Enel Americas (ENIA) 20-F 2018 FY Annual report (foreign)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

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

For the fiscal year ended December 31, 2021

OR

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

For the transition period from to

OR

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

Date of event requiring this shell company report,

Commission file number: 001-12440

ENEL AMÉRICAS S.A.

(Exact name of Registrant as specified in its charter)

ENEL AMÉRICAS S.A.

(Translation of Registrant’s name into English)

CHILE

(Jurisdiction of incorporation or organization)

Santa Rosa 76, Santiago, Chile

(Address of principal executive offices)

Rafael de la Haza, phone: (56-2) 2353-4400, ir.enelamericas@enel.com, Av. Santa Rosa 76, Piso 15, Comuna de Santiago, Santiago, Chile

(Name, Telephone, Email, and Address of Company Contact Person)

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

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
American Depositary Shares Representing Common Stock	ENIA	New York Stock Exchange
Common Stock, no par value *	*	New York Stock Exchange
US$ 600,000,000 4.00% Notes due October 25, 2026	ENIA26A	New York Stock Exchange
US$ 858,000 6.60% Notes due December 1, 2026	ENIA26	New York Stock Exchange

* Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Shares of Common Stock: 76,086,311,036

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

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐ Yes ☒ No

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 ¨ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Emerging growth company

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, 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. ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ⌧

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP ☐	International Financial Reporting Standards as issued by the International Accounting Standards Board ☒	Other ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. ☐ Item 17 ☐ Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

Auditor Firm ID: 1273 Auditor Name: KPMG Auditores Consultores SpA Auditor Location: Santiago, Chile

Enel Américas Simplified Organizational Structure⁽¹⁾

As of the date of this Report

(1) Only principal operating subsidiaries are presented here. The percentage listed in the box for each of Enel Américas’ consolidated subsidiaries represents our economic interest in such subsidiary. Please refer to “Presentation of Information” for an explanation of the calculation of economic interest.

(2) In November 2021, EGP Brasil was merged into Enel Brasil. The Brazilian subsidiaries holding the NCRE generation assets in Brazil formerly held by EGP Brasil are now subsidiaries of Enel Brasil.

(3) In March 2022, Codensa, EGP Colombia, and ESSA2 merged into Emgesa. The new corporate name of the merged companies is Enel Colombia. As a result of the merger, Enel Colombia conducts the generation and distribution activities of Emgesa and Codensa, respectively.

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TABLE OF CONTENTS

		Page
GLOSSARY		4
INTRODUCTION		10
PRESENTATION OF INFORMATION		11
FORWARD-LOOKING STATEMENTS		13
PART I
Item 1.	Identity of Directors, Senior Management and Advisers	14
Item 2.	Offer Statistics and Expected Timetable	14
Item 3.	Key Information	14
Item 4.	Information on the Company	25
Item 4A.	Unresolved Staff Comments	80
0
Item 5.	Operating and Financial Review and Prospects	80
Item 6.	Directors, Senior Management and Employees	144
Item 7.	Major Shareholders and Related Party Transactions	152
Item 8.	Financial Information	154
Item 9.	The Offer and Listing	156
Item 10.	Additional Information	156
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	172
Item 12.	Description of Securities Other Than Equity Securities	176
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	177
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	177
Item 15.	Controls and Procedures	177
Item 16.	Reserved	178
Item 16A.	Audit Committee Financial Expert	178
Item 16B.	Code of Ethics	178
Item 16C.	Principal Accountant Fees and Services	181
Item 16D.	Exemptions from the Listing Standards for Audit Committees	181
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	182
Item 16F.	Change in Registrant’s Certifying Accountant	182
Item 16G.	Corporate Governance	182
Item 16H.	Mine Safety Disclosure	183
Item 16I.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	183
PART III
Item 17.	Financial Statements	184
Item 18.	Financial Statements	184
Item 19.	Exhibits	184

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GLOSSARY

ADR	American Depositary Receipt(s)	A certificate issued by our depositary that represents ADS, or American Depositary Shares.
ADS	American Depositary Share(s)	An equity interest in our company that is issued by Citibank, N.A., as the depositary, in respect of shares of our company held by the depositary. Each ADS represents 50 shares, and ADS are traded on the New York Stock Exchange.
AFP	Administradora de Fondos de Pensiones	A legal entity that manages a Chilean pension fund.
ANEEL	Agência Nacional de Energia Elétrica	Brazilian governmental agency for electric energy.
Brazilian MME	Ministério de Minas y Energia	Brazilian Ministry of Mines and Energy.
Cachoeira Dourada	Enel Green Power Cachoeira Dourada S.A.	Brazilian generation subsidiary owned by Enel Brasil. Formerly Centrais Elétricas Cachoeira Dourada S.A.
CAMMESA	Compañía Administradora del Mercado Mayorista Eléctrico S.A.	Argentine autonomous entity in charge of the Mercado Eléctrico Mayorista (Wholesale Electricity Market), or MEM. CAMMESA’s stockholders are generation, transmission, distribution companies, large users, and the Secretariat of Energy.
CCEE	Câmara de Comercialização de Energia Elétrica	Electricity Trading Chamber or Wholesale Clearing House
Chilean Stock Exchanges	Chilean Stock Exchanges	The two stock exchanges located in Chile: the Santiago Stock Exchange and the Electronic Stock Exchange.
Cien	Enel CIEN S.A.	Brazilian transmission subsidiary, wholly owned by Enel Brasil. Formerly Companhia de Interconexão Energética S.A.
CND	Centro Nacional de Despacho	Colombian National Dispatch Center in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.
CMF	Comisión para el Mercado Financiero	Chilean Financial Market Commission, the governmental authority that supervises the financial markets.

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Codensa	Codensa S.A. E.S.P.	Colombian distribution subsidiary that operates mainly in Bogotá and whose voting power is controlled by us.
COES	Comité de Operación Económica del Sistema	Peruvian entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.
Costanera	Enel Generación Costanera S.A.	A publicly held Argentine generation company controlled by us. Formerly Central Costanera S.A.
CREG	Comisión de Regulación de Energía y Gas	Colombian Commission for the Regulation of Energy and Gas.
CTM	Compañía de Transmisión del Mercosur S.A.	Argentine transmission company and a subsidiary of Enel Brasil.
Dock Sud	Central Dock Sud S.A.	Argentine generation subsidiary.
Edesur	Empresa Distribuidora del Sur S.A.	Argentine distribution subsidiary, with a concession area in the southern part of the Buenos Aires greater metropolitan area.
EGP Colombia	Enel Green Power Colombia S.A.S. ESP	A wholly owned subsidiary located in Colombia engaged in renewable energy generation.
EGP Costa Rica	Enel Green Power Costa Rica S.A.	A wholly owned subsidiary located in Costa Rica engaged in renewable energy generation.
EGP Guatemala	Enel Green Power Guatemala S.A.	A wholly owned subsidiary located in Guatemala engaged in renewable energy generation.
EGP Panama	Enel Green Power Panamá S.R.L.	A wholly owned subsidiary located in Panama engaged in renewable energy generation.
EGP Peru	Enel Green Power Perú S.A.C.	A wholly owned subsidiary located in Peru engaged in renewable energy generation.
EGP Volta Grande	Enel Green Power Volta Grande S.A.	Brazilian generation subsidiary located in the State of Minas Gerais, in Brazil, wholly owned by Enel Brasil.
El Chocón	Enel Generación El Chocón S.A.	Argentine generation company with two hydroelectric plants, El Chocón and Arroyito, both located in the Limay River, Argentina, and our subsidiary. Formerly Hidroeléctrica El Chocón S.A.
Emgesa	Emgesa S.A. E.S.P.	Colombian generation subsidiary whose voting power is controlled by us.

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Enel	Enel S.p.A.	Our Italian parent company with multinational operations in the power and gas markets, with an 82.3% beneficial ownership of Enel Américas as of December 31, 2021.
Enel Américas	Enel Américas S.A.	Our company, a publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, headquartered in Chile, with subsidiaries engaged primarily in the generation and distribution of electricity in Argentina, Brazil, Colombia, Costa Rica, Guatemala, Panama, and Peru, and controlled by Enel. The registrant of this Report. Formerly known as Enersis S.A.
Enel Argentina	Enel Argentina S.A.	Argentine holding company subsidiary.
Enel Brasil	Enel Brasil S.A.	Brazilian holding company subsidiary. Formerly known as Endesa Brasil S.A.
Enel Distribution Ceara	Companhia Energética Do Ceará S.A.	A publicly held Brazilian distribution subsidiary operating in the state of Ceará controlled by Enel Brasil. Also commercially known as Enel Distribuição Ceará.
Enel Distribution Goias	CELG Distribuição S.A.	Brazilian distribution subsidiary that operates a concession in the state of Goias, owned by Enel Brasil. Also commercially known as Enel Distribuição Goiás.
Enel Distribution Peru	Enel Distribución Perú S.A.A.	A publicly held Peruvian distribution subsidiary controlled by Enel Peru, with a concession area in the northern part of Lima. Formerly Empresa de Distribución Eléctrica de Lima Norte S.A. or Edelnor.
Enel Distribution Rio	Ampla Energia e Serviços S.A.	A publicly held Brazilian distribution subsidiary operating in Rio de Janeiro, controlled by Enel Brasil. Also commercially known as Enel Distribuição Rio.
Enel Distribution Sao Paulo	Eletropaulo Metropolitana Eletricidade de São Paulo S.A.	A publicly held Brazilian distribution subsidiary operating in Sao Paulo, controlled by Enel Brasil. Also commercially known as Enel Distribuição São Paulo.
Enel Generation Peru	Enel Generación Perú S.A.A.	A publicly held Peruvian generation subsidiary controlled by Enel Peru. Formerly Edegel S.A.A.

