582
(119 )
MCAC SBU 141
142
(1 ) 275
202
73
Eurasia SBU 188
171
17
475
729
(254 )
Corporate and Other (139 ) (115 ) (24 ) (406 ) (322 ) (84 )
Total SBUs $ 735
$ 819
$ (84 ) $ 1,689
$ 2,182
$ (493 )

~~_____________________________~~


⁽¹⁾	~~Operating cash flow as presented above include the effects of intercompany transactions with other segments except for interest, tax sharing, charges for management fees and transfer pricing.~~

~~US SBU~~

~~The decrease~~due to the issuance of senior notes due in ~~Operating Cash Flow of $50 million was driven primarily~~2028 by the ~~following (in millions):~~

US SBU Q3 2017 vs. Q3 2016 (QTD)
Lower operating margin, net of lower depreciation of $4 million $ (9 )
Higher payments for inventory purchases primarily due to inventory optimization efforts at DPL and IPL that occurred in 2016 (20 )
Timing of payments for general accounts payable at DPL (13 )
Timing of interest payments primarily at DPL and IPL (13 )
Other 5
Total US SBU Operating Cash Decrease $ (50 )

~~The decrease in Operating Cash Flow~~Parent Company, and the issuance of ~~$147 million was driven primarily~~a bridge loan, fully guaranteed by the ~~following (in millions):~~Parent Company, at AES Clean Energy.

US SBU Q3 2017 vs. Q3 2016 (YTD)
Lower operating margin, net of lower depreciation of $26 $ (41 )
Higher payments for inventory purchases primarily due to inventory optimization efforts at DPL and IPL that occurred in 2016 (66 )
Timing of payments for purchased power and general accounts payable at DPL (42 )
Timing of interest payments primarily at DPL and IPL (19 )
Lower collections at DPL, primarily due to the settlement of receivable balances at DPLER upon its sale in Q1 2016 (11 )
Higher collections at IPL, primarily due to higher A/R balances in December 2016 resulting from favorable weather and the 2016 rate order 32
Total US SBU Operating Cash Decrease $ (147 )

~~ANDES SBU~~

•The ~~decrease in Operating Cash Flow of $47~~$840 million ~~was driven~~impact from non-recourse revolvers is primarily ~~by the following (in millions):~~

Andes SBU Q3 2017 vs. Q3 2016 (QTD)
Lower operating margin, net of increased depreciation of $7 $ (45 )
Increase in other working capital requirements primarily due to delay in collections at Gener (59 )
Increase in collections of financing receivables in Argentina, resulting primarily from the commencement of commercial operations at the Guillermo Brown plant and the impact of major maintenance in 2016 44
Environmental tax accruals in Chile impacting margin but not operating cash flow 13
Total Andes SBU Operating Cash Decrease $ (47 )

~~The~~due to an increase in ~~Operating Cash Flow~~borrowings at our Renewables SBU to fund capital expenditures of ~~$38~~renewable projects.

•The $529 million ~~was driven~~impact from acquisitions of noncontrolling interests is mainly due to the acquisition of an additional 32% ownership interest in AES Andes in 2022.

•The $143 million impact from supplier financing arrangements is primarily due to higher net borrowings at the Renewables SBU, partially offset by higher net repayments at the ~~following (in millions):~~Energy Infrastructure SBU.

•The $1.3 billion impact from non-recourse debt transactions is mainly due to higher net repayments at Corporate and lower net borrowings at the Energy Infrastructure SBU.

•The $459 million impact from the Parent Company revolver and commercial paper program is primarily due to higher net repayments in the current period.

Andes SBU Q3 2017 vs. Q3 2016 (YTD)
Higher operating margin, net of increased depreciation of $32 $ 18
Lower tax payments at Chivor and Argentina 57
Increase in collections of financing receivables in Argentina, resulting primarily from the commencement of commercial operations at the Guillermo Brown plant 50
Environmental tax accruals in Chile impacting margin but not operating cash flow 37
Increase in other working capital requirements primarily due to delay in collections at Gener (60 )
Lower collections at Chivor, primarily due higher receivables in Q1 2016 resulting from higher sales in Q4 2015 (35 )
Increase in interest payments to reflect the cessation of capitalization of interest for the Cochrane project (14 )
Lower VAT refunds, primarily at Alto Maipo and Cochrane (14 )
Other (1 )
Total Andes SBU Operating Cash Increase $ 38

~~BRAZIL SBU~~

~~The increase in Operating Cash Flow of $21 million was driven primarily by the following (in millions):~~

Brazil SBU Q3 2017 vs. Q3 2016 (QTD)
Higher operating margin, net of increased depreciation of $11 $ 65
Lower payments for energy purchases at Eletropaulo due to lower energy costs and lower regulatory charges 166
Timing of payments at Tietê for energy to be resold 24
Lower collections of costs deferred in net regulatory assets at Eletropaulo due to higher energy costs (181 )
Higher accounts receivable balances at Eletropaulo due primarily to higher tariffs in 2017 (22 )
Lack of AES Sul’s operating cash flow, which was sold in 2016 (13 )
Lower collections at Tietê, due to higher energy sales under bilateral contracts (7 )
Higher interest payments resulting from the assumption of debt for the acquisition of Alto Sertão II (6 )
Other (5 )
Total Brazil SBU Operating Cash Increase $ 21

~~The decrease in Operating Cash Flow of $119 million was driven primarily by the following (in millions):~~

Brazil SBU Q3 2017 vs. Q3 2016 (YTD)
Higher operating margin, net of increased depreciation of $30 $ 167
Higher collections in 2016 of costs deferred in net regulatory assets at Eletropaulo as a result of unfavorable hydrology in prior periods (556 )
Lower collections of accounts receivable at Eletropaulo due primarily to higher tariff flags in 2016 (193 )
Lack of AES Sul’s operating cash flow, which was sold in 2016 (68 )
Lower collections at Tietê, due to higher energy sales under bilateral contracts (20 )
Increase in pension contributions at Eletropaulo (13 )
Timing of payments for energy purchases at Eletropaulo due to lower energy costs and lower regulatory charges 401
Receipt of YPF legal settlement at Uruguaiana 60
Lower tax payments at Tietê 58
Timing of payments at Tietê for energy to be resold 32
Lower interest payments at Tietê 11
Other 2
Total Brazil SBU Operating Cash Decrease $ (119 )

~~MCAC SBU~~

~~The decrease in Operating Cash Flow of $1 million was driven primarily by the following (in millions):~~

MCAC SBU Q3 2017 vs. Q3 2016 (QTD)
Higher operating margin, net of increased depreciation of $3 $ 28
Higher working capital requirements in the Dominican Republic, primarily due to an increase in days outstanding of accounts receivable (68 )
Lower working capital requirements in El Salvador, primarily due to lower energy pricing reducing overall accounts receivable balances and an increase in Accounts Payable days outstanding related to energy purchases 25
Lower working capital requirements in Puerto Rico, primarily due to higher collections and lower sales in September 2017 due to Hurricane Maria 19
Other (5 )
Total MCAC SBU Operating Cash Decrease $ (1 )

~~The increase in Operating Cash Flow of $73 million was driven primarily by the following (in millions):~~

MCAC SBU Q3 2017 vs. Q3 2016 (YTD)
Higher operating margin, net of increased depreciation of $8 $ 68
Lower working capital requirements in AES Puerto Rico, primarily due to higher collections 36
Lower tax payments in El Salvador 16
Lower tax payments in the Dominican Republic, primarily due to lower withholding taxes on dividends paid in 2016 to AES affiliates 10
Higher working capital requirements in the Dominican Republic, primarily due to an increase in accounts receivable days outstanding at Itabo (42 )
Higher interest payments in the Dominican Republic, primarily due to an increase in net debt and higher average interest rates (13 )
Other (2 )
Total MCAC SBU Operating Cash Increase $ 73

~~EURASIA SBU~~

~~The increase in Operating Cash Flow of $17 million was driven primarily by the following (in millions):~~

Eurasia SBU Q3 2017 vs. Q3 2016 (QTD)
Increase in C0₂ allowances at Maritza due to decreased prices in 2016
$ 9
Lower working capital requirements at Kilroot primarily due to a decrease in rates and net VAT payments received in 2017 8
Total Eurasia SBU Operating Cash Increase $ 17

~~The decrease in Operating Cash Flow of $254 million was driven primarily by the following (in millions):~~

Eurasia SBU Q3 2017 vs. Q3 2016 (YTD)
Higher operating margin, net of lower depreciation of $16 $ 19
Lower collections at Maritza, primarily due to the collection of overdue receivables from NEK in 2016 (376 )
Lower payments to fuel suppliers at Maritza, due primarily to the settlement of overdue invoices in 2016 pursuant to the tripartite agreement with NEK and MMI 73
Decrease in service concession asset expenditures at Mong Duong 22
Lower working capital requirements at Masinloc due to the timing of payments for coal purchases 19
Increase in C0₂ allowances at Maritza due to decreased prices in 2016
17
Higher mark-to-market valuation of commodity swaps at Kilroot impacting margin but not operating cash flow (9 )
Lower coal purchases at Mong Duong due to the reserve shutdown in 2017 (9 )
Other (10 )
Total Eurasia SBU Operating Cash Decrease $ (254 )

~~CORPORATE AND OTHER~~

~~The decrease in Operating Cash Flow of $24 million was driven primarily by the following (in millions):~~

Corporate and Other Q3 2017 vs. Q3 2016 (QTD)
Timing of insurance recoveries $ (15 )
Lower payments for interest expense, primarily due to timing of refinancings and draws on Revolver debt 10
Other (19 )
Total Corporate and Other Operating Cash Decrease $ (24 )

~~The decrease in Operating Cash Flow of $84 million was driven primarily by the following (in millions):~~

Corporate and Other Q3 2017 vs. Q3 2016 (YTD)
Timing of intercompany settlements with SBUs $ (39 )
Higher realized losses on oil derivatives (22 )
Higher payments for people-related costs and associated payroll taxes (14 )
Other (9 )
Total Corporate and Other Operating Cash Decrease $ (84 )

Parent Company Liquidity

The following discussion is included as 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~~Cash and cash equivalents, which is determined in accordance with ~~GAAP as a measure of liquidity. Cash and cash equivalents is disclosed in the Condensed Consolidated Statements of Cash Flows.~~GAAP. 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; proceeds from debt and equity financings at the Parent Company level, including availability under our revolving credit facility and commercial paper program; and proceeds from asset sales. Cash requirements at the Parent Company level are primarily to

67 | The AES Corporation | September 30, 2023 Form 10-Q

fund interest and principal repayments of debt, construction commitments, other equity commitments, ~~common stock repurchases,~~ acquisitions, taxes, Parent Company overhead and development costs, and dividends on common stock.

The Company defines Parent Company Liquidity as cash available to the Parent Company, including cash at qualified holding companies, plus available borrowings under our existing credit ~~facility.~~facility and commercial paper program. 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 GAAP financial measure, ~~cash~~Cash and cash equivalents, at the periods indicated as follows (in millions):


	September 30, 2017			December 31, 2016				September 30, 2023		December 31, 2022
Consolidated cash and cash equivalents	$	1,398		$	1,305		Consolidated cash and cash equivalents	$	1,765	$	1,374
Less: Cash and cash equivalents at subsidiaries	(1,317		)	(1,205		)	Less: Cash and cash equivalents at subsidiaries	(1,714)		(1,350)
Parent Company and qualified holding companies’ cash and cash equivalents	81			100			Parent Company and qualified holding companies’ cash and cash equivalents	51		24
Commitments under Parent Company credit facilities	1,100			800
Less: Letters of credit under the credit facilities	(9		)	(6		)
Less: Borrowings under the credit facilities	(540		)	—
Borrowings available under Parent Company credit facilities	551			794
Commitments under the Parent Company credit facility							Commitments under the Parent Company credit facility	1,500		1,500
Less: Letters of credit under the credit facility							Less: Letters of credit under the credit facility	(39)		(34)
Less: Borrowings under the credit facility							Less: Borrowings under the credit facility	—		(325)
Less: Borrowings under the commercial paper program							Less: Borrowings under the commercial paper program	(604)		—
Borrowings available under the Parent Company credit facility							Borrowings available under the Parent Company credit facility	857		1,141
Total Parent Company Liquidity	$	632		$	894		Total Parent Company Liquidity	$	908	$	1,165

The Company utilizes its Parent Company credit facility and commercial paper program for short term cash needs to bridge the timing of distributions from its subsidiaries throughout the year.

The Parent Company paid dividends of ~~$0.12~~$0.1659 per outstanding share to its common stockholders during ~~each of~~ the first, second, and third quarters of ~~2017~~2023 for dividends declared in December ~~2016,~~2022, February ~~2017,~~2023, and July ~~2017,~~2023, respectively. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance that we will continue to pay dividends, or if continued, the amount of such dividends.

Recourse Debt

Our total recourse debt was ~~$5.0~~$5.6 billion and ~~$4.7~~$3.9 billion as of September 30, ~~2017~~2023 and December 31, ~~2016,~~2022, respectively. See Note 7—Debt in Item 1.—Financial Statements of this Form 10-Q and Note 11—Debt in Item 8.—Financial Statements and Supplementary Data of our ~~2016~~2022 Form 10-K for additional detail.

~~While we~~We believe that our sources of liquidity will be adequate to meet our needs for the foreseeable ~~future, this~~future. This belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets, 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~~revolving credit ~~facility.~~facility and commercial paper program. See Item 1A.—Risk Factors—The AES ~~Corporation is a holding company and its~~Corporation’s ability to make payments on its outstanding indebtedness ~~including its public debt securities,~~ is dependent upon the receipt of funds from ~~its~~our subsidiaries ~~by way of dividends, fees, interest, loans or otherwise~~ of the Company’s ~~2016~~2022 Form 10-K for additional information.

Various debt instruments at the Parent Company level, including our ~~senior secured~~revolving credit facility and commercial paper program, contain certain restrictive covenants. The covenants provide for, — among other items, — limitations on other ~~indebtedness;~~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 September 30, ~~2017,~~2023, 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;

68 | The AES Corporation | September 30, 2023 Form 10-Q

•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~~revolving credit facility 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 Condensed Consolidated Balance Sheets amounts to ~~$2.3~~$3.1 billion. The portion of current debt related to such defaults was ~~$1.0 billion~~$332 million at September 30, ~~2017,~~2023, all of which was non-recourse debt related to ~~three~~four subsidiaries — ~~Alto Maipo,~~AES Mexico Generation Holdings, AES Puerto Rico, AES Ilumina, and AES ~~Ilumina.~~Jordan Solar. Defaults at AES Puerto Rico are covenant and payment defaults, for which forbearance and standstill agreements have been signed. All other defaults are not payment defaults, but are instead technical defaults triggered by failure to comply with other covenants or other conditions contained in the non-recourse debt documents. See Note 7—Debt in Item 1.—Financial Statementsof this Form 10-Q for additional detail.

None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under ~~AES’ corporate~~the Parent Company’s debt agreements as of September 30, ~~2017,~~2023, in order for such defaults to trigger an event of default or permit acceleration under ~~AES’~~the Parent Company’s 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 Parent Company’s outstanding debt securities. A material subsidiary is defined in the Parent Company’s ~~senior secured~~revolving credit facility as any business that contributed 20% or more of the Parent Company’s total cash distributions from businesses for the four most recently ended fiscal quarters. As of September 30, ~~2017,~~2023, none of the defaults listed above, individually or in the aggregate, results in or is at risk of triggering a cross-default under the recourse debt of the Parent Company.

Critical Accounting Policies and Estimates

The condensed consolidated financial statements of AES are prepared in conformity with U.S. 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.

The Company’s significant accounting policies are described in Note 1—1 — General and Summary of Significant Accounting Policies of our ~~2016~~2022 Form 10-K. The Company’s critical accounting estimates are described in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations in the ~~2016~~2022 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that these remain as critical accounting policies as of and for the nine months ended September 30, ~~2017.~~2023.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Overview Regarding Market Risks —

Our businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal, and environmental credits. In addition, our businesses are exposed to lower electricity ~~prices~~price trends due to increased competition, including from renewable sources such as wind and solar, as a result of lower costs of entry and lower variable costs. We operate in multiple countries and as such, are subject to volatility in exchange rates at varying degrees at the subsidiary level and between our functional currency, the ~~U.S. Dollar,~~USD, 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.

69 | The AES Corporation | September 30, 2023 Form 10-Q

The disclosures presented in this Item 3 are based upon a number of assumptions; actual effects may differ. 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 3. For further information regarding market risk, see Item 1A.—Risk Factors, ~~Our financial position and results of operations may fluctuate significantly due to fluctuations~~Fluctuations in currency exchange rates ~~experienced at~~may impact our ~~foreign operations;Our businesses~~financial results and position;Wholesale power prices may ~~incur substantial costs and liabilities and be exposed to price~~experience significant volatility ~~as a result of risks associated with the electricity~~in our markets which could ~~have a material adverse effect on~~impact our ~~financial performance~~;operations and opportunities for future growth;We may not be adequately hedged against our exposure to changes in commodity prices or interest ~~rates~~rates; and Certain of our businesses are sensitive to variations in weather and hydrology of the ~~2016~~2022 Form 10-K.

Commodity Price Risk —

Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels, and environmental credits, some of our generation businesses operate under short-term sales, have contracted electricity obligations greater than supply, or operate under contract sales that leave an unhedged exposure on some of our capacity or through imperfect fuel pass-throughs. ~~In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms.~~ 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. At our generation businesses for 2017-2019, 75% to 80% of our variable margin is hedged against changes in commodity prices. At our utility businesses for 2017-2019, 85% to 90% of our variable margin is insulated from changes in commodity prices.

The portion of our sales and purchases that are not subject to such agreements, or contracted businesses where indexation is not perfectly matched to business drivers, will be exposed to commodity price risk. When hedging the output of our generation assets, we utilize contract sales that lock in the spread per MWh between variable costs and the price at which the electricity can be sold.

AES businesses will see changes in variable margin performance as global commodity prices shift. ~~For 2017,~~As of September 30, 2023, we project ~~pretax~~pre-tax earnings exposure on a 10% ~~move~~(uncorrelated) increase in commodity prices ~~would~~to be ~~approximately~~less than a $5 million loss for ~~U.S.~~ power, ~~(DPL),~~gas and coal and a less than $5 million gain for ~~natural gas,~~ oil ~~and coal, respectively.~~for the remainder of the year. Our estimates exclude correlation ~~of oil with coal or natural gas.~~effects, including those due to renewable resource availability. For example, a decline in oil or natural gas prices can be accompanied by a decline in ~~coal~~power 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, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.