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Enel Generation Piura	Enel Generación Piura S.A.	A publicly held Peruvian generation subsidiary controlled by Enel Peru. Formerly Empresa Eléctrica de Piura S.A. or EEPSA.
Enel Peru	Enel Perú S.A.C.	Peruvian holding company subsidiary.
Enel Trading Argentina	Enel Trading Argentina S.R.L.	Energy trading subsidiary with operations in Argentina. Formerly Central Comercializadora de Energía S.A. or CEMSA.
Enel X Brasil	Enel X Brasil S.A.	A Brazilian subsidiary engaged in developing, implementing, and selling products and services different from the sale of energy or energy distribution under concessions, and associated services in Brazil, wholly owned by Enel Brasil.
Enel X Peru	Enel X Perú S.A.C.	A Peruvian subsidiary engaged in developing, implementing, and selling products and services different from the sale of energy or energy distribution under concessions, and associated services in Peru, wholly owned by Enel Peru.
ENRE	Ente Nacional Regulador de la Electricidad	Argentine national regulatory authority for the energy sector.
Fortaleza	Central Geradora Termeletrica Fortaleza S.A.	Brazilian generation subsidiary that operates in the state of Ceará and is wholly owned by Enel Brasil. Also commercially known as Enel Geração Fortaleza.
GEB	Grupo Energía Bogotá S.A.	Colombian state-owned financial and energy holding company, with investments in electricity generation, transmission, trading and distribution and natural gas transmission, distribution, and trading sectors. Formerly Empresa Energía de Bogotá S.A. or EEB.
IFRS	International Financial Reporting Standards	International Financial Reporting Standards as issued by the International Accounting Standards Board (IASB).
LNG	Liquefied Natural Gas	Liquefied natural gas.
MEM	Mercado Eléctrico Mayorista	Wholesale Electricity Market. There are such markets in each of Argentina, Colombia, and Peru. In Peru it is known as the Mercado Mayorista de Electricidad (MME).
MINEM	Ministerio de Energia y Minas	Peruvian Ministry of Energy and Mines.
NCRE	Non-Conventional Renewable Energy	Energy sources continuously replenished by natural processes, such as wind, biomass,

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		mini-hydro, geothermal, wave, solar, or tidal energy.
NIS	Sistema Interconectado Nacional	National interconnected electric system. There are such systems in each of Argentina, Brazil, and Colombia.
OEF	Obligación de Energía Firme	Colombian firm energy commitment of generators to guarantee energy in the long term.
ONS	Operador Nacional do Sistema Elétrico	National Electric System Operator. Brazilian non-profit private entity responsible for the planning and coordination of operations in interconnected systems.
OSM	Ordinary Shareholders’ Meeting	Ordinary Shareholders’ Meeting
PPA	Power Purchase Agreement	Power Purchase Agreement
PLD	Preço de Liquidação das Diferenças	Settlement price for differences. It is the price assigned to sales and purchases of energy on the Brazilian spot market.
SAIDI	System Average Interruption Duration Index	Index of average duration of interruptions in the power supply.
SAIFI	System Average Interruption Frequency Index	Index of average frequency of interruptions in the power supply.
SEE	Secretaria de Energía Argentina	The Argentine Ministry of Energy and Mining manages the electricity industry through the Argentine Secretary of Energy.
SEIN	Sistema Eléctrico Interconectado Nacional	Peruvian national interconnected electricity system.
TESA	Transportadora de Energía S.A.	Transmission company with operations in Argentina and a subsidiary of Enel Brasil, our subsidiary.
UF	Unidad de Fomento	Chilean inflation-indexed, Chilean peso-denominated monetary unit equivalent to Ch$ 30,991.74 as of December 31, 2021.
UPME	Unidad de Planificación Minero Energética	Colombian energy and mining planning unit responsible for planning the expansion of the generation and transmission systems.
VAD	Valor Agregado de Distribución	Value-added from distribution of electricity.
XM	Expertos de Mercado S.A. E.S.P.	A subsidiary of Interconexión Eléctrica S.A. (“ISA”), a Colombian company that provides system management in real-time services in

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electrical, financial, and transportation sectors.

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INTRODUCTION

As used in this Report on Form 20-F (“Report”), first-person personal pronouns such as “we,” “us” or “our” as well as “Enel Américas” and “the Company” refer to Enel Américas S.A. and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries and jointly controlled companies and associates is expressed in terms of our economic interest as of December 31, 2021.

We are a Chilean company engaged through our subsidiaries and jointly controlled companies in the electricity generation, transmission, and distribution businesses in Argentina, Brazil, Colombia, Costa Rica, Guatemala, Panama, and Peru. We participate in the generation and transmission businesses mainly through our subsidiaries Costanera, Dock Sud, and El Chocón in Argentina; Cachoeira Dourada, Fortaleza, EGP Volta Grande, and Cien in Brazil; Emgesa in Colombia; EGP Costa Rica in Costa Rica; EGP Guatemala in Guatemala; EGP Panama in Panama; and Enel Generation Peru and Enel Generation Piura in Peru. In the distribution business, our principal subsidiaries are Edesur in Argentina; Enel Distribution Ceara, Enel Distribution Rio, Enel Distribution Sao Paulo, and Enel Distribution Goias in Brazil; Codensa in Colombia; and Enel Distribution Peru in Peru. For additional information relating to our principal subsidiaries and associates, please see “Item 4. Information on the Company — C. Organizational Structure — Principal Subsidiaries and Affiliates.”

We are a publicly held limited liability stock corporation headquartered in Chile and organized on June 19, 1981, under the laws of the Republic of Chile. During 2016, we completed a corporate reorganization to separate our Chilean businesses from our non-Chilean businesses as a separate publicly held limited liability stock corporation, Enel Chile S.A. We continue to own and operate the non-Chilean businesses. As part of this process, the former Enersis S.A. changed its name to Enel Américas S.A. on December 1, 2016.

As of the date of this Report, Enel S.p.A. (“Enel”), an Italian energy company with multinational operations in the power and gas markets, owns a beneficial interest of 82.3% of us and is our ultimate controlling shareholder. For additional information relating to the Merger with EGP Americas, please see “Item 4. Information on the Company — A. History and Development of the Company.”

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PRESENTATION OF INFORMATION

Financial Information

In this Report, unless otherwise specified, references to “US$” or “U.S. dollars” are to dollars of the United States of America (“United States”); references to “Ar$” or “Argentine pesos” are to the currency of Argentina; references to “R$,” or “reais” are to Brazilian reais, the currency of Brazil; references to “Ch$” or “pesos” are to Chilean pesos, the currency of Chile; references to “COP$” or “Colombian pesos” are to the currency of Colombia; references to “soles” are to Peruvian soles, the currency of Peru; references to “EUR” are to Euro, the currency of the European Union; and references to “UF” are to Unidades de Fomento. The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is adjusted daily to reflect changes in the official Consumer Price Index (“CPI”) of the Chilean National Institute of Statistics (Instituto Nacional de Estadísticas or “INE”). The UF is adjusted in monthly cycles. Each day in the period beginning on the tenth day of the current month through the ninth day of the succeeding month, the nominal peso value of the UF is indexed to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month. As of December 31, 2021, one UF was equivalent to Ch$ 30,991.74. The U.S. dollar equivalent of one UF was US$ 36.69 as of December 31, 2021, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2021, of Ch$ 844.69 per US$ 1.00. The U.S. dollar observed exchange rate (dólar observado) (the “Observed Exchange Rate”), which is reported by the Central Bank of Chile and published daily on its webpage, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Unless the context specifies otherwise, all amounts translated from Chilean pesos to U.S. dollars or vice versa, or from UF to Chilean pesos, have been carried out at the rates applicable as of December 31, 2021. Our functional currency is the U.S. dollar.

We have prepared our consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). All our subsidiaries are integrated, and all their assets, liabilities, income, expenses, and cash flows are included in the consolidated financial statements after making the adjustments and eliminations related to intra-group transactions. Our interest in associated companies over which we exercise significant influence is included in our consolidated financial statements using the equity method. For detailed information regarding consolidated entities, jointly controlled entities, and associated companies, see Notes 2.4, 2.5, and 2.6 of the Notes to our consolidated financial statements.

This Report may contain translations of Chilean peso amounts into U.S. dollars at specified rates. Unless otherwise indicated, the Chilean peso equivalent for information in U.S. dollars is based on the Observed Exchange Rate for December 31, 2021, as defined in “Item 3. Key Information — A. Selected Financial Data — Exchange Rates.” The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. No representation is made that the Chilean peso or U.S. dollar amounts disclosed in this Report could have been or could be converted into U.S. dollars or Chilean pesos at such rate or any other rate. See “Item 3. Key Information — A. Selected Financial Data — Exchange Rates.”

Technical Terms

References to “TW” are to terawatts (10¹² watts or a trillion watts); references to “GW” and “GWh” are to gigawatts (10⁹ watts or a billion watts) and gigawatt-hours, respectively; references to “MW” and “MWh” are to megawatts (10⁶ watts or a million watts) and megawatt-hours, respectively; references to “kW” and “kWh” are to kilowatts (10³ watts or a thousand watts) and kilowatt-hours, respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. References to “BTU” and “MBTU” are to a British thermal unit and million British thermal units, respectively. A “BTU” is an energy unit equal to approximately 1,055 joules. References to “Hz” are to hertz, and references to “mtpa” are to metric tons per annum. Unless otherwise indicated, statistics provided in this Report concerning the installed capacity of electricity generation facilities are expressed in MW. One TW equals 1,000 GW, one GW equals 1,000 MW, and one MW equals 1,000 kW. The installed capacity we present in this Report corresponds to the net installed capacity, which takes into account the MW that each power plant consumes for its operation. Starting in 2020, the electricity sales we present in this Report correspond to gross energy sales. 2019 amounts have been updated to correspond to this new presentation. Beginning in 2020, in calculating the number of customers we consider all customers with a current contract in a given period (rather than only those customers with a current contract who were supplied with energy and billed for it in a given period). 2019 amounts have been updated to correspond to this new presentation.

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Statistics relating to aggregate annual electricity production are expressed in GWh and based on a year of 8,760 hours, except for a leap year like 2020, which is based instead on 8,784 hours. Statistics relating to installed capacity and production of the electricity industry do not include electricity of self-generators.

Energy losses experienced by generation companies during transmission are calculated by subtracting the number of GWh of energy sold from the number of GWh of energy generated (excluding their energy consumption and losses on the part of the power plant) within a given period. Losses are expressed as a percentage of total energy generated.

Energy losses during distribution are calculated as the difference between total energy purchased (GWh of electricity demand, including own generation) and the energy sold excluding tolls and energy consumption not billed (also measured in GWh) within a given period. Distribution losses are expressed as a percentage of the total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical losses.

Calculation of Economic Interest

In this Report, references are made to the “economic interest” of Enel Américas in its related companies. We could have a direct and indirect interest in such companies. In circumstances in which we do not directly own an interest in a related company, our economic interest in such ultimate affiliated company is calculated by multiplying the percentage of economic interest in a directly held related company by the percentage of economic interest of any entity in the ownership chain of such affiliated company. For example, if we directly own a 6% equity stake in an affiliated company and 40% is directly held by our 60%-owned subsidiary, our economic interest in such associate would be 60% times 40% plus 6%, equal to 30%.

Rounding

Figures included in this Report have been rounded for ease of presentation. Due to rounding, the sums in tables do not always exactly equal the sums of the entries.

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FORWARD-LOOKING STATEMENTS

This Report contains statements that are or may constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements appear throughout this Report and include statements regarding our intent, belief, or current expectations, including but not limited to any statements concerning:

● our capital investment program;

● trends affecting our financial condition or results of operations;

● our dividend policy;

● the future impact of competition and regulation;

● political and economic conditions in the countries in which our related companies or we operate or may operate in the future;

● any statements preceded by, followed by, or that include the words “believes,” “expects,” “predicts,” “anticipates,” “intends,” “estimates,” “should,” “may,” or similar expressions; and

● other statements contained or incorporated by reference in this Report regarding matters that are not historical facts.