Commodity prices affect our businesses differently depending on contract terms, the local market characteristics and risk management strategies. Spot power prices, contract indexation provisions, and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil, and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. Exposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies, and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. 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.

In the USEnergy Infrastructure SBU, the generation businesses are largely contracted, but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. ~~IPL primarily generates energy~~In California, our Southland once-through cooling generation units (“Legacy Assets”) in Long Beach and Huntington Beach have been extended to ~~meet its retail customer demand however it opportunistically sells surplus economic energy into wholesale markets~~operate through 2026 under capacity contracts with the State as part of the Strategic Reserve program. The Office of Administrative Law (OAL) is expected to confirm approval by the end of November. Our facility in Redondo Beach has been approved to retire at ~~market prices. Additionally,~~the end of 2023. Our ability to operate the Long Beach facility at ~~DPL, competitive retail markets permit our customers~~full capacity through 2026 remains subject to ~~select alternative energy suppliers or elect to remain~~approved Time Schedule Order coverage, which is expected in ~~aggregated customer pools for which energy is supplied by third party suppliers through a competitive auction process. DPL participates in these auctions held by other utilities~~late November 2023. Our Southland combined cycle gas turbine (Southland Energy) units benefit from higher power and ~~sells the remainder of its economic energy into the wholesale market. Given that natural gas-fired generators generally get energy prices for many markets, higher natural~~lower gas prices, ~~tend to expand our coal fixed margins. Our non-contracted generation margins are impacted by many factors, including~~depending on the ~~growth in natural gas-fired generation plants, new energy supply from renewable sources, and increasing energy efficiency~~.contracted or hedge position.

~~In the~~The AES Andes ~~SBU, our~~ business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. ~~In the central region, the contract sales generally cover the efficient generation from~~A significant portion of our ~~coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the~~

~~amount~~PPAs through 2024 include mechanisms of ~~hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets~~indexation that adjust the price of ~~which depends~~energy based on ~~fuel pricing at~~fluctuations in the ~~time required. There is a small amount~~price of coal, ~~generation~~with an index defined by the National Energy Commission based on the physical coal imports for the energy system. This mechanism mitigates exposures to changes in the ~~northern region that is not covered by~~price of fuel. In the Dominican Republic, we own natural gas plants contracted under a portfolio of contract sales, and ~~therefore~~both contract and spot prices may move with commodity prices through 2024.

70 | The AES Corporation | September 30, 2023 Form 10-Q

Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations. Our assets operating in Vietnam and Bulgaria have minimal exposure to commodity price risk as they have no or minor merchant exposure and fuel is subject to ~~spot price risk.~~ a pass-through mechanism.

In ~~both regions, generators with oil or oil-linked fuel generally set~~the Renewables SBU, our businesses have commodity exposure on unhedged volumes and resource volatility and benefit from higher power ~~prices.~~prices, where generation exceeds contracted levels. In Colombia, we operate under a ~~short-term~~shorter-term sales strategy ~~and have commodity~~with spot market exposure ~~to unhedged~~for uncontracted volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.

In Brazil, the ~~Brazil SBU,~~majority of the hydroelectric and other renewable generating facility isvolumes are covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation.

~~In the MCAC SBU, our~~ Our Renewables businesses ~~have commodity exposure on unhedged volumes.~~in Panama isare highly contracted under ~~a portfolio of fixed volume contract sales.~~financial and load-following PPA type structures, exposing the business to hydrology-based variance. To the extent hydrological inflows are greater than or less than the contract ~~sales volume,~~volumes, the business will be sensitive to changes in spot power prices which may be driven by oil and natural gas prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.

~~In the Eurasia SBU, our Kilroot facility operates on a short-term sales strategy~~. To the extent that sales are unhedged, the commodity risk at our Kilroot business is to the clean dark spread, which is the difference between electricity price and our coal-based variable dispatch cost, including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. Similarly, increased wind generators displaces higher cost generation, reducing Kilroot's margins, and vice versa. Our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume or shortfalls of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices sold in the spot market. Our Mong Duong business has minimal exposure to commodity price risk as it has no merchant exposure and fuel is subject to a pass-through mechanism.

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 ("USD").~~USD. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in ~~the~~ USD or currencies other than their own functional currencies. Certain of our foreign subsidiaries calculate and pay taxes in currencies other than their own functional currency.We have varying degrees of exposure to changes in the exchange rate between the USD and the following currencies: Argentine ~~Peso, British Pound,~~peso, Brazilian ~~Real,~~real, Chilean ~~Peso,~~peso, Colombian ~~Peso,~~peso, Dominican ~~Peso,~~peso, Euro, ~~Indian Rupee,~~and Mexican ~~Peso~~peso. Our exposure to certain of these currencies may be material and ~~Philippine Peso.~~economic mechanisms to hedge certain of these risks may not always be available. 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.

AES enters into ~~cash flow~~foreign currency hedges to protect economic value of the business and minimize the impact of foreign exchange rate fluctuations to ~~AES~~AES’ portfolio. While protecting cash flows, the hedging strategy is also designed to reduce ~~forward looking~~forward-looking earnings foreign exchange volatility. Due to variation of timing and amount between cash ~~distribution~~distributions and earnings exposure, the hedge impact may not fully cover the earnings exposure on a realized basis, which could result in greater volatility in earnings. ~~The largest~~

AES has unhedged forward-looking earnings foreign exchange ~~risks over a 12-month forward- looking period stem~~deterioration risk from the ~~following currencies: Brazilian Real, Euro, Colombian Peso, British Pound, and Kazakhstani Tenge. As of~~Argentina peso that could be material. Additionally, as of September 30, ~~2017,~~2023, assuming a 10% USD appreciation, cash distributions attributable to foreign subsidiaries in the Euro may be exposed to ~~movement in the~~ exchange rate movement of ~~the Brazilian Real, British Pound, Colombian Peso, and Euro each are projected to be reduced by~~ less than a $5 million ~~for 2017. These numbers have been~~loss. Sensitivities are produced by applying a one-time 10% USD appreciation to forecasted exposed cash distributions for ~~2017~~2023 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional ~~gains/~~gains or losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted cash distributions exposed to foreign exchange risk may result in further

modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency ~~inconvertibility.~~in convertibility.

Interest Rate ~~Risk~~ — 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, floor, and option agreements.

Decisions on the fixed-floating debt mix 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. Most of our interest rate risk is related to non-recourse financings at our businesses.

71 | The AES Corporation | September 30, 2023 Form 10-Q

As of September 30, ~~2017,~~2023, the portfolio’s ~~pretax~~pre-tax earnings exposure ~~for 2017~~ to a one-time 100-basis-point increase in interest rates for our Argentine ~~Peso,~~peso, Brazilian ~~Real,~~real, Chilean peso, Colombian ~~Peso,~~peso, Euro, and USD denominated debt would be approximately ~~$10~~$15 million on interest expense for the debt denominated in these currencies. These amounts represent year to go exposure and do not take into account the historical correlation between these interest rates.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures—

The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the ~~Securities~~Exchange Act, ~~of 1934, as amended (the “Exchange Act”),~~ as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective as of September 30, ~~2017,~~2023, to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Controls over Financial Reporting—

There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

72 | The AES Corporation | September 30, 2023 Form 10-Q

PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims ~~where~~when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company's condensed consolidated financial statements. It is reasonably possible, however, 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, but cannot be estimated as of September 30, ~~2017.~~

~~In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the state~~2023. Pursuant to SEC amendments Item 103 of ~~Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating~~SEC Regulation S-K, AES’ policy is to the methodology for calculating monetary adjustments under the parties' financing agreement. In April 1999, the FDC found in favor of Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$2.03 billion ($641 million) from Eletropaulo as estimated by Eletropaulo (or approximately R$2.76 billion ($872 million) as of June 2017, as estimated by Eletrobrás, and possiblydisclose environmental legal costs) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo's defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings to ~~determine whether Eletropaulo~~which a governmental authority is ~~liable for the debt. In December 2012, the FDC issued~~ a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC appointed an accounting expert to analyze the issues in the case. In September 2015, the expert issued a preliminary report concluding that Eletropaulo is liable for the debt, without quantifying the debt. Eletropaulo thereafter submitted questions to the expert and reports rebutting the expert's preliminary report (“Rebuttal Reports”). In April 2016, Eletrobrás requested that the expert determine both the criteria to calculate the debt and the amount of the debt. In April 2017, the FDC ordered the expert to comment on Eletropaulo’s Rebuttal Reports and to analyze the questions presented by the parties. It is unclear when the expert will issue his comments. Pursuant to a memorandum of understanding, in October 2017, Eletropaulo and Eletrobrás requested that the FDC suspend the case for 60 days to allow Eletropaulo and Eletrobrás to engage in settlement discussions. If settlement is achieved, it will be subject to the approval of the Eletropaulo Board of Directors and the majority of non-AES board members of Eletropaulo. If settlement is not achieved, the case will proceed and, ultimately, a decision will be issued by the FDC, which will be free to reject or adopt in whole or in part the expert's report. If the FDC again determines that Eletropaulo is liable for the debt, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. In June 2016, the FDC dismissed CTEEP’s lawsuit, on the ground that CTEEP’s claim would be decided in the FDC lawsuit initiated by Eletrobrás. 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. If Eletrobrás requests the seizure of the security noted above and the FDC grantsparty if such request (or if a court determines that Eletropaulo is liable for the debt), Eletropaulo's results of operations may be materially adversely affected and, in turn, the Company's results of operations may also be materially adversely affected. Eletropaulo and the Company could face a loss of earnings and/or cash flows and 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 Eletropaulo cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.

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 São 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$2 million ($632 thousand) as of December 31, 2015, or pay an indemnification amount of approximately R$15 million ($5 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court's decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court's decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which isare reasonably expected to be

~~approximately R$2 million ($632 thousand). Eletropaulo also requested that the court add the current owner~~result in monetary sanctions of ~~the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party~~greater than or equal to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court's decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo. In January 2015, the Secretary of the Environment for the State of São Paulo notified Eletropaulo and the court that it would not accept Eletropaulo's proposed green areas donation. Instead of such green areas donation, the Secretary of the Environment proposed in March 2015 that Eletropaulo undertake an environmental project to offset the alleged environmental damage. Since March 2015, Eletropaulo and the Secretary of Environment have been working together to define an environmental project, which will be submitted for approval by the Public Prosecutor. The cost of such project is currently estimated to be R$3 million ($1 million).$1 million.

In December 2001, Grid Corporation of Odisha (“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 shareholders agreement between GRIDCO, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. (“CESCO”), an affiliate of the Company. In the arbitration, 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. 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. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. GRIDCO filed challenges of the tribunal's awards with the local Indian court. GRIDCO's challenge of the costs award has been dismissed by the court, but its challenge of the liability award remains pending. A hearing on the liability award ~~is scheduled for November 2, 2017.~~has not taken place to date. 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 March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, 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. The MPF 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 (“FCSP”) 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. In April 2015, the FCA issued a decision holding that the FCSP should consider all five alleged violations. AES Elpa and AES Brasiliana (the successor of AES Transgás) have appealed the April 2015 decision to the Superior Court of Justice. The lawsuit remains pending before the FCSP. AES Elpa and AES Brasiliana 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.

Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the state of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to ~~recover~~mitigate the contaminated area located on the grounds of the pole factory and an indemnity payment of approximately R$6 million ($21 million) ~~to the state's Environmental Fund.~~. In October 2011, the State Attorney ~~Office~~ filed a request for an injunction ordering the defendant companies to contain and remove the contamination immediately. The court granted injunctive relief on

October 18, 2011, but determined ~~only~~ that ~~defendant~~only CEEE was required to ~~proceed with~~perform the removal work. In May 2012, CEEE began the removal work in compliance with the injunction. The case is now awaiting judgment. The removal and remediation costs are estimated to be approximately R$15 million to R$60 million ($193 million to $12 million), and there could be additional costs which cannot be estimated at this time. In June 2016, the work was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The court-appointed expert final report was presented to the State Attorneys in October 2014, and in January 2015 to the defendant companies. In March 2015,Company sold AES Sul to CPFL Energia S.A. and as part of the sale, AES ~~Florestal submitted comments and supplementary questions regarding~~Guaiba, a holding company of AES Sul, retained the ~~expert report.~~potential liability relating to this matter. The Company believes that ~~it has~~there are 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 May 2008, the Tax Authority initiated a collection suit against Eletropaulo, seeking to collect approximately R$230 million ($73 million) in PIS taxes (as estimated by Eletropaulo) for the period of March 1996 to December 1998. Unfavorable decisions on the merits were issued by the First Instance Court (“FIC”) and the Second Instance Court (“SIC”) in January 2011 and April 2015, respectively. Subsequently, Eletropaulo requested that the SIC remit the case to the Superior Court of Justice (“STJ”) and the Supreme Federal Court (“STF”). In March 2017, the SIC rejected Eletropaulo’s request. Eletropaulo has requested that an SIC panel review the March 2017 decision. In addition, Eletropaulo has appealed that decision to the STJ and STF. Also, in April 2017, in a related execution proceeding, the FIC asked the Tax Authority to advise on whether it intends to pursue collection. In August 2017, the Tax Authority requested that Eletropaulo replace its bank guarantee with a cash deposit of the amount in dispute into a judicial account (currently, the bank guarantee is in place as security for Eletropaulo’s alleged obligation). Eletropaulo contested the Tax Authority’s request. In September 2017, the FIC denied the Tax Authority’s request. The Tax Authority is expected to appeal. Eletropaulo believes it has meritorious defenses and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In October 2009, IPL received an NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleges violations of the CAA at IPL's three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. IPL management previously met with EPA staff regarding possible resolutions of the 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, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. 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 of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.

In June 2011, the São Paulo Municipal Tax Authority (the “Tax Authority”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the grounds that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court (“FIAC”) determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$3.3 billion ($1 billion) as estimated by Eletropaulo. Eletropaulo thereafter appealed to the Second Instance Administrative Court (“SIAC”). In January 2016, the Tax Authority nullified most of the ISS sought from Eletropaulo. In January 2017, the SIAC issued a decision confirming the reduction and rejecting certain other amounts of ISS as time-barred, but finding that Eletropaulo was liable for the remainder of ISS totaling approximately R$200 million ($63 million). The Tax Authority appealed the SIAC’s decision on the time-barred amounts, totaling approximately R$16 million ($5 million) (“Time-Barred Amounts”), to the Municipal Council of Taxes (“MCT Proceeding”). With respect to the R$200 million, in March 2017, the Tax Authority canceled most of that amount (“March 2017 Cancelation”), and initiated an execution lawsuit to collect the remainder of approximately R$70 million ($22 million) (“Execution Lawsuit”). The Time-Barred Amounts and the March 2017 Cancelation will be reviewed in the ongoing MCT Proceeding. The Execution Lawsuit is also ongoing. Eletropaulo believes it has meritorious defenses and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê had paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the grounds that the tax rate was set in the applicable legislation. In April 2013, the FIAC determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest, and penalties totaling approximately R$1.16 billion ($366 million) as estimated by AES Tietê. AES Tietê appealed to the SIAC. In January 2015, the SIAC issued a decision in AES Tietê's favor, finding that AES Tietê was not liable for unpaid taxes. The public prosecutor subsequently filed an appeal, which was denied as untimely. The Tax Authority thereafter filed a motion for clarification of the SIAC's decision, which was

denied in September 2016. The Tax Authority later filed a special appeal (“Special Appeal”), which was rejected as untimely in October 2016. The Tax Authority thereafter filed an interlocutory appeal with the Superior Administrative Court (“SAC”). In March 2017, the President of the SAC determined that the SAC would analyze the Special Appeal on timeliness and, if required, the merits. AES Tietê has challenged the Special Appeal. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In January 2015, DPL received NOVs from the EPA alleging violations of opacity at Stuart and Killen Stations, and in October 2015, IPL received a similar NOV alleging violations at Petersburg Station. In February 2017, EPA issued a second NOV for DPL Stuart Station, alleging violations of opacity in 2016. Moreover, in February 2016, IPL received an NOV from the EPA alleging violations of New Source Review (“NSR”) and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Station. It is too early to determine whether the NOVs could have a material impact on our business, financial condition or results of our operations. IPL would seek recovery of any operating or capital expenditures, but not fines or penalties, related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that we would be successful in this regard.

In September 2015, AES Southland Development, LLC and AES Redondo Beach, LLC filed a lawsuit against the California Coastal Commission (the “CCC”) over the CCC's determination that the site of AES Redondo Beach included approximately 5.93 acres of CCC-jurisdictional wetlands. The CCC has asserted that AES Redondo Beach has improperly installed and operated water pumps affecting the alleged wetlands in violation of the California Coastal Act and Redondo Beach Local Coastal Program ~~and has ordered AES Redondo Beach to restore the site. Additional potential~~(“LCP”). Potential outcomes of the CCC determination could include an order requiring AES Redondo Beach to ~~fund~~perform a ~~wetland mitigation project~~restoration and/or pay fines or penalties. AES Redondo Beach believes that it has meritorious arguments ~~and intends to vigorously prosecute such lawsuit,~~concerning the underlying CCC determination, but there can be no assurances that it will be successful. On March 27, 2020, AES Redondo Beach, LLC sold the site to an unaffiliated third-party purchaser that assumed the obligations contained within these proceedings. On May 26, 2020, CCC staff sent AES a NOV directing AES to submit a Coastal Development Permit (“CDP”) application for the

73 | The AES Corporation | September 30, 2023 Form 10-Q

removal of the water pumps within the alleged wetlands. AES has submitted the CDP to the permitting authority, the City of Redondo Beach (“the City”), with respect to AES’ plans to disable or remove the pumps. The NOV also directed AES to submit technical analysis regarding additional water pumps located within onsite electrical vaults and a CDP application for their continued operation. AES has responded to the CCC, providing the requested analysis and seeking further discussion with the agency regarding the CDP. On October 14, 2020, the City deemed the CDP application to be complete and indicated a public hearing will be required, at which time AES must present additional information and analysis on the pumps within the alleged wetlands and the onsite electrical vaults. AES will vigorously defend its interests with regard to the NOV, but we cannot predict the outcome of the matter at this time. However, settlements and litigated outcomes of Coastal Act and LCP claims alleged against other companies have required them to pay significant civil penalties and undertake remedial measures.