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such forward-looking statements. Factors that could cause actual results to differ materially include but are not limited to:

● demographic developments, political events, economic fluctuations, social unrest, public health crises and pandemics, and interventionist measures by authorities in the markets in South America in which we operate;

● hydrology, droughts, flooding, and other weather conditions;

● changes in the environmental regulations and the regulatory framework of the electricity industry in one or more of the countries in which we operate;

● our ability to implement proposed capital expenditures, including our ability to arrange financing where required;

● the nature and extent of future competition in our principal markets; and

● the factors discussed below under “Risk Factors.”

You should not place undue reliance on such statements, which speak only as of the date that they were made. Our independent registered public accounting firm has not examined or compiled the forward-looking statements and, accordingly, does not provide any assurance concerning such statements. You should consider these cautionary statements together with any written or oral forward-looking statements that we may issue in the future. We do not undertake any obligation to release publicly any revisions to forward-looking statements contained in this Report to reflect later events or circumstances or the occurrence of unanticipated events, except as required by law.

For all these forward-looking statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

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PART I

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

A.  [Reserved].

B.  Capitalization and Indebtedness.

Not applicable.

C.  Reasons for the Offer and Use of Proceeds.

Not applicable.

D.  Risk Factors.

Material Risks Related to Our Business

Our businesses depend heavily on hydrology and are affected by droughts, flooding, storms, ocean currents, and other chronic changes in weather conditions as a result of climate change.

The fight against climate change is a major global challenge that exposes our businesses to a variety of medium- and long-term risks. Our generation business could be negatively affected by arid hydrological conditions, which could negatively affect our ability to dispatch energy from our hydroelectric generation facilities. Regional hydrological conditions have often been subject to two weather phenomena dealing with ocean currents - El Niño and La Niña - that influence rainfall and may result in drought or flooding, depending on the region affected. In the past, El Niño has affected hydrologic conditions in Colombia, where 86% of our installed capacity is hydroelectric, leading to rainfall deficits, high temperatures, and higher energy prices in some years, and unusually intensive rains, flooding, and landslides that negatively impacted our hydroelectric power plants in other years. Each ocean current event is unique and, depending on its intensity and duration, the magnitude of the social and economic effects could be material.

Our distribution business is also affected by inclement weather, mainly in Argentina. With extreme temperatures, demand can increase significantly within a short period, affecting service and resulting in service outages that may result in fines. Depending on weather conditions, results obtained by our distribution businesses can vary from year to year.

Our operating expenses increase during drought periods when thermal power plants, which have higher operating costs relative to hydroelectric power plants, are dispatched more frequently. Depending on our commercial obligations, we may need to buy electricity at higher spot prices to comply with our contractual supply obligations. Beyond increasing operating costs, the cost of these electricity purchases may exceed our contracted electricity sale prices, thus potentially producing losses from those contracts. For further information concerning the effect of hydrology on our business and financial results, please refer to “Item 5. Operating and Financial Review and Prospects— A. Operating Results — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company—a. Generation and Transmission Business.”

Droughts also indirectly affect the operation of our thermal power plants, including our facilities that use natural gas, fuel oil, or coal. Our thermal power plants require water for cooling, and droughts may reduce water availability and increase transportation costs. As a result, we may have to purchase water from agricultural areas that are also experiencing water shortages. These water purchases may increase our operating costs and require us to negotiate further with the local communities. If such negotiations were unsuccessful, we may be unable to operate our power plants.

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A full recovery from the droughts affecting the regions where most of our hydroelectric power plants are located may require an extended period, and new drought periods may recur in the future. Climate change may increase the likelihood of prolonged droughts exacerbating the risks described above, which would have a further negative effect on our business, results of operations, and financial condition.

We are subject to physical, operational, and financial risks related to climate change effects.

The electricity generated by our solar and wind generation facilities is highly dependent on climate factors other than hydrology, including suitable solar and wind conditions, which, even under normal operating circumstances, can vary greatly. Climate change may also have long-term effects on wind patterns and the amount of solar energy received at a particular solar facility, reducing electricity generated by these facilities. Although we base our business decisions on solar and wind studies for each renewable energy facility, actual conditions may not conform to the findings of these studies. They may be affected by changes in weather patterns, including the potential impact of climate change.

If our renewable energy production falls below anticipated levels, we may have to dispatch our backup thermal power plants to make up the electricity generation shortfall. Our thermal power plants have higher operating costs and generate greenhouse gas (GHG) emissions. We may also need to buy electricity in the spot market to fulfill our solar and wind generation facilities’ contractual supply obligations, which may be at prices higher than the contracted electricity sales. In 2021, spot prices reached historic highs. These impacts could increase our costs or result in losses and have a material adverse effect on our business, results of operations, and financial condition.

We depend on distributions from our subsidiaries to meet our payment obligations.

We rely on cash from dividends, loans, interest payments, capital reductions, and other distributions from our subsidiaries to pay our obligations. Such payments and distributions may be subject to legal constraints, such as dividend restrictions, fiduciary obligations, contractual limitations, and foreign exchange controls imposed by local authorities.

Historically, we have not always accessed some of our operating subsidiaries’ cash flows due to government regulations, strategic considerations, economic conditions, and credit restrictions. In the future, we may not always be able to immediately rely on cash flows from operating subsidiaries to repay our debt.

Dividend Limits and Other Legal Restrictions: Some of our subsidiaries are subject to legal reserve requirements and other restrictions on dividend payments. Other legal restrictions, such as foreign currency controls, may limit the ability of our subsidiaries to pay dividends and make loan payments or other distributions to us. Their directors’ fiduciary duties to their minority shareholders may restrict the ability of any of our subsidiaries that are not wholly owned to distribute cash to us. Furthermore, local authorities may force some of our subsidiaries, under applicable regulation, to reduce or eliminate dividend payments. These restrictions could impede our subsidiaries from distributing cash to us under certain circumstances.

Contractual Constraints: Distribution restrictions included in certain credit agreements of our subsidiaries in Brazil, may prevent dividends and other distributions to shareholders if they do not comply with specified financial ratios.

Operating Results of Our Subsidiaries: Our subsidiaries’ ability to pay dividends or make loan payments or other distributions to us is limited by their operating results. To the extent that any of our subsidiaries’ cash requirements exceed their available cash, they will not be able to make funds available to us. Insufficient cash flows from our subsidiaries may result in their inability to meet debt obligations and the need to seek waivers to comply with some debt covenants. To a limited extent, these subsidiaries may require guarantees or other emergency measures from us as shareholders, especially those located in Brazil and Argentina. For further details regarding financial support provided to our Brazilian subsidiaries, please refer to “Item 7. Major Shareholders and Related Party Transactions — B. Related Party Transactions.”

The currency of any dividend paid by our subsidiaries is subject to depreciation in relation to our functional currency, which may adversely affect our ability to pay dividends to shareholders. The situations described above could adversely affect our business, results of operations, and financial condition.

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Construction and operation of power plants may encounter significant delays, stoppages, cost overruns, and stakeholder opposition that may damage our reputation and impair our goodwill with stakeholders.

Our power plant projects may be delayed in obtaining regulatory approvals or may face shortages and increases in the price of equipment, materials, or labor. They may be subject to construction delays, strikes, accidents, and human error. Any such event could negatively affect our business, results of operations, and financial condition.

Market conditions may change significantly between the approval and completion of a project, which, in some cases, may decrease its profitability or render it impracticable. Deviations in market conditions, such as estimates of timing and expenditures, may lead to cost overruns and delays in project completion that widely exceed our initial forecasts. In turn, this may have a material adverse effect on our business, results of operations, and financial condition.

We may develop new projects in locations with challenging geographical topography, such as mountain slopes, high altitudes, jungles, or other areas with limited access. Additionally, given some projects’ locations, there may be additional inherent risks to archaeological heritage sites. These factors may also lead to significant delays and cost overruns.

The operation of our power plants, especially those that are coal-fired, may also affect our goodwill with stakeholders due to GHG emissions that could adversely affect the environment and local residents. In addition, communities might have their own interests and different perceptions of the company, being influenced by other stakeholders or motivations unrelated to the project. Therefore, if the company fails to engage with its relevant stakeholders, we may face opposition, which could negatively affect our reputation, impact operations, or lead to litigation threats or actions.

Our reputation is the foundation of our relationship with key stakeholders and other constituencies. Any damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders, possibly leading to the abandonment of projects and operations, which could cause our share prices to drop and hinder our ability to attract and retain valuable employees. Any of these outcomes could result in an impairment of our goodwill with stakeholders. If we do not effectively manage these sensitive issues, they could adversely affect our business, results of operations, and financial condition.

Our long-term electricity sales contracts are subject to fluctuations in the market prices of certain commodities, energy, and other factors.

We have exposure to fluctuations in certain commodity market prices that affect our long-term electricity sales contracts. These contracts commit our generation subsidiaries to material obligations as selling parties and contain prices indexed to different commodities, exchange rates, inflation, and the market price of electricity. Unfavorable changes to these indices would reduce the rates we can charge under these contracts, which could adversely affect our business, results of operations, and financial condition.

We are subject to incremental risks in distribution markets that are becoming more liberalized.

In some countries, our distribution customers who meet the minimum and maximum demand requirements may freely choose unregulated tariffs. This flexibility may adversely affect our operating income. In some cases, customers may choose an alternative energy provider, which could adversely affect our business, results of operations, and financial condition.

If third-party electricity transmission facilities, gas pipeline infrastructure, or fuel supply contracts fail to provide us with adequate service, we may be unable to deliver the electricity we sell to our final customers.

We depend on transmission facilities owned and operated by other companies to deliver the electricity we sell. This dependence exposes us to several risks. If the transmission is disrupted, or its capacity is inadequate, we may be unable to sell and deliver our electricity, particularly electricity generated by our solar and wind plants, which requires more flexibility. If a region’s power transmission infrastructure is inadequate, our recovery of sales costs and profits may be insufficient. If restrictive transmission price regulations are imposed, transmission companies that we rely on may not have sufficient incentives to invest in expanding their infrastructure, which could unfavorably affect our results of operations and financial condition or affect our ability to deploy our portfolio of projects under development. The

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construction of new transmission lines may take longer than in the past, mainly because of sustainability, social, and environmental requirements that create uncertainties regarding project completion timing. As a result, in some of the countries in which we operate, renewable energy generation projects are being completed faster than new transmission projects, creating a backlog of electricity that is difficult to transmit through current transmission systems. In Argentina, for example, the lack of investment in transmission lines will reduce incentives for the development of renewable energy projects.

We also rely on pipelines to obtain natural gas, mainly in Peru, where more than 50% of our generation capacity is thermal. In recent years, the Peruvian system has occasionally faced gas and electricity shortages due to a lack of sufficient capacity in the pipeline and transmission lines, which led to higher spot prices. Depending on the facility type, our thermal generation power plants purchase gas, coal, diesel, and other fuels to produce electricity. Any supply contract breach or supply shortage may prevent our facilities from producing electricity on time.