In October 2015, AES Indiana received an NOV alleging violations of the Clean Air Act (“CAA”), the Indiana State Implementation Plan (“SIP”), and the Title V operating permit related to alleged particulate and opacity violations at Petersburg Station Unit 3. In addition, in February 2016, AES Indiana received an NOV from the EPA alleging violations of New Source Review and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and the Indiana Department of Environmental Management (“IDEM”), resolving these purported violations of the CAA at Petersburg Station. The settlement agreement, in the form of a proposed judicial consent decree, was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's current Title V air permit; payment of civil penalties totaling $1.5 million; a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.3 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023.

In December 2018, a lawsuit was filed in Dominican Republic civil court against the Company, AES Puerto Rico, and three other AES affiliates. The lawsuit purports to be brought on behalf of over 100 Dominican claimants, living and deceased, and appears to seek relief relating to CCRs that were delivered to the Dominican Republic in 2004. The lawsuit generally alleges that the CCRs caused personal injuries and deaths and demands $476 million in alleged damages. The lawsuit does not identify, or provide any supporting information concerning, the alleged injuries of the claimants individually. Nor does the lawsuit provide any information supporting the demand for damages or explaining how the quantum was derived. The relevant AES companies believe that they have meritorious defenses to the claims asserted against them and will defend themselves vigorously in this proceeding; however, there can be no assurances that they will be successful in their efforts.

In February 2019, a separate lawsuit was filed in Dominican Republic civil court against the Company, AES Puerto Rico, two other AES affiliates, and an unaffiliated company and its principal. The lawsuit purports to be brought on behalf of over 200 Dominican claimants, living and deceased, and appears to seek relief relating to CCRs that were delivered to the Dominican Republic in 2003 and 2004. The lawsuit generally alleges that the CCRs caused personal injuries and deaths and demands over $900 million in alleged damages. The lawsuit does not identify or provide any supporting information concerning the alleged injuries of the claimants individually, nor does the lawsuit provide any information supporting the demand for damages or explaining how the quantum was derived. In August 2020, at the request of the relevant AES companies, the case was transferred to a different civil court (“Civil Court”). Preliminary hearings have taken place. The parties are awaiting the Civil Court’s ruling on the AES respondents’ motions to dismiss the lawsuit. The relevant AES companies believe that they have meritorious defenses to the claims asserted against them and will defend themselves vigorously in this proceeding; however, there can be no assurances that they will be successful in their efforts.

In October ~~2015, Ganadera Guerra, S.A. (“GG”~~2019, the Superintendency of the Environment (the "SMA") notified AES Andes of certain alleged breaches associated with the environmental permit of the Ventanas Complex, initiating a sanctioning process through Exempt Resolution N° 1 / ROL D-129-2019. The alleged charges include exceeding generation limits, failing to reduce emissions during episodes of poor air quality, exceeding limits on discharges to the sea, and ~~Constructora Tymsa, S.A. (“CT”) filed separate lawsuits against~~exceeding noise limits. AES ~~Panama~~Andes has submitted a proposed “Compliance Program” to the SMA for the Ventanas Complex. The latest version of this Compliance Program was submitted on May 26, 2021. On December 30, 2021, the Compliance Program was approved by the SMA. However an ex officio action was brought by the SMA due to alleged exceedances of generation limits, which would require the Company to reduce SO2, NOx and PM emissions in order to achieve the emissions offset established in the ~~local courts~~Compliance Program. On January 6, 2022, AES Andes filed a reposition with the SMA seeking modification of ~~Panama.~~the means for compliance with the ex officio action. On January 17, 2023, the SMA approved street paving measures, or alternatively a program providing heaters for community members, as the means to satisfy the air emissions offsets in the approved Compliance Plan. The ~~claimants allege~~cost of proposed Compliance Program is approximately $10.8 million USD. On April 21, 2023, the SMA

74 | The AES Corporation | September 30, 2023 Form 10-Q

notified AES Andes of a resolution alleging an additional “serious” non-compliance of the Ventanas Complex failing to reduce emissions during episodes of poor air quality. On May 24, 2023, AES Andes submitted disclaimers to the SMA in response to this resolution. AES Andes plans to vigorously defend itself through the administrative process, but there are no guarantees that it will be successful. Fines are possible if AES Andes is unsuccessful in its defense of the April 2023 resolution and/or if the SMA determines there is an unsatisfactory execution of the Compliance Program approved in connection with the October 2019 sanctioning process.

In March 2020, Mexico’s Comisión Federal de Electricidad (“CFE”) served an arbitration demand upon AES Mérida III. CFE made allegations that AES ~~Panama profited from~~Mérida III was in breach of its obligations under a ~~hydropower facility (La Estrella) being partially located on land owned initially by GG~~power and ~~currently by CT, and that AES Panama must pay compensation for its use~~capacity purchase agreement (“Contract”) between the two parties, which allegations related to CFE’s own failure to provide fuel within the specifications of the ~~land.~~Contract. CFE sought to recover approximately $200 million in payments made to AES Mérida under the Contract as well as approximately $480 million in alleged damages for having to acquire power from alternative sources in the Yucatan Peninsula. AES Mérida filed an answer denying liability to CFE and asserted a counterclaim for damages due to CFE’s breach of its obligations. The parties submitted their respective initial briefs and supporting evidence in December 2020. After additional briefing, the evidentiary hearing took place in November 2021. Closing arguments were heard in May 2022. In November 2022, the arbitration Tribunal issued its decision in the case, rejecting CFE’s claims for damages ~~sought from~~and granting AES ~~Panama are approximately $685 million (GG) and $100 million (CT)~~Mérida a net amount of damages on AES Mérida’s counterclaims (“Award”). ~~In October 2016, the court dismissed GG's claim because of GG's failure to comply with a court order requiring GG to disclose certain information. GG has refiled its lawsuit. Also, there~~There are ongoing ~~administrative~~ proceedings in the Mexican courts concerning ~~whether~~ AES ~~Panama is entitled~~Mérida’s attempt to ~~acquire an easement over~~enforce the ~~land~~Award and ~~whether~~CFE’s attempt to challenge the Award. AES ~~Panama can continue to occupy the land. AES Panama~~Mérida believes that it has meritorious defenses and claims and will assert them ~~vigorously;~~vigorously in this dispute; however, there can be no assurances that it will be successful in its efforts.

InOn May 12, 2021, the Mexican Federal Attorney for Environmental Protection (the “Authority”) initiated an environmental audit at the TEP thermal generating facility. On January ~~2017, the Superintendencia del Medio Ambiente (“SMA”) issued a Formulation of Charges asserting that Alto Maipo is in violation of certain conditions~~20, 2023 TEP was notified of the Environmental Approval Resolution (“RCA”) governing Alto Maipo’s hydropower project, for, among other things, operating vehicles at unauthorized times and failing to mitigate the impact of water intrusion during tunnel construction. In February 2017, Alto Maipo submitted a compliance plan to the SMA which, if approvedresolution issued by the ~~agency, would resolve~~Authority, which alleges breaches of air emission regulations, including the ~~matter without materially impacting construction~~failure to submit reports. The resolution imposes a fine of $27,615,140 pesos (approximately USD $1.6 million). On March 3, 2023, the facility filed a nullity judgment to challenge such resolution, which has been admitted by the local judge with an injunction granted against execution of the ~~project. In June 2017,~~proposed fine during the SMA issued a resolution detailing its comments on the compliance plan. Alto Maipo responded to the SMA’s comments in July 2017. The SMA is expected to issue its decision on Alto Maipo’s compliance plan in the near future. The outcome of this matter is uncertain, but an adverse decision by the SMA could have a negative impact on the constructioncourse of the ~~project. Alto Maipo will pursue its interests vigorously in this matter; however, there can be no assurance~~underlying proceedings. However, the local tax authority rejected receiving the bond that ~~it will be successful in its efforts.~~

~~In June 2017, Alto Maipo terminated one~~is required to guarantee the injunction, and as a result, TEP filed a complaint on September 18, 2023 seeking to compel the tax authority to accept the bond and recognize the validity of its contractors, Constructora Nuevo Maipo S.A. (“CNM”), given CNM’s stoppage of tunneling works, its failure to produce a completion plan, and its other breaches of contract. Alto Maipo also initiated arbitration against CNM to recover completion costs and other damages relating to these breaches. CNM subsequently initiated a separate arbitration, seeking a declaration that its termination was wrongful, damages, and other relief. CNM has not supported its alleged damages, but it has asserted that it is entitled to recover over $20 million in damages, legal costs, and the amounts drawn by Alto Maipo under letters of credit. The arbitrations have been consolidated into a single action, which is ongoing. As noted above, Alto Maipo drew on letters of credit securing CNM’s obligations, totaling approximately $73 million. Initially, the issuing bank did not pay Alto Maipo because CNM obtained an ex parte injunction from a Chilean court prohibiting the bank from honoring the draws. However, at Alto Maipo’s request, the Chilean court later removed the injunction. Accordingly, in July 2017, the bank paid Alto Maipo in full. CNM is attempting to seek relief in the Chilean court of appeals and the arbitration in relation to the draws on the letters of credit. To date, CNM has been unable to obtain such relief. Alto

~~Maipo~~The Company believes that it has meritorious defenses to the claims ~~and defenses~~asserted against it and will ~~assert them~~defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

In ~~October 2017, the Ministry of Justice (“MOJ”) of the Republic of Kazakhstan (“ROK”) filed~~February 2022, a lawsuit was filed in the Economic Court of Kazakhstan against Tau Power BV (an AES affiliate), Altai Power LLP (an AES affiliate), the Company, and two hydropower plants (“HPPs”) previously under concession to Tau Power. In its lawsuit, the MOJ references a 2013 treaty arbitration awardDominican Republic civil court against the ~~ROK concerning the ROK’s energy laws. While its~~Company. The lawsuit ~~is unclear, the MOJ~~purports to be brought on behalf of over 425 Dominican claimants, living and deceased, and appears to seek relief relating to CCRs that were delivered to the ~~net income distributed by~~Dominican Republic in 2003 and 2004. The lawsuit generally alleges that the ~~HPPs during certain years~~CCRs caused personal injuries and deaths and demands over $600 million in alleged damages. The lawsuit does not identify or provide any supporting information concerning the alleged injuries of the ~~concession period. There is a hearing on this matter in the Economic Court on November 1, 2017. The AES defendants believe that~~claimants individually. Nor does the lawsuit ~~is without merit~~provide any information supporting the demand for damages or explaining how the quantum was derived. The Company believes that it has meritorious defenses to the claims asserted against it and ~~they~~ will ~~assert their defenses vigorously;~~defend itself vigorously in this proceeding; however, there can be no assurances that ~~they~~it will be successful in ~~their~~its efforts.

On July 25, 2022, AES Puerto Rico, LP (“AES-PR”) received from the EPA an NOV alleging certain violations of the CAA at AES-PR’s coal-fired power facility in Guayama, Puerto Rico. The NOV alleges AES-PR exceeded an emission limit and did not continuously operate certain monitoring equipment, conduct certain analyses and testing, maintain complete records, and submit certain reports as required by the EPA’s Mercury and Air Toxics Standards. The NOV further alleges AES-PR did not comply fully with the facility’s Title V operating permit. AES-PR is engaging in discussions with the EPA about the NOV. AES-PR will defend its interests, but we cannot predict the outcome of this matter at this time. However, settlements and litigated outcomes of CAA claims alleged against other coal-fired power plants have required companies to pay civil penalties and undertake remedial measures.

In April 2022, the Superintendency of the Environment (the "SMA") notified AES Andes of certain alleged breaches associated with the construction of the Mesamávida wind project, initiating a sanctioning process. The alleged charges include untimely implementation of road improvement measures and road use schedules and the failure to identify all noise receptors closest to the first construction phases of the project. On June 23, 2022, the SMA addressed the charges to Energía Eólica Mesamávida SpA. On June 28, 2022, Energía Eólica Mesamávida SpA submitted a proposed compliance program, with an estimated cost of $4.3 million, which was subsequently approved by the SMA. On November 9, 2022, opponents to the project submitted before the Third Environmental Court a judicial action challenging the approval of this compliance program. On March 7, 2023, the Third

75 | The AES Corporation | September 30, 2023 Form 10-Q

Environmental Court rejected the third-party judicial action against the Compliance Program. The deadline to appeal the decision has passed and no appeals were submitted. If the SMA determines there is an unsatisfactory execution of the compliance program, fines are possible.

In June 2020, the Energy Regulatory Commission of Mexico passed resolution RES/894/2020 that may increase the wheeling tariffs that are paid by TEG and TEP to CFE. The increase is currently estimated to be over $130 million for the relevant period (July 2020 through March 2024). In October 2022, TEG and TEP initiated a challenge of the constitutionality of the resolution. If that challenge is unsuccessful, TEG and TEP will seek to enforce their respective contractual rights to pass-through the tariff increases to their respective offtakers.

On January 26, 2023, the SMA notified Alto Maipo SpA of four alleged charges relating to the Alto Maipo facility, all which are categorized by the SMA as “serious.” The alleged charges include untimely completion of intake works and insufficient capture by the provisional works, irrigation water outlet and canal contemplated by an agreement with local communities; non-compliance with the details of the forest management plans and intervention in unauthorized areas; construction of a road in a restricted paleontological area; and unlawful moving of fauna. On February 16, 2023, the Alto Maipo project submitted a compliance program, to which the SMA provided observations. On June 6, 2023, Alto Maipo responded to the SMA’s observations by submitting a revised compliance program, which is currently under consideration by the SMA. In late June and early July 2023, third-party opponents submitted observations to the compliance program, claiming that the proposal to address the intake works charges is inadequate. Alto Maipo completed its submission of responses to these third-party observations in August 2023, and subsequently, new, additional observations were submitted by opponents to the project. The costs of any such compliance program are uncertain. If a compliance program is not approved by or executed to the satisfaction of the SMA, fines, revocation of the facility’s RCA environmental permit approved by the SMA, or closure are possible outcomes for such alleged serious violations under applicable regulations.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors disclosed in ~~Part I~~—Item 1A.—Risk Factors of our ~~2016~~2022 Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations, including those discussed in Item 2.—Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-Q.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~No repurchases were made by the AES Corporation of its common stock during the third quarter of 2017.~~

The Board has authorized the Company to repurchase stock through a variety of methods, including open market repurchases, purchases by contract (including, without limitation, accelerated stock repurchase programs or 10b5-1 plans), and/or privately negotiated transactions. There can be no assurances as to the amount, timing, or prices of repurchases, which may vary based on market conditions and other factors. The Program does not have an expiration date and can be modified or terminated by the Board of Directors at any time. As of September 30, ~~2017, $246~~2023, $264 million remained available for repurchase under the Program. No repurchases were made by The AES Corporation of its common stock during the third quarter of 2023.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

~~None.~~Trading Arrangements

None of the Company’s directors or “officers,” as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K, during the Company’s fiscal quarter ended September 30, 2023.

76 | The AES Corporation | September 30, 2023 Form 10-Q

ITEM 6. EXHIBITS



~~4.1~~31.1		Twenty-First Supplemental Indenture, dated August 28, 2017, between The AES Corporation and Deutsche Bank Trust Company Americas, as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company’s Form 8-K filed on August 28, 2017.
~~31.1~~	~~Rule13a-14(a)~~Rule 13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith).
31.2		Rule 13a-14(a)/15d-14(a) Certification of ~~Thomas M. O’Flynn~~Stephen Coughlin (filed herewith).
32.1		Section 1350 Certification of Andrés Gluski (filed herewith).
32.2		Section 1350 Certification of ~~Thomas M. O’Flynn~~Stephen Coughlin (filed herewith).
~~101.INS~~101		The AES Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, formatted in Inline XBRL ~~Instance Document (filed herewith).~~(Inline Extensible Business Reporting Language): (i) the Cover Page, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Operations, (iv) Condensed Consolidated Statements of Comprehensive Income (Loss), (v) Condensed Consolidated Statements of Changes in Equity, (vi) Condensed Consolidated Statements of Cash Flows, and (vii) Notes to Condensed Consolidated Financial Statements. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
~~101.SCH~~104		Cover Page Interactive Data File (formatted as Inline XBRL ~~Taxonomy Extension Schema Document (filed herewith).~~
~~101.CAL~~	~~XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith).~~
~~101.DEF~~	~~XBRL Taxonomy Extension Definition Linkbase Document (filed herewith).~~
~~101.LAB~~	~~XBRL Taxonomy Extension Label Linkbase Document (filed herewith).~~
~~101.PRE~~	~~XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith).~~and contained in Exhibit 101)

77 | The AES Corporation | September 30, 2023 Form 10-Q

SIGNATURES

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

THE AES CORPORATION

(Registrant)

Date:

November 2, 2023

~~THE AES CORPORATION~~

~~(Registrant)~~

By:

/s/ STEPHEN COUGHLIN

Name:

Stephen Coughlin

~~Date:~~

~~November 1, 2017~~

~~By:~~

~~/s/ THOMAS~~ ~~M. O’FLYNN~~

Title:

~~Name:~~

~~Thomas M. O’Flynn~~

~~Title:~~

Executive Vice President and Chief Financial Officer (Principal Financial Officer)

By:

/s/ F~~ABIAN~~ ~~E. SOUZA~~

SHERRY L. KOHAN

Name:

~~Fabian E. Souza~~Sherry L. Kohan

Title:

Senior Vice President and ~~Controller~~Chief Accounting Officer (Principal Accounting Officer)



Three Months Ended September 30, 2016	Interest Rate			Foreign Currency			Commodity			Total
Balance at July 1	$	(421	)	$	271		$	11		$	(139	)
Total realized and unrealized gains (losses):
Included in earnings	(1		)	12			1			12
Included in other comprehensive income — derivative activity	6			—			—			6
Included in other comprehensive income — foreign currency translation activity	—			(5		)	—			(5		)
Settlements	17			(4		)	(3		)	10
Transfers of liabilities into Level 3	(2		)	—			—			(2		)
Transfers of liabilities out of Level 3	94			—			—			94
Balance at September 30	$	(307	)	$	274		$	9		$	(24	)
Total gains for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	—		$	8		$	1		$	9