We may be unable to reach satisfactory collective bargaining agreements with our unionized employees or retain key employees in labor conflict cases.

Our business relies on attracting and retaining many highly specialized employees, and a large percentage of our employees are members of unions with whom we have collective bargaining agreements that must be renewed regularly. Our business, results of operations, and financial condition could be unfavorably affected by a failure to reach a collective bargaining agreement with any labor union or by a deal with a labor union that contains terms we view as unfavorable. Laws in many of the countries in which we operate provide legal mechanisms for judicial authorities to impose a collective bargaining agreement if the parties cannot agree. Specific actions such as strikes, walkouts, or work stoppages by these employees could negatively impact our business, results of operations, financial condition, and reputation.

We may be unable to enter into suitable acquisitions or successfully integrate businesses that we acquire.

On an ongoing basis, we carry out mergers and review acquisition prospects to expand our operations, which may increase our market coverage or provide synergies with our existing businesses. However, there can be no assurance that we will be able to identify and acquire suitable companies in the future. The acquisition and integration of independent companies that we do not control may be a complicated, costly, and time-consuming process that may strain our resources and relationships with our employees and customers.

These mergers and acquisitions may not ultimately be successful or achieve the expected benefits and may encounter delays or difficulties in connection with the integration of their operations, due to a number of factors, including but not limited to:

● inconsistencies in standards, controls, procedures and policies, business cultures, and compensation structures;

● difficulties in integrating various business-specific operating procedures and systems, as well as our financial, accounting, information, and other systems;

● complications in retaining key employees, customers, and suppliers;

● unexpected transaction costs or failures in the assessed value or a proper projection of the potential benefits and synergies; and

● diversion of our management’s attention from their other responsibilities.

Any of these risks encountered in the integration process could have a material adverse effect on our revenues, expenses, results of operations, and financial condition.

Interruption in or failure of our information technology, control, and communications systems or cyberattacks to or cybersecurity breaches of these systems could have a material adverse effect on our business, results of operations, and financial condition.

We operate in an industry that requires the continued operation of sophisticated information technology, control, and communications systems (“IT Systems”) and network infrastructure. We use our IT Systems and network infrastructure to create, collect, use, disclose, store, dispose of, and otherwise process sensitive information, including company and customer data and personal information regarding customers, employees and their dependents, contractors, shareholders,

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and other individuals. IT Systems are critical to controlling and monitoring our power plants’ operations, maintaining generation and network performance, monitoring smart grids, managing billing processes and customer service platforms, achieving operating efficiencies, and meeting our service targets and standards in our generation and distribution businesses. The operation of our generation system is dependent not only on the physical interconnection of our facilities with the electricity network infrastructure but also on communications among the various parties connected to the network. The reliance on IT Systems to manage information and communication among those parties has increased significantly since the implementation of smart meters and intelligent grids in Brazil and Colombia.

Our generation and distribution facilities, IT Systems, and other infrastructure and the information processed in our IT Systems could be affected by cybersecurity incidents, including those caused by human error. Cybersecurity incidents have evolved dramatically in recent years, and the number of incidents and their degree of impact have grown exponentially, making it increasingly difficult to identify their source in a timely manner. Our industry has begun to see an increase in volume and sophistication of cybersecurity incidents from international activist organizations, nation-states, and individuals, and are among the emerging risks identified in our planning process. Cybersecurity incidents could harm our business by limiting our generation and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations, or exposing us to various events that could increase our liability exposure. Our generation and distribution business systems are part of an interconnected system. Given the role of electricity as a vital resource in modern society, a widespread or prolonged disruption caused by the impact of a cybersecurity incident in the electric transmission grid, network infrastructure, fuel sources, or our third-party service providers’ operations could have broad socio-economic ramifications across households, businesses, and vital institutions, which could unfavorably affect our business.

Our businesses require the collection and storage of personally identifiable information of our customers, employees, and shareholders, who expect that we will adequately protect the privacy of such information. Cybersecurity breaches may expose us to a risk of loss or misuse of confidential and proprietary information. Significant theft, loss, or fraudulent use of information, or other unauthorized disclosure of personal or sensitive data, may lead to high costs to notify and protect the impacted persons. It could cause us to become subject to significant litigation, losses, liability, fines, or penalties, any of which could materially and adversely affect our results of operations and reputation. We may also be required to incur significant costs associated with governmental actions in response to such intrusions or strengthen our information and electronic control systems.

The cybersecurity threat is dynamic, evolving, and increasing in sophistication, magnitude, and frequency. We may be unable to implement adequate preventive measures or accurately assess the likelihood of a cybersecurity incident. We are unable to quantify the potential impact of cybersecurity incidents on our business and reputation. These potential cybersecurity incidents and corresponding regulatory action could result in a material decrease in revenues and high additional costs, such as penalties, third-party claims, repairs, increased insurance expense, litigation, notification and remediation, security, and compliance costs.

Material Risks Related to Regulatory Matters

Governmental regulations may unfavorably affect our businesses, cause delays, impede the development of new projects, or increase the costs of operations and capital expenditures.

Our electricity businesses are subject to extensive regulation, inspections, and audits. The tariffs we charge to our customers are a result of a tariff-setting process defined by regulators, which may negatively affect our profitability. Our business is also exposed to the decision of governmental authorities regarding material rationing policies during droughts or prolonged failures of power facilities, or regulatory changes that may unfavorably affect our future operations and profitability.

Electricity regulations issued by governmental authorities in the countries where we operate may affect our generation companies’ ability to collect revenues sufficient to offset their operating costs, which could adversely affect our business, results of operations, and financial condition. Governmental authorities may also delay the distribution tariff review process, or tariff adjustments determined by regulatory authorities may be insufficient to pass on our costs to customers.

Our operating subsidiaries are also subject to environmental regulations that, among other things, require us to perform environmental impact studies on future projects and obtain construction and operating permits from local and

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national regulators. Governmental authorities may withhold or delay the approval of these permits until the completion of environmental impact studies, sometimes unexpectedly. Environmental regulations for existing and future generation capacity have become stricter and require increased capital investments. Any delay in meeting the required emission standards may constitute a violation of the environmental regulations. Failure to certify the original implementation and ongoing emission standard requirements of monitoring systems may result in significant penalties and sanctions or legal claims for damages. We expect that more restrictive emission limits will be established in the future.

Proposed changes in the regulatory framework are often submitted to legislators and administrative authorities. Some of these changes, if implemented, could have a material adverse effect on our business, results of operations, and financial condition.

Our business and profitability could be unfavorably affected if water rights are denied, if water concessions are granted with a limited duration, or if the cost of water rights is increased.

Each country’s respective water authority grants us water rights for water supply from rivers, lakes, and reservoirs near our generation facilities based on specific criteria. The terms differ from country to country, ranging from 25 years to an indefinite period. In Argentina, hydroelectric generators with a generation capacity exceeding 500 kW must obtain a concession to use public water sources for a determined or indefinite term. In Brazil, hydroelectric plants with an installed capacity of more than 50 MW must obtain a water rights concession for up to 35 years. In Costa Rica, all hydroelectric plants require a concession from the governmental authority for up to 25 years. The concession can be revoked if the plant is not operating within five years, extendable once for up to one year. In Guatemala, concessions are required for all hydroelectric plants with an installed capacity greater than 5 MW and may be granted for up to 50 years. In Colombia, water rights and water concessions are awarded for different periods for each of our power plants, in some cases for up to 50 years. However, these concessions may be revoked for specific reasons, including a progressive water decrease or depletion, and water for human consumption has priority over any other use. In Panama, all hydroelectric generators must obtain a concession, which may be granted for up to 50 years, and renewed for an additional 50 years. In Peru, the concessions are granted for indefinite periods but could be revoked due to scarcity or a decline in service quality.

Governmental authorities may revoke water rights granted to us for various reasons, including but not limited to failure to initiate operations within a specified period, progressive water decrease or depletion, non-compliance with environmental standards, and a decline in service quality, among others.

Any revocation of or limitations on our current water rights, additional water rights, or the duration of our water concessions could have a material adverse effect on our hydroelectric development projects and profitability.

We are subject to potential business and financial risks resulting from climate change legislation and regulation to limit GHG emissions.

Climate change legislation and regulation restricting or regulating GHG emissions could increase our operating costs and have a material adverse effect on our business, results of operations, and financial condition. The adoption and implementation of any international treaty, legislation, or regulation imposing new or additional reporting obligations or limiting emissions of GHGs from our operations could require us to incur additional costs to comply with such requirements and possibly require the reduction or limitation of GHG emissions associated with our operations. These higher compliance standards, such as net zero emissions, may require higher levels of investment in new, more efficient technologies. Failure to monitor or delay the adoption of new technologies may jeopardize our ability to adapt to climate change and may involve additional costs to operate and maintain our equipment and facilities, install emission controls, or pay taxes and fees relating to GHG emissions, which could have a material adverse effect on our business, results of operations, and financial condition.

Material Risks Related to Latin America and Other Global Risks

Certain Latin American countries have been historically characterized by frequent and occasionally drastic economic interventionist measures by governmental authorities, including expropriations that may adversely affect our business and financial results.

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Governmental authorities have altered monetary, credit, tariff, tax, and other policies to influence Latin American countries, including the countries in which we operate. Even though we do not have electricity operations in Chile, our company is established under the laws of the Republic of Chile. It is also subject to changes in Chilean tax, labor, and monetary laws, among others. Other governmental actions in the countries in which we operate have also implemented wage, price, and tariff rate controls and other interventionist measures, such as expropriation or nationalization.

If we do not meet minimum service and technical standards in the distribution business, we may lose our concessions. In some concession areas, such as those in Buenos Aires, Goiás, and Rio de Janeiro, it may be challenging to satisfy specific minimum standards that, if not met, empower regulators to revoke our concessions and reassign them to our competitors. If this situation occurs, it could lead to an event of default or a material adverse event under some of our subsidiaries’ debt obligations, which could trigger an acceleration of payment, cross-default, bankruptcy, or insolvency proceedings.

Although proposed tax reforms and amendments to the tax laws in Colombia did not materialize due to widespread protests throughout the country, on January 1, 2022, the corporate income tax rate in Colombia increased from 30% to 35%. In 2021, Argentina eliminated its fixed corporate tax regime and installed a progressive system with a maximum corporate tax rate of 35%. The Brazilian Congress is currently legislating a tax reform bill that could decrease corporate income tax rates, create a new withholding tax on cross-border dividends, and reduce or eliminate other tax benefits.

Changes in governmental and monetary policies regarding tariffs, exchange controls, regulations, and taxation could reduce our profitability. Inflation, devaluation, social instability, and other political, economic, diplomatic developments or crises, including governments’ response in the region to these circumstances, could also reduce our profitability.

Economic fluctuations, political instability, and corruption scandals in Latin America and other regions in the world may affect our results of operations, financial condition, liquidity, and the value of our securities.

All our operations are in Latin America. Accordingly, our consolidated revenues may be affected by regional economic performance in Latin America and around the world. If local, regional, or worldwide economic trends adversely affect the economy of any of the countries in which we operate, it is likely that consumer demand for electricity will decrease and that some of our customers may have difficulties paying their electric bills, possibly increasing our uncollectible accounts, which could adversely affect our results of operations and financial condition.

The challenges arising from changes in economic conditions, regulatory policies, laws governing foreign trade, manufacturing, development and investments, and various crises around the world, either individually or in the aggregate, could severely affect the economies in the countries in which we operate and our business, results of operations, and financial condition. For example, since 2018, the U.S. and China have been involved in a trade war involving protectionist measures that increase volatility in financial markets worldwide due to the uncertainty of political decisions. Also, instability in the Middle East or any other major oil-producing region could result in higher fuel prices worldwide, which would increase the operating costs for our thermal generation power plants and unfavorably affect our results of operations and financial condition. An international financial crisis and its disruptive effects on the financial industry could negatively affect our ability to obtain new bank financings under the same historical terms and conditions that we have benefited from to date.

We operate in more volatile countries that at times have experienced political instability due to, among other things, corruption scandals involving several high-ranking government officials. Political events or financial and other crises could also diminish our ability to access local and international capital markets as sources of liquidity or increase interest rates available to us. Reduced liquidity could negatively affect our capital expenditures, long-term investments and acquisitions, growth prospects, and dividend payout policy.

Although we do not have operations in Chile, our management and headquarters are in Santiago, Chile, and our common stock is traded on the Chilean Stock Exchanges. Widespread protests and social unrest erupted throughout Chile in October 2019. As a result, the Chilean government has introduced several social reforms and in a November 2020 referendum, Chilean citizens strongly supported convening a constitutional convention to draft a new Chilean constitution. Any new constitution could alter the Chilean political situation, affect the Chilean economy, its business outlook, change existing rights, including rights to exploit natural resources, and water and property rights, any of which could adversely affect our business, results of operations, and financial condition. If a new Chilean constitution is not approved, the existing constitution, which has been in place since 1980, would remain in effect. There can be no

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assurance that the constitutional convention will agree on a draft of a new constitution or that the Chilean citizens will approve any draft constitution approved by the constitutional convention. We cannot give any assurance that these reforms and proposals or the constitutional reform process will resolve the social and economic concerns or that mass protests or civil unrest will not resume. The long-term effects of this social unrest are hard to predict but could include slower economic growth, which could adversely affect our business, results of operations, and financial condition. Demonstrations and civil unrest in Chile and the countries in which we operate may continue or worsen, which could negatively impact these countries’ economies and adversely affect our business, results of operations, financial condition, and value of our securities.

In addition, in December 2021, Chile elected Gabriel Boric as the new president. President Boric took office on March 11, 2022, and his agenda is mainly focused on the elimination of private pension funds, social security programs, increases in the minimum wage and pensions, and increases in corporate taxes. President Boric is also a strong supporter of the constitutional reforms being considered by the constitutional convention drafting a new Chilean constitution. While it is still very early in President Boric’s term, and there is uncertainty regarding how his reforms may affect the political and business climate in Chile in the future, these reforms could lead to higher-than-expected inflation levels, unemployment, and higher corporate taxes in Chile, any of which could negatively affect our business, results of operations, and financial condition. In June 2021, Pedro Castillo, a far-left candidate, was elected president of Peru. President Castillo’s government has advocated for increasing taxes and taking measures to prohibit imports and nationalize strategic sectors of the economy, such as the energy sector. Congressional elections in Argentina in November 2021 also contributed to the political uncertainty in that country as far-left and far-right candidates both gained seats, resulting in President Alberto Fernández losing his majority support in Argentine Congress.

Future adverse developments in these countries, including political events, financial or other crises, changes to policies regarding foreign exchange controls, regulations, and taxation, may impair our ability to execute our business plan and could adversely affect our growth, results of operations, and financial condition. Inflation, devaluation, social instability, and other political, economic, or diplomatic developments could also reduce our profitability. Economic and market conditions in financial and capital markets of the countries in which we operate may be affected by international events, which could unfavorably affect the value of our securities.

A further deterioration of Argentina’s economic situation or further devaluation of the Argentine peso could have an adverse effect on our operations and profitability.

Since July 2018, Argentina has been considered a hyperinflationary economy according to IFRS accounting standards. A general price index was used to present the amounts related to our Argentine subsidiaries in our consolidated financial statements retrospectively to reflect the changes in the purchasing power of the Argentine peso under the provisions outlined in IAS 29, “Financial Reporting in Hyper-Inflationary Economies.” Non-monetary assets and liabilities were restated as of February 2003, the latest date in which an inflation adjustment for accounting purposes was applied in our Argentine subsidiaries. Our consolidated financial statements have not been restated to reflect the gain from the indexation of our Argentine subsidiaries’ non-monetary assets and liabilities before January 1, 2018. Such monetary gain up to that date was recognized as an adjustment to our retained earnings as of January 1, 2018. Please see Note 2.9 of the Notes to our consolidated financial statements.

The Argentine peso experienced one of the steepest devaluations against the U.S. dollar in 2019, 2020, and 2021, amounting to an annual depreciation of 37.1%, 28.8%, and 18.1%, respectively. Further deterioration of Argentina’s economy, a continued devaluation of the Argentine peso against the U.S. dollar driven by hyperinflation, or the initial freezing and subsequent lowering of electricity distribution tariffs could adversely affect our results of operations and financial condition.

We may be subject to the effects of the armed conflict between Russia and Ukraine.

The effects of the armed conflict between Russia and Ukraine, which began in February 2022, on our company are unknown. Although we do not have direct business transactions with suppliers, clients, or lenders from Russia or Ukraine, our business, results of operations, and financial condition may be impacted by (i) limited access to financial markets; (ii) possible interruptions in the global supply chain; and (iii) an increase in inflationary pressures in the countries in which we operate, which could increase the rates charged to our customers.

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We are subject to the adverse effects of worldwide pandemics.

In response to the Covid-19 pandemic that began in December 2019 and was declared by the World Health Organization as a public health emergency of international concern, governments in all the countries where we operate declared states of emergency, instituted nighttime curfews, mandatory quarantines in affected areas, control of entrance, exit, and traffic within specified zones, the prohibition of mass gatherings, and the closing of public schools, among other measures. The private sector in the countries in which we operate has voluntarily taken further actions, such as adopting telecommuting wherever possible and closing commercial offices.

Governments of the countries in which we operate took the following measures, among others, to preserve access to essential services and preserve business continuity:

● In March 2020, Argentina enacted a rule prohibiting companies providing essential services, such as electricity distribution companies, from cutting service due to customer non-payment for 180 days for low-income residential customers, small businesses, and companies providing other essential services, such as health facilities. In May 2020, the Argentine regulator issued a resolution allowing users who have reduced their demand by 50% or more to suspend their payments or to make payments in 30 monthly installments. In March 2021, the Argentine regulator enacted a resolution prohibiting distribution companies from suspending services to customers for unpaid debts accrued through February 28, 2021.

● Brazil enacted a prohibition on the suspension of electricity supply due to customer non-payment for all residential customers and companies and facilities providing essential services. This measure was in effect from March to July 2020. In March 2020, the Brazilian National Electric Energy Agency (“ANEEL” in its Portuguese acronym) issued a regulation to grant loans to the distribution companies, commonly known as the “CONTA-COVID,” aiming to ease financial distress and avoid tariff adjustments. For further information with respect to the CONTA-COVID, please refer to Note 8 of the Notes to our consolidated financial statements.

● Colombia allowed low-income level 1 and 2 residential customers (representing approximately 44% of the customer base) to defer payment of monthly electricity bills for 36 months and level 3 and 4 residential customers (representing approximately 40% of the customer base) to defer payment of monthly electricity bills for 24 months, in each case without penalty or risk of a suspension in service.

● Peru allowed 4.8 million vulnerable residential customers to pay bills issued between March and June 30, 2020, in up to 24 monthly installments, without interest, charges, or fees due to late payment. The Peruvian government also established a subsidy payable to distribution companies to cover customers’ unpaid bills for monthly energy consumption of up to 125 kW from March to December 2020.

All of these measures, as well as other government restrictions, temporarily disrupted our business and operations, decreased the demand for electricity, destabilized financial markets, negatively affected the global supply chain, and compromised our ability to generate income. As a result, each country where we operate experienced negative growth in GDP in 2020, and these disruptions significantly impacted our 2020 performance. For example, during the year ended December 31, 2020, sales from energy distribution decreased 4.5%, net production fell 3.1%, and sales from energy generation decreased 7.7%. Our collection rates fell 4.7% in Peru, 2.0% in Colombia, 1.9% in Argentina, and 1.5% in Brazil as compared to the same period of 2019. We estimate that the impact on our net income caused by the Covid-19 pandemic stemmed from lower energy demand and increased uncollectible debts. However, governments loosened restrictions in 2021, and each country where we operate experienced a rebound in economic activity that resulted in positive growth in GDP in 2021. As restrictions loosened, the demand for electricity increased, which positively impacted our net income in 2021. For further information with respect to the pandemic effect on our business and financial results, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results.”

The recent emergence of new Covid-19 variants and increases in infection rates may result in a reimposition of governmental and private sector measures in response. If there is a resurgence of the Covid-19 pandemic or similar outbreaks in the future, our business, results of operations, and financial condition may be materially adversely affected.

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Foreign exchange risks may unfavorably affect our results and the U.S. dollar value of dividends payable to ADS holders.

Even though our functional currency is the U.S. dollar, most of our subsidiaries generate revenues in other currencies, such as Argentine pesos, Brazilian reais, Colombian pesos, Costa Rican colones, Guatemalan quetzales and, Peruvian soles. We generally have been and will continue to be materially exposed to currency fluctuations in our local currencies against the U.S. dollar because of time lags and other limitations to pegging our tariff rates to the U.S. dollar. This exposure can substantially decrease the value of the cash generated by our subsidiaries and the value of our dividends when translated into U.S. dollars if our local currencies experience a devaluation against the U.S. dollar. For example, the Argentine peso and Colombian peso devalued by approximately 18% and 14% against the U.S. dollar in 2021, respectively. Future volatility in the currency exchange rate in which we receive revenues or incur expenditures may adversely affect our business, results of operations, and financial condition, especially when measured in U.S. dollars, the currency that affects our ADS holders.

Material Risks Related to Ownership of Our Shares and ADSs

Our controlling shareholder may influence us and may have a strategic view for our development that differs from that of our minority shareholders.