Nine Months Ended September 30, 2017	Interest Rate			Foreign Currency			Commodity			Total
Balance at January 1	$	(179	)	$	255		$	5		$	81
Total realized and unrealized gains (losses):
Included in earnings	(5		)	12			(1		)	6
Included in other comprehensive income — derivative activity	(29		)	—			—			(29		)
Included in regulatory liabilities	—			—			10			10
Settlements	28			(25		)	(8		)	(5		)
Transfers of liabilities into Level 3	(7		)	—			—			(7		)
Balance at September 30	$	(192	)	$	242		$	6		$	56
Total losses for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	—		$	(12	)	$	—		$	(12	)



Nine Months Ended September 30, 2016	Interest Rate			Foreign Currency			Commodity			Total
Balance at January 1	$	(304	)	$	277		$	3		$	(24	)
Total realized and unrealized gains (losses):
Included in earnings	—			30			3			33
Included in other comprehensive income — derivative activity	(172		)	6			—			(166		)
Included in other comprehensive income — foreign currency translation activity	(3		)	(43		)	—			(46		)
Included in regulatory liabilities	—			—			11			11
Settlements	56			(8		)	(8		)	40
Transfers of liabilities into Level 3	(2		)	—			—			(2		)
Transfers of assets out of Level 3	118			12			—			130
Balance at September 30	$	(307	)	$	274		$	9		$	(24	)
Total gains for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period	$	5		$	25		$	3		$	33



Derivatives	Maximum Notional Translated to USD		Latest Maturity
Interest Rate (LIBOR and EURIBOR)	$	4,557	2035
Cross-Currency Swaps (Chilean Unidad de Fomento and Chilean Peso)	394		2029
Foreign Currency:
Argentine Peso	233		2026
Chilean Peso	504		2020
Colombian Peso	255		2019
Others, primarily with weighted average remaining maturities of a year or less	326		2020



	Nine Months Ended September 30,
50%-or-less-Owned Affiliates	2017		2016
Revenue	$	532	$	439
Operating margin	91		108
Net income	44		46



Subsidiary	Issuances		Repayments			Gain (Loss) on Extinguishment of Debt
Tietê	$	585	$	(293	)	$	(5	)
IPALCO	532		(480		)	(9		)
Southland	360		—			—
AES Argentina	307		(181		)	65
Los Mina	278		(259		)	(4		)
Gener	243		(78		)	—
Colon	220		—			—
Eletropaulo	189		(147		)	—
Other	261		(509		)	(3		)
Total	$	2,975	$	(1,947	)	$	44



Contingent Contractual Obligations	Amount (in millions)		Number of Agreements	Maximum Exposure Range for Each Agreement (in millions)
Guarantees and commitments	$	806	21	<$1 — 272
Letters of credit under the unsecured credit facility	125		5	$2 — 73
Asset sale related indemnities ⁽¹⁾	27		1	$27
Letters of credit under the senior secured credit facility	9		17	<$1 — 2
Total	$	967	44



	Nine Months Ended September 30, 2017									Nine Months Ended September 30, 2016
	The Parent Company Stockholders’ Equity			NCI			Total Equity			The Parent Company Stockholders’ Equity			NCI			Total Equity
Balance at the beginning of the period	$	2,794		$	2,906		$	5,700		$	3,149		$	3,022		$	6,171
Net income (loss) ⁽¹⁾	181			328			509			(181		)	97			(84		)
Total foreign currency translation adjustment, net of income tax	117			10			127			179			53			232
Total change in derivative fair value, net of income tax	5			3			8			(52		)	(63		)	(115		)
Total pension adjustments, net of income tax	1			19			20			3			7			10
Cumulative effect of a change in accounting principle ⁽²⁾	31			—			31			—			—			—
Fair value adjustment ⁽³⁾	(19		)	—			(19		)	(4		)	—			(4		)
Disposition of businesses	—			—			—			—			18			18
Distributions to noncontrolling interests	—			(261		)	(261		)	(2		)	(293		)	(295		)
Contributions from noncontrolling interests	—			17			17			—			23			23
Dividends declared on common stock	(158		)	—			(158		)	(144		)	—			(144		)
Purchase of treasury stock	—			—			—			(79		)	—			(79		)
Issuance and exercise of stock-based compensation benefit plans	12			—			12			15			—			15
Sale of subsidiary shares to noncontrolling interests	22			47			69			—			17			17
Acquisition of subsidiary shares from noncontrolling interests	200			(85		)	115			(2		)	(3		)	(5		)
Less: Net loss attributable to redeemable stock of subsidiaries	—			9			9			—			8			8
Balance at the end of the period	$	3,186		$	2,993		$	6,179		$	2,882		$	2,886		$	5,768



Details About AOCL Components	Affected Line Item in the Condensed Consolidated Statements of Operations	Three Months Ended September 30,						Nine Months Ended September 30,
Details About AOCL Components		2017			2016			2017			2016
Foreign currency translation adjustment, net
	Loss on disposal and sale of businesses	$	—		$	—		$	(98	)	$	—
	Net income (loss) attributable to The AES Corporation	$	—		$	—		$	(98	)	$	—
Unrealized derivative gains (losses), net
	Non-regulated revenue	$	12		$	20		$	22		$	94
	Non-regulated cost of sales	(2		)	(17		)	(11		)	(54		)
	Interest expense	(20		)	(25		)	(63		)	(86		)
	Foreign currency transaction gains (losses)	14			(3		)	(4		)	18
	Income (loss) from continuing operations before taxes and equity in earnings of affiliates	4			(25		)	(56		)	(28		)
	Income tax benefit (expense)	(5		)	4			6			5
	Loss from continuing operations	(1		)	(21		)	(50		)	(23		)
	Less: Net loss from operations attributable to noncontrolling interests and redeemable stock of subsidiaries	1			5			10			4
	Net income (loss) attributable to The AES Corporation	$	—		$	(16	)	$	(40	)	$	(19	)
Amortization of defined benefit pension actuarial loss, net
	Regulated cost of sales	$	(10	)	$	(4	)	$	(30	)	$	(13	)
	General and administrative expenses	—			—			1			—
	Other expense	(1		)	—			(1		)	—
	Loss from continuing operations before taxes and equity in earnings of affiliates	(11		)	(4		)	(30		)	(13		)
	Income tax benefit	4			2			10			4
	Loss from continuing operations	(7		)	(2		)	(20		)	(9		)
	Net loss from disposal and impairments of discontinued businesses	—			(1		)	—			(1		)
	Net loss	(7		)	(3		)	(20		)	(10		)
	Less: Net loss from operations attributable to noncontrolling interests and redeemable stock of subsidiaries	6			2			16			7
	Net income (loss) attributable to The AES Corporation	$	(1	)	$	(1	)	$	(4	)	$	(3	)
Total reclassifications for the period, net of income tax and noncontrolling interests		$	(1	)	$	(17	)	$	(142	)	$	(22	)



	Three Months Ended September 30,						Nine Months Ended September 30,
Total Adjusted PTC	2017			2016			2017			2016
Reconciliation from Income from Continuing Operations before Taxes and Equity In Earnings of Affiliates:
Income from continuing operations before taxes and equity in earnings of affiliates	$	347		$	294		$	746		$	445
Add: Net equity in earnings of affiliates	24			11			33			25
Less: Income from continuing operations before taxes, attributable to noncontrolling interests	(148		)	(82		)	(454		)	(196		)
Pretax contribution	223			223			325			274
Unrealized derivative losses (gains)	(8		)	5			(7		)	1
Unrealized foreign currency transaction losses (gains)	(21		)	3			(54		)	12
Disposition/acquisition losses (gains)	1			(3		)	107			(5		)
Impairment expense	2			24			264			309
Losses on extinguishment of debt	48			20			43			26
Total Adjusted PTC	$	245		$	272		$	678		$	617

	Three Months Ended September 30,						Nine Months Ended September 30,
Total Adjusted PTC	2017			2016			2017			2016
US SBU	$	129		$	114		$	240		$	257
Andes SBU	62			134			232			279
Brazil SBU	12			6			64			18
MCAC SBU	98			74			256			197
Eurasia SBU	61			46			218			197
Corporate and Other	(117		)	(102		)	(332		)	(331		)
Total Adjusted PTC	$	245		$	272		$	678		$	617



	Nine Months Ended September 30, 2016
Cash flows provided by operating activities of discontinued operations	$	68
Cash flows used in investing activities of discontinued operations	(63		)



IPL
Lower retail margin primarily due to weather	$	(10	)
Other	(3		)
Total IPL Decrease	(13		)
US Generation
Warrior Run primarily due to higher availability and lower maintenance cost due to major outages in 2016	6
Other	4
Total US Generation Increase	10
Other Business Drivers	(2		)
Total US SBU Operating Margin Decrease	$	(5	)



IPL
Decrease due to implementation of new base rates in Q2 2016 which resulted in a favorable change in accrual	$	(18	)
Other	(1		)
Total IPL Decrease	(19		)
DPL
Lower retail margin due to lower regulated rates	(26		)
Lower depreciation expense driven by lower PP&E carrying values from impairments in 2016 and 2017	19
Total DPL Decrease	(7		)
US Generation
Warrior Run primarily due to higher availability and lower maintenance cost due to major outages in 2016, partially offset by a decrease in energy price under the PPA	4
Other	7
Total US Generation Increase	11
Total US SBU Operating Margin Decrease	$	(15	)



Gener
Lower availability of efficient generation resulting in higher replacement energy and fixed costs mainly associated with major maintenance at Ventanas Complex	$	(29	)
Negative impact of new regulation on emissions (green taxes)	(13		)
Lower margin at the SING market primarily associated with lower contract sales and increase in coal prices at Norgener	(8		)
Start of operations at Cochrane Units I and II in July and October 2016, respectively	17
Other	(3		)
Total Gener Decrease	(36		)
Chivor
Lower spot sales mainly associated to lower generation and lower prices	(16		)
Other	1
Total Chivor Decrease	(15		)
Other Business Drivers	(1		)
Total Andes SBU Operating Margin Decrease	$	(52	)



Eletropaulo
Revenue associated with a favorable opinion on the basis calculation for PIS and COFINS taxes from prior years	$	50
Lower fixed costs mainly due to lower bad debt and regulatory penalties	34
Higher tariffs due to annual tariff reset	20
Lower volume mainly due to lower demand resulting from economic decline and migration to free market	(30		)
Other	(2		)
Total Eletropaulo Increase	72
Tietê
Net impact of volume and prices of bilateral contracts due to higher energy purchased	(45		)
Net impact of volume and prices of lower energy purchased in spot market	13
Higher volume due to acquisition of new wind entities - Alto Sertão II	12
Other	2
Total Tietê Decrease	(18		)
Total Brazil SBU Operating Margin Increase	$	54



Dominican Republic
Higher contracted energy sales mainly driven by Los Mina combined cycle commencement of operations in June 2017	$	14
Higher availability driven by Los Mina combined cycle interconnection in 2016	5
Other	6
Total Dominican Republic Increase	25
Total MCAC SBU Operating Margin Increase	$	25



Dominican Republic
Higher energy sales mainly driven by higher contracted capacity	$	32
Higher availability driven by greater major maintenance scope in 2016	13
Other	(7		)
Total Dominican Republic Increase	38
Mexico
Lower maintenance and higher availability	17
Other	4
Total Mexico Increase	21
Other Business Drivers	1
Total MCAC SBU Operating Margin Increase	$	60



Ballylumford
Higher energy and capacity prices	$	4
Other	4
Total Ballylumford Increase	8
Other Business Drivers	(1		)
Total Eurasia SBU Operating Margin Increase	$	7



Kilroot
Higher fair value adjustments of commodity swaps	$	10
Favorable capacity prices due to fixed EUR/GBP rate set by the Regulator	9
Unfavorable clean-dark spread leading to lower dispatch	(6		)
Other	(3		)
Total Kilroot Increase	10
Ballylumford
Higher energy and capacity prices	7
Settlement with offtaker on previous gas transportation charges billed in April 2017	4
Lower maintenance costs due to outages in 2016	3
Other	6
Total Ballylumford Increase	20
Other Business Drivers	5
Total Eurasia SBU Operating Margin Increase	$	35



Increases in:
Accounts receivable, primarily at Gener and Itabo	$	(128	)
Prepaid expenses and other current assets, primarily short-term regulatory assets at Eletropaulo and Sul	(213		)
Inventory, primarily at IPL, Eletropaulo, Itabo and Gener	(47		)
Accounts payable and other current liabilities, primarily at Eletropaulo	306
Other	7
Total decrease in cash from changes in operating assets and liabilities	$	(75	)



Increases in:
Accounts receivable, primarily at Maritza and Eletropaulo	$	(614	)
Prepaid expenses and other current assets, primarily short-term regulatory assets at Eletropaulo and Sul	(530		)
Inventory, primarily at Gener, IPL and DPL	(102		)
Accounts payable and other current liabilities, primarily at Eletropaulo, Maritza and Gener	729
Income taxes payable, net, and other taxes payable, primarily at Gener,Tietê and Eletropaulo	266
Decreases in:
Other liabilities, primarily due to higher deferrals into regulatory liabilities related to energy costs in 2016 compared to 2017 at Eletropaulo	(363		)
Other	(29		)
Total decrease in cash from changes in operating assets and liabilities	$	(643	)



Decreases In:
Capital expenditures ⁽¹⁾	$	51
Short-term investments	221
Increases in:
Acquisitions of businesses, net of cash acquired, and equity method investees (related to the acquisitions of sPower and Alto Sertão II in 2017, partially offset by the acquisition of Distributed Energy in 2016)	(554		)
Restricted cash, debt service and other assets	(318		)
Other investing activities	(31		)
Total increase in net cash used in investing activities	$	(631	)



Decreases in:
Capital expenditures ⁽¹⁾	$	183
Proceeds from the sales of businesses, net of cash sold, and equity method investments (primarily related to the sales of DPLER, Kelanitissa and Jordan in 2016 and the receipt of contingent sales proceeds in 2016 from the sale of Cameroon, partially offset by the sale of Kazakhstan CHPs in 2017)	(118		)
Short-term investments	319
Increases in:
Acquisitions of businesses, net of cash acquired, and equity method investees (related to the acquisitions of sPower and Alto Sertão II in 2017, partially offset by the acquisition of Distributed Energy in 2016)	(545		)
Restricted cash, debt service and other assets	(188		)
Other investing activities	(64		)
Total increase in net cash used in investing activities	$	(413	)



Decreases in:
Growth expenditures at the Andes SBU, primarily due to slower than anticipated productivity by construction contractors at Alto Maipo	$	137
Maintenance and environmental expenditures at the US SBU, primarily due to lower spending at IPALCO on the NPDES compliance and Harding Street refueling projects and decreased spending on CCR compliance	19
Growth expenditures at the Eurasia SBU, primarily due to timing of payments to contractors for Unit 3 expansion at Masinloc	18
Increases in:
Growth expenditures at the US SBU, primarily due to increased spending at Southland repowering	(130		)
Other capital expenditures	7
Total decrease in net cash used for capital expenditures	$	51



Increases in:
Borrowings under the revolving credit facilities, at the Parent Company	$	384
Issuance of recourse debt at the Parent Company ⁽¹⁾	204
Issuance of non-recourse debt, primarily at the US, MCAC, and Brazil SBUs ⁽¹⁾	204
Proceeds from sale of noncontrolling interests related to the sell down of Dominican Republic business in 2017	60
Other financing activities	(23		)
Total increase in net cash provided by financing activities	$	829



Decreases in:
Proceeds from the sale of redeemable stock of subsidiaries at IPALCO	$	(134	)
Increases in:
Borrowings under the revolving credit facilities, primarily at the Parent Company and net decrease in repayment at the US SBU	415
Issuance of non-recourse debt, primarily at the Brazil, MCAC, and US SBUs⁽¹⁾	574
Proceeds from sale of noncontrolling interests related to the sell down of Dominican Republic business in 2017	60
Other financing activities	21
Total increase in net cash provided by financing activities	$	936



US SBU Q3 2017 vs. Q3 2016 (QTD)
Lower operating margin, net of lower depreciation of $4 million	$	(9	)
Higher payments for inventory purchases primarily due to inventory optimization efforts at DPL and IPL that occurred in 2016	(20		)
Timing of payments for general accounts payable at DPL	(13		)
Timing of interest payments primarily at DPL and IPL	(13		)
Other	5
Total US SBU Operating Cash Decrease	$	(50	)



US SBU Q3 2017 vs. Q3 2016 (YTD)
Lower operating margin, net of lower depreciation of $26	$	(41	)
Higher payments for inventory purchases primarily due to inventory optimization efforts at DPL and IPL that occurred in 2016	(66		)
Timing of payments for purchased power and general accounts payable at DPL	(42		)
Timing of interest payments primarily at DPL and IPL	(19		)
Lower collections at DPL, primarily due to the settlement of receivable balances at DPLER upon its sale in Q1 2016	(11		)
Higher collections at IPL, primarily due to higher A/R balances in December 2016 resulting from favorable weather and the 2016 rate order	32
Total US SBU Operating Cash Decrease	$	(147	)



Andes SBU Q3 2017 vs. Q3 2016 (QTD)
Lower operating margin, net of increased depreciation of $7	$	(45	)
Increase in other working capital requirements primarily due to delay in collections at Gener	(59		)
Increase in collections of financing receivables in Argentina, resulting primarily from the commencement of commercial operations at the Guillermo Brown plant and the impact of major maintenance in 2016	44
Environmental tax accruals in Chile impacting margin but not operating cash flow	13
Total Andes SBU Operating Cash Decrease	$	(47	)



Andes SBU Q3 2017 vs. Q3 2016 (YTD)
Higher operating margin, net of increased depreciation of $32	$	18
Lower tax payments at Chivor and Argentina	57
Increase in collections of financing receivables in Argentina, resulting primarily from the commencement of commercial operations at the Guillermo Brown plant	50
Environmental tax accruals in Chile impacting margin but not operating cash flow	37
Increase in other working capital requirements primarily due to delay in collections at Gener	(60		)
Lower collections at Chivor, primarily due higher receivables in Q1 2016 resulting from higher sales in Q4 2015	(35		)
Increase in interest payments to reflect the cessation of capitalization of interest for the Cochrane project	(14		)
Lower VAT refunds, primarily at Alto Maipo and Cochrane	(14		)
Other	(1		)
Total Andes SBU Operating Cash Increase	$	38