Enel, our controlling shareholder, owns a beneficial interest of 82.3% of our share capital as of the date of this Report. Under Law 18,046 (the “Chilean Corporations Law”), Enel has the power to determine the outcome of all material matters that require a simple majority of shareholders’ votes, such as the election of most of the seats on our board, and, subject to contractual and legal restrictions, the adoption of our dividend policy, as well as all material matters that require the approval of two-thirds of the shareholders’ votes. Enel also exercises significant influence over our business strategy and operations. However, in some cases, its interests may differ from those of our minority shareholders. Certain conflicts of interest affecting Enel in these matters may be resolved in a manner that is different from the interests of our company or our minority shareholders.

Following the 2021 tender offer by Enel S.p.A., our public float has been reduced and has negatively affected the liquidity and market for our shares and ADSs.

Following the 2021 tender offer by Enel S.p.A., the number of shares of our common stock and ADSs remaining in public circulation decreased and resulted in less liquidity and a less active public trading market for our shares and ADSs. The low liquidity of the markets for our shares and ADSs may impair shareholders’ ability to sell their shares or holders of ADSs to sell their ADSs or the underlying shares of our common stock in the public markets in the amount and at the desired price and time, which could unfavorably affect the price of our common stock and ADSs.

The relative illiquidity and volatility of the Chilean securities markets could unfavorably affect the price of our common stock and ADSs.

Even though we do not have assets in Chile, our shares are traded on the Chilean Stock Exchanges because we are organized under the laws of the Republic of Chile and have our headquarters in Chile. Chilean securities markets are substantially smaller and have less liquidity than major securities markets in the United States and other developed countries. The low liquidity of the Chilean markets may impair shareholders’ ability to sell shares, or holders of ADSs to sell shares of our common stock withdrawn from the ADS program, on the Chilean Stock Exchanges in the amount and at the desired price and time.

Lawsuits against us brought outside of the Latin American countries in which we operate, or complaints against us based on foreign legal concepts may be unsuccessful.

All our operations are located outside of the United States. All our directors and officers reside outside of the United States, and substantially all their assets are located outside the United States. If investors were to bring a lawsuit against our directors and officers in the United States, it may be difficult for them to effect service of legal process within the United States upon these persons. It may also be difficult to enforce judgments obtained in the U.S. courts based on civil liability provisions of U.S. federal securities laws against them in U.S. or Chilean courts. There is also doubt about whether an action could be brought successfully in Chile for liability based solely on the civil liability provisions of U.S. federal securities laws.

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We identified a material weakness in our internal controls over financial reporting for fiscal year 2020, which has been remediated; however, if we experience additional material weaknesses or otherwise fail to maintain an effective system of internal control over financial reporting, it could result in material misstatements of our consolidated financial statements or cause us to fail to meet our periodic reporting obligations.

In connection with the preparation of our financial statements as of and for the year ended December 31, 2020, we identified a material weakness in our internal control over financial reporting related to our general information technology controls, including the design and implementation of access-and-change management controls. As a result, as reported in our annual report on Form 20-F for the year ended December 31, 2020, our management concluded that as of December 31, 2020, our internal control over financial reporting was not effective, although our consolidated financial statements as of and for the year ended December 31, 2020, present fairly, in all material respects, our consolidated financial position, results of operations, and cash flows as of the dates and for the periods presented.

A material weakness will not be considered remediated until any applicable new or enhanced controls operate for a sufficient period, and management has concluded through testing that these controls are operating effectively. We believe we have taken the necessary steps to remediate the identified material weakness and enhance our internal controls. Accordingly, our management has concluded that, as of December 31, 2021, our internal control over financial reporting was effective. See “Item 15. Controls and Procedures—Disclosure Control and Procedures.”

If we experience additional material weaknesses or otherwise fail to maintain an effective system of internal control over financial reporting, it could (i) result in a material misstatement in our financial reporting or financial statements that would not be prevented or detected, (ii) cause us to fail to meet our reporting obligations under applicable securities laws, or (iii) cause investors to lose confidence in our financial reporting or financial statements, the occurrence of any of which could materially and adversely affect our business, financial condition, cash flows, results of operations, and the prices of our securities.

General Risk Factors

Our electricity business is subject to risks arising from extreme weather events related to climate change, natural disasters, catastrophic accidents, and acts of vandalism or terrorism, which could unfavorably affect our operations, earnings, and cash flow.

Our primary facilities include power plants and transmission and distribution assets that are exposed to damage from the increased severity and frequency of extreme weather events, such as cyclones, hurricanes, or floods, due to climate change, catastrophic natural disasters, such as earthquakes and fires, and human causes, such as vandalism, protests, riots, and terrorism. A catastrophic event could cause prolonged unavailability of our assets, disruptions in our business, significant decreases in revenues due to lower demand, or significant additional costs not covered by our business interruption insurance and could require us to incur unplanned capital expenditures. There may be lags between a significant accident or catastrophic event and the final reimbursement from our insurance policies, which typically carry a deductible and are subject to per event policy maximum amounts.

Any natural or human catastrophic disruption to our electricity assets in the countries in which we operate could significantly affect our business, results of operations, and financial condition.

We are subject to financing risks, such as those associated with funding our new projects and capital expenditures or refinancing existing obligations.

As of December 31, 2021, our consolidated debt totaled US$ 7.6 billion, mainly consisting of accounts payable to related parties and financial liabilities. Please see Notes 10 and 19 of the Notes to our consolidated financial statements for further information on related party transactions and financial liabilities, respectively.

A significant portion of our financial indebtedness is subject to (i) financial covenants, (ii) affirmative and negative covenants, (iii) events of default, (iv) mandatory prepayments for contractual breaches, (v) change of control clauses for material mergers and divestments, (vi) bankruptcy and insolvency proceeding covenants, and (vii) cross-default provisions, which have varying definitions, criteria, materiality thresholds, and applicability concerning subsidiaries that

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could result in a cross-default event. Our debt may also become immediately due and payable in cases involving bankruptcy or insolvency proceedings of a significant or material subsidiary.

The market conditions prevailing at any time may prevent us from accessing capital markets or satisfying our financial needs to fund new projects. We may also be unable to raise the necessary funds required to finish our projects under development or construction. Likewise, we may be unable to refinance our debt or obtain such refinancing in terms acceptable to us. In the absence of such refinancing, we could be forced to liquidate assets at unfavorable prices to make payments due on our debt. Furthermore, we may be unable to sell our assets at opportune moments or sufficiently high prices to obtain proceeds that would enable us to make such payments.

Our inability to finance new projects or capital expenditures, refinance our existing debt, or comply with our covenants could negatively affect our business, results of operations, and financial condition.

Regulatory authorities may impose fines, penalties, or sanctions on our subsidiaries due to operational failures or any breach of regulations.

Our electricity businesses may be subject to regulatory fines, penalties, or sanctions for any breach of current regulations, including failures to supply energy, in the countries in which we operate. Local regulatory entities supervise our generation subsidiaries. We may be subject to fines or penalties when the regulator determines that the company is responsible for the operational failures that affect the system’s regular energy supply, including coordination issues. Our subsidiaries may be required to pay fines or compensate customers if they cannot deliver electricity, even if such failures are not within their control, or when they do not meet environmental or other standards. Fines may also be associated with a breach of regulations. Please see Note 36 of the Notes to our consolidated financial statements for further information on sanctions.

We are involved in litigation proceedings.

We are involved in various litigation proceedings, including lawsuits and arbitrations, that could result in unfavorable decisions or financial penalties against us. Given the difficulty of predicting the outcome of legal matters, we have no certainty about the most likely outcome of these proceedings or what the eventual fines or penalties related to each litigation may be. Although we intend to defend our positions vigorously, our defense of these litigation proceedings may not be successful and responding to such lawsuits and arbitrations diverts resources and our management’s attention from day-to-day operations.

Our financial condition or results of operations could be unfavorably affected if we are unsuccessful in defending these litigations or other lawsuits and legal proceedings against us. Please see Note 34.3 of the Notes to our consolidated financial statements for further information on litigation and arbitration proceedings.

Item 4. Information on the Company

A.  History and Development of the Company.

History

We are a publicly held limited liability stock corporation headquartered in Chile and organized on June 19, 1981, under the laws of the Republic of Chile. Since January 1983, we have been registered in Santiago with the Chilean Financial Market Commission (“CMF” in its Spanish acronym) under Registration No. 0175. We have also been registered with the SEC under the commission file number 001-12440 since October 19, 1993. Our full legal name is Enel Américas S.A., and we are also known commercially as “Enel Américas.” Our shares are listed and traded on the Chilean Stock Exchanges under the trading symbol “ENELAM.” Our ADSs are listed and traded on the NYSE under the trading symbol “ENIA.”

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Our contact information for the Investor Relations Department in Chile is:

Contact Person:	Rafael de la Haza
Street Address:	Av. Santa Rosa 76, Piso 15 Comuna de Santiago Santiago, Chile
Email:	ir.enelamericas.com
Telephone:	(56-2) 2353-4400
Web site:	www.enelamericas.com

The information contained on or linked from our website is not included as part of, or incorporated by reference into, this Report. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, such as our company, at www.sec.gov.

We are one of the largest publicly listed companies in the electricity sector in South America and have been known as Enel Américas since 2016. We trace our origins to Compañía Chilena de Electricidad Ltda. (“CCE”), which was formed in 1921. Following the nationalization of the CCE in the 1970s, the Chilean electric utility sector was reorganized in the 1980s under the Chilean Electricity Law, known as the Decree with Force of Law No. 1 of 1982 (“DFL 1”). In August 1988, our predecessor company changed its name to Enersis S.A. (“Enersis”). In the 1990s, Enersis diversified into electricity generation, transmission, and distribution sectors in five South American countries, including Chile.

Following our 2013 capital increase, we acquired additional interests in certain companies, directly or indirectly through our subsidiaries, and undertook other reorganizations in Brazil and Peru.

Following a corporate reorganization completed in 2016, Enersis changed its name to Enel Americas S.A. and ceased to hold electricity assets in Chile. Since 2016, we have held electricity generation, transmission, and distribution assets in Argentina, Brazil, Colombia, and Peru.

In 2019, we completed a US$ 3 billion capital increase, the largest cash only capital increase in Chilean corporate history, the proceeds of which were used to refinance the debt incurred in our 2018 acquisition of Enel Distribution Sao Paolo.

On April 1, 2021, we completed the acquisition of EGP Américas S.p.A., a wholly owned subsidiary of Enel S.p.A., our controlling shareholder, through a merger of EGP Américas S.p.A. with and into Enel Américas. Prior to the merger, EGP Américas S.p.A., a newly formed company, held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A. The merger allowed the acceleration of our positioning within the energy transition scenario and enables us to become the leading power utility in Central and South America in the generation, transmission, and distribution of energy. As a result of the merger, we have now strengthened our renewable energy generation business and diversified geographically through exposure to Costa Rica, Guatemala, and Panama, in addition to acquiring new assets in South American countries where we were already present. As a result of the merger, Enel S.p.A.’s ownership interest in us increased to 75.2% as of April 1, 2021.

On March 15, 2021, Enel S.p.A. launched dual Chilean and U.S. partial public tender offers to acquire shares and ADS of Enel Américas, representing 10% of our then-current share capital, for a cash purchase price of Ch$ 140 per share and the U.S. dollar equivalent of Ch$ 7,000 per ADS. The tender offers were completed on April 16, 2021, and as a result of the merger and the tender offers, Enel S.p.A. currently owns 82.3% of our share capital as of the date of this Report.

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Capital Investments, Capital Expenditures, and Divestitures

We coordinate our overall financial strategy, including the terms and conditions of loans and intercompany advances entered into by our subsidiaries, to optimize debt and liquidity management. Generally, our operating subsidiaries independently plan capital expenditures financed by internally generated funds or direct financings. One of our goals is to focus on investments that will provide long-term benefits, such as energy loss reduction projects. Although we have considered how these investments will be financed as part of our budget process, we have not committed to any particular financing structure, and investments will depend on the prevailing market conditions when the cash flows are needed.

Our investment plan is flexible enough to adapt to changing circumstances by giving different priorities to each project following expected profitability and strategic fit, including sustainability considerations. We are currently focused on making investments (i) on behalf of the distribution business related to network reliability, capacity improvement, and new technology developments such as smart meters, (ii) for maintenance of our distribution network and generation plants, (iii) in studies required to develop other potential generation and distribution projects, and (iv) in the development of new businesses. For further detail regarding these projects, please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Development.”

The table below sets forth the expected capital expenditures for the 2022-2024 period and the capital expenditures incurred in 2021, 2020, and 2019:

	Estimated 2022-2024	2021	2020	2019
	(in millions of US$)
Capital expenditures(1)	8,900	3,012	1,553	1,659

(1) Capital expenditures figures listed in this table represent cash flow used to purchase property, plant, and equipment, and intangible assets for each year.

While our planned investments go beyond the three years highlighted in this table, we report three years to align with Enel’s three-year industrial plan disclosed in November 2021. Please refer to “Item 4. Information on the Company — D. Property, Plant and Equipment — Project Investments” for further information.

Capital Expenditures in 2021, 2020, and 2019

During the last three years, our capital expenditures were principally related to (i) maintenance of our existing installed capacity in Argentina (wastewater treatment system - Costanera power plant); Colombia (Termozipa thermal power plant); Peru (Ventanilla power plant), to increase the quality and operation standards of our facilities, and (ii) maintenance of our existing networks and the reduction of energy losses in Brazil, Colombia, Argentina, and Peru.

During 2021, our investments in our generation business focused on our recently acquired renewable energy projects, primarily in (i) wind projects in Brazil (Cumaru, Fontes dos Ventos, Lagoa dos Ventos, Morro do Chapeu Sul), Colombia (Windpeshi), and Peru (Wayra II); (ii) solar projects in Brazil (Sao Goncalo III), Panama (La Esperanza, El Jaguito, and Madre Vieja), Colombia (La Loma and Guayepo), and Peru (Clemesi). We also invested in hydroelectric repowering projects in Brazil (Paranapanema) and Peru (Callahuanca).

During 2021, our investments in our distribution business focused primarily on (i) expanding our distribution service due to an increase in demand; (ii) improving and reinforcing the capacity of high-, medium-, and low-voltage substations and networks; and (iii) implementing projects to reduce energy losses and improve the quality of distribution networks.

We reserve a portion of our capital expenditures for maintenance and the assurance of our facilities’ quality and operational standards. Projects in progress will be financed with resources provided by external financing and internally generated funds. Please refer to “Item 4. Information on the Company — D. Property, Plant and Equipment — Project Investments” for further information.

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B.  Business Overview.

We are a publicly held limited liability stock corporation engaged in the generation, transmission, and distribution of electricity in Argentina, Brazil, Colombia, Costa Rica, Guatemala, Panama, and Peru through our subsidiaries and affiliates. As of December 31, 2021, we had 15,926 MW of net installed generation capacity and approximately 26.2 million distribution customers. Our net installed generation capacity is comprised of 248 generation units, of which 42.3% are hydroelectric, 31.4% are thermal, 14.4% are wind, and 11.9% are solar power plants. As of and for the year ended December 31, 2021, we had consolidated assets of US$ 34,959 million and operating revenues of US$ 16,192 million.

The table below presents our revenues by reportable segments and by operating segments within such reportable segments.

	Year ended December 31,
	2021	2020	2019	Change 2021 vs. 2020
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	228	231	436	(1.3)
Costanera	105	113	214	(7.1)
El Chocón	42	49	72	(14.3)
Dock Sud	79	66	147	19.7
Other	2	3	3	(33.3)
Generation and Transmission Business in Brazil	2,550	1,106	778	130.6
EGP Cachoeira Dourada	1,428	812	494	75.9
Fortaleza	327	187	310	74.9
Cien	55	53	70	3.8
EGP Volta Grande	81	62	107	30.6
Brazil NCRE Subsidiaries(1)(2)	540	—	—	n.a.
Enel Trading Brasil	827	—	—	n.a.
Other	(708)	(8)	(203)	(8,750.0)
Generation and Transmission Business in Colombia	1,266	1,159	1,247	9.2
Emgesa	1,262	1,159	1,247	8.9
EGP Colombia(1)	30	—	—	n.a.
Other	(26)	—	—	n.a.
Generation and Transmission Business in Peru	573	505	596	13.5
Enel Generation Peru	431	408	474	5.6
Enel Generation Piura	74	63	82	17.5
Chinango	47	41	45	14.6
EGP Peru(1)	33	—	—	n.a.
Other	(12)	(7)	(5)	(71.4)
Generation and Transmission Business in Central America(1)	233	—	—	n.a.
EGP Costa Rica	17	—	—	n.a.
EGP Guatemala	108	—	—	n.a.
EGP Panama	149	—	—	n.a.
Other	(41)	—	—	n.a.
Total Generation and Transmission Business reportable segment	4,850	3,001	3,057	61.6
Distribution Business in Argentina	794	801	1,347	(0.9)
Edesur	794	801	1,347	(0.9)
Distribution Business in Brazil	8,762	6,834	8,227	28.2
Enel Distribution Rio	1,581	1,253	1,526	26.2
Enel Distribution Ceara	1,512	1,166	1,398	29.7
Enel Distribution Goias	1,820	1,394	1,546	30.6
Enel Distribution Sao Paulo	3,849	3,021	3,757	27.4
Distribution Business in Colombia	1,707	1,547	1,665	10.3
Codensa	1,707	1,547	1,665	10.3
Distribution Business in Peru	895	887	950	0.9
Enel Distribution Peru	895	887	950	0.9
Total Distribution Business reportable segment	12,158	10,069	12,189	20.7
Less: Consolidation adjustments and non-core activities	(816)	(778)	(861)	(4.9)
Total Revenues	16,192	12,292	14,385	31.7

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

(2) In November 2021, EGP Brasil was merged into Enel Brasil.

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(3) During 2021, we reclassified from financial income to operating income the value to be recovered of certain financial assets related to the concession contracts of the electricity distribution subsidiaries in Brazil. As a consequence of such reclassification, we retrospectively reclassified in the consolidated statements of comprehensive income the amount of ThUS$ 99,071 from financial income to operating income for the year ended December 31, 2020. Please refer to Note 2.2.c of the Notes to our consolidated financial statements for further detail.

For further information related to our revenues and total income, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 27. Please see Note 34.5 of the Notes to our consolidated financial statements for further information related to the effects of Covid-19 on our business.

Electricity Generation Business

In 2021, our consolidated electricity sales were 71,255 GWh, and our electricity production was 48,739 GWh, a 20% increase and a 20% increase, respectively, compared to 2020. Our total installed capacity in 2021 was 15,926 MW, a 41% increase compared to 2020, due to the acquisition of EGP Américas S.p.A. as of April 1, 2021, by means of a merger.

For additional information on the merger, please see “Item 4. Information on the Company — A. History and Development of the Company.” For additional information on our historical capacity, see “Item 4. Information on the Company — D. Property, Plant and Equipment.”

The following tables summarize the operating data relating to our electricity generation:

	Year ended December 31,
	2021	2020	2019
Argentina
Number of generating units(1)	29	29	29
Installed capacity (MW)(2)	4,419	4,419	4,419
Electricity generation (GWh)	13,099	13,901	12,974
Energy sales (GWh)	13,101	13,903	12,976
Brazil(3)
Number of generating units(1)	127	17	17
Installed capacity (MW)(2)	4,978	1,354	1,354
Electricity generation (GWh)	10,987	4,823	5,292
Energy sales (GWh)	26,396	17,533	20,512
Colombia(3)
Number of generating units(1)	37	36	36
Installed capacity (MW)(2)	3,589	3,506	3,506
Electricity generation (GWh)	13,209	14,009	15,250
Energy sales (GWh)	17,686	17,539	18,376
Peru(3)
Number of generating units(1)	32	30	30
Installed capacity (MW)(2)	2,294	1,990	1,987
Electricity generation (GWh)	9,339	7,722	8,244
Energy sales (GWh)	11,434	10,258	11,199
Central America(3)
Number of generating units(1)	23	—	—
Installed capacity (MW)(2)	646	—	—
Electricity generation (GWh)	2,106	—	—
Energy sales (GWh)	2,637	—	—
Total
Number of generating units(1)	248	112	112
Installed capacity (MW)(2)	15,926	11,269	11,267
Electricity generation (GWh)	48,740	40,455	41,760
Energy sales (GWh)	71,255	59,232	63,063

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(1) For details on generation facilities, see “Item 4. Information on the Company — D. Property, Plant, and Equipment — Property, Plant, and Equipment of Generating Companies.”

(2) Total installed capacity is the maximum capacity (MW) under specific technical conditions and characteristics. In most cases, installed capacity is confirmed by satisfaction guarantee tests performed by equipment suppliers. Figures may differ from installed capacity declared to governmental authorities and customers in each country, according to criteria defined by such authorities and relevant contracts.

(3) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

It is common in the electricity industry to divide the business into hydroelectric, thermoelectric, and other generation types because each type of generation has significantly different variable costs. Thermoelectric generation requires fuel purchase, which generally leads to higher variable costs than hydroelectric generation from reservoirs or rivers, which typically has immaterial variable costs. Of our total consolidated generation in 2021, 50.7% was from hydroelectric sources, 32.6% was from thermal sources, 13.2% was from solar sources, and 3.5% was from wind sources.

The following table summarizes our consolidated generation by type of energy:

CONSOLIDATED GENERATION BY TYPE OF ENERGY (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric	24,704	50.7	25,143	62.1	25,604	61.3
Solar	1,687	3.5	—	—	—	—
Wind	6,453	13.2	—	—	—	—
Thermal	15,895	32.6	15,313	37.9	16,155	38.7
Total generation(1)	48,739	100.0	40,456	100.0	41,760	100.0

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

In the countries where we operate, the potential for contracting electricity is related to electricity demand. Customers identified as small volume regulated customers, including residential customers, are subject to government-regulated electricity tariffs and must purchase electricity directly from a distribution company. These distribution companies, which purchase large amounts of electricity for small volume residential customers, generally enter into contractual agreements with generators at a regulated tariff price. Those identified as large volume industrial customers also enter into contractual agreements with energy suppliers. However, such large volume industrial customers are not subject to the regulated tariff price. Instead, these customers are allowed to negotiate the energy price with generators based on the required service characteristics. Finally, the pool market, where energy is typically sold at the spot price, is not carried out through contracted pricing.

We break down our sales to customers by using the two following criteria:

● The first criterion corresponds to regulated and unregulated customers. Regulated customers are distribution companies that mainly serve residential customers. Unregulated customers may freely negotiate the electricity price with generators or may purchase electricity in the pool market at the spot price. The classification of regulated customers differs from one country to another.

● The second criterion corresponds to contracted and non-contracted sales. This method is useful because it provides us a uniform way to compare the customers for each country. Contracted sales are defined uniformly throughout.

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Specific energy consumption limits (measured in GWh) for regulated and unregulated customers are country specific. Moreover, regulatory frameworks often require that regulated distribution companies have contracts to support their commitments to small volume customers and determine which customers can purchase energy in electricity pool markets.

Energy purchases and transportation costs are the principal variable costs involved in the electricity generation business, in addition to the direct variable cost of generating hydroelectric or thermal electricity, such as fuel costs. Our thermal generation increases during relatively low rainfall periods, typically resulting in higher fuel costs. Under dry conditions, the electricity we have contractually agreed to provide may exceed the electricity we generate, requiring us to purchase electricity in the pool market at spot prices to satisfy our contractual commitments. The cost of these purchases at spot prices may, under certain circumstances, exceed the price at which we sell electricity under contracts and, therefore, may result in a loss. We attempt to minimize the effects of poor hydrological conditions on our operations in any given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated production in a dry year. To determine the estimated production in a dry year, we consider the available statistical information concerning rainfall, hydrological levels, and critical reservoirs’ capacity. In addition to limiting contracted sales, we may adopt other strategies, including installing temporary thermal capacity, negotiating lower consumption levels with unregulated customers, negotiating with other water users, and including pass-through cost clauses in contracts with customers. For further details about hydrological conditions and their effects on our business, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — a. Generation and Transmission Business.”

Seasonality

While our core business is subject to weather patterns, only extreme events such as prolonged droughts, rather than seasonal weather variations, may adversely affect our generation capacity and materially affect our operating results and financial condition.

The generation business in the countries where we operate is affected by seasonal changes throughout the year. The months with the most precipitation in Argentina are typically May through August, with snowmelts generally occurring between October and December. In Brazil, due to tropical weather, rainfall is mostly concentrated in summer from November through May, and it is the lightest during the winter. The months with the most precipitation in our operating area in Colombia and Central America are typically April, May, October, and November. The months with the most precipitation in Peru are generally November through March.

When there is more precipitation, hydroelectric generating facilities can accumulate additional water for generation. Our reservoirs’ increased levels allow us to generate more electricity with hydroelectric power plants during the months when marginal electricity costs are lower.

In general, hydrological conditions such as droughts and insufficient rainfall may adversely affect our generation capacity. For example, severe prolonged drought conditions or reduced rainfall levels in the countries in which we operate caused by the El Niño phenomenon minimizes the amount of water accumulated in reservoirs, thereby curtailing our hydroelectric generation capacity. Hydroelectric generation may be substituted with thermal generation (natural gas, liquefied natural gas, coal, or diesel) and energy purchases on the spot market to mitigate hydrological risk. Both could result in higher costs to meet our obligations under contracts with regulated and unregulated customers.

Operations in Argentina

We participate in electricity generation in Argentina through our subsidiaries Costanera, El Chocón, and Dock Sud. As of December 31, 2021, we had 29 power units with a total net installed capacity of 4,419 MW in Argentina, representing 10.3% of the Argentine National Interconnected System’s (“Argentine NIS”) total installed capacity in 2021, according to the Wholesale Electric Market Management Company (“CAMMESA” in its Spanish acronym).

Costanera owns 11 thermal units, with a total net installed capacity of 2,210 MW, El Chocón owns nine hydroelectric units and four diesel engines, with a total net installed capacity of 1,362 MW, and Dock Sud owns five thermal units with an aggregate net installed capacity of 847 MW. For information on the installed generation capacity for each of our subsidiaries, see “Item 4. Information on the Company — D. Property, Plant, and Equipment—Property, Plant, and Equipment of Generating Companies.”

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During 2021, the electricity demand throughout the Argentine NIS increased by 5.2%. The total electricity demand was 133,873 GWh in 2021 and 127,314 GWh in 2020. Our total generation in Argentina amounted to 13,099 GWh in 2021, representing 9.8% of the total demand.

Our hydroelectric generation in Argentina accounted for over 14.9% of our total generation in Argentina in 2021, reaching 1,955 GWh, a decrease of 32% compared to 2020 due to dry hydrological conditions and resulting low water levels in the reservoirs available for generation. Our thermal generation in Argentina accounted for 85.1% of our total generation in 2021, reaching 11,144 GWh, an increase of 0.9% compared to 2020 due to an increase in demand and to compensate for the lower hydroelectric generation because of dry hydrological conditions.

Our generation by type and subsidiary in Argentina is shown in the following table:

ELECTRICITY GENERATION IN ARGENTINA (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (El Chocón)	1,955	14.9	2,860	20.6	2,509	19.3
Thermal generation (Costanera and Dock Sud)(1)	11,144	85.1	11,041	79.4	10,464	80.7
Total generation	13,099	100.0	13,901	100.0	12,974	100.0

(1) Includes diesel engines at El Chocón

The following table sets forth our electricity generation and purchases in Argentina:

ELECTRICITY GENERATION AND PURCHASES IN ARGENTINA (GWh)

	Year ended December 31,
	2021		2020		2019
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	13,099	99.98	13,901	99.98	12,974	99.98
Electricity purchases	2	0.02	2	0.02	2	0.02
Total(1)	13,101	100.0	13,903	100.0	12,976	100.0

(1) Electricity generation and electricity purchases may differ from total electricity sales because of transmission losses, the power plants’ own consumption, and technical losses.

The distribution of our electricity sales in Argentina by subsidiary is shown in the following table:

ELECTRICITY SALES BY SUBSIDIARY IN ARGENTINA (GWh)

	Year ended December 31,
	2021	2020	2019
Costanera	5,695	6,518	6,210
El Chocón	2,028	2,924	2,528
Dock Sud	5,378	4,461	4,238
Total	13,101	13,903	12,976

For the year ended December 31, 2021: (1) Costanera did not have contracts with unregulated customers or distribution companies and sold all of its electricity to the pool market during the year; (2) El Chocón had seven contracts with unregulated customers and no contracts with distribution companies; and (3) Dock Sud did not have any contracts with regulated customers or distribution companies and sold all of its electricity to the pool market during the year.

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Operations in Brazil

We participate in electricity generation in Brazil through our subsidiaries Cachoeira Dourada, Fortaleza, EGP Volta Grande, and Enel Brasil. Enel Brasil operates the renewable generation units in Brazil as a result of the merger of EGP Brasil into Enel Brasil in November 2021. Before that merger, EGP Brasil was part of EGP Américas, which was merged into Enel Américas on April 1, 2021. For additional information on the merger, please see “Item 4. Information on the Company — A. History and Development of the Company.” As of December 31, 2021, we had 127 power units with a total net installed capacity of 4,978 MW in Brazil, representing 5.4% of the Brazilian system’s total installed capacity, according to ANEEL.

Cachoeira Dourada is a hydroelectric company consisting of three generation units, with a total net installed capacity of 655 MW, as of December 31, 2021.

Fortaleza owns a combined-cycle plant with ten generation units that use natural gas, with a total net installed capacity of 319 MW. Since January 2010, Fortaleza has received natural gas from the Pecem regasification terminal, an unrelated company. In 2019, our thermal generation increased after a decrease in 2018, caused by a legal dispute in connection with our gas supply contract with Petrobras, a gas supplier. On August 28, 2020, Petrobras and Fortaleza reached an agreement to settle the existing claims. However, a final judicial ruling is pending, as Petrobras and Fortaleza have requested that the judicial claims be settled without a judgment on the merits. From January to August 2020, there was an injunction in place that required Petrobras to provide the gas supply. Petrobras and Fortaleza have since reached an agreement to settle the claims, and the contract will be enforced and will remain in effect until 2023. In 2021, our thermal generation decreased because the ONS established lower dispatch energy levels for thermal generators to ensure adequate supply at reasonable costs.

EGP Volta Grande is a hydroelectric company consisting of four generation units, with a total net installed capacity of 380 MW, and Enel Brasil owns 11 hydroelectric, 29 solar, and 70 wind generation units, with a total net installed capacity of 235 MW, 1,233 MW, and 2,156 MW, respectively. For information on the installed generation capacity for each of our subsidiaries, see “Item 4. Information on the Company — D. Property, Plant, and Equipment—Property, Plant, and Equipment of Generating Companies.”

During 2021, the electricity demand throughout the Brazilian National Interconnected System (“Brazilian NIS”) increased by 5.5% to 498,851 GWh in 2021, from 473,062 GWh in 2020. Our total generation in Brazil amounted to 10,987 GWh in 2021, which represents 2.2% of the total demand in 2021.

Our hydroelectric generation in Brazil accounted for over 31.2% of our total generation in Brazil in 2021, reaching 3,430 GWh, a decrease of 26% compared to 2020, while our thermal generation accounted for 3.6% of our total generation in 2021, reaching 399 GWh, an increase of 88% compared to 2020, in each case mainly due to lower dispatch as a result of dry hydrological conditions. Finally, our solar and wind energy accounted for 10.8% and 54.4%, respectively, of our total generation in 2021, reaching 1,186 GWh and 5,972 GWh, respectively.

Our generation by type and subsidiary in Brazil is shown in the following table:

ELECTRICITY GENERATION IN BRAZIL (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (Cachoeira Dourada, Brazil NCRE Subsidiaries, EGP Volta Grande)	3,430	31.2	4,611	95.6	4,164	78.7
Solar generation (Brazil NCRE Subsidiaries)	1,186	10.8	—	—	—	—
Wind generation (Brazil NCRE Subsidiaries)	5,972	54.4	—	—	—	—
Thermal generation (Fortaleza)(1)	399	3.6	212	4.4	1,128	21.3
Total(2)(3)	10,987	100.0	4,823	100.0	5,292	100.0

(1) In 2020, our thermal generation decreased because the ONS defined lower dispatch energy levels by thermal generators to ensure adequate supply at reasonable costs.

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(2) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

(3) In November 2021, EGP Brasil was merged into Enel Brasil.

The following table sets forth our electricity generation and purchases in Brazil:

ELECTRICITY GENERATION AND PURCHASES IN BRAZIL (GWh)

	Year ended December 31,
	2021		2020		2019
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	10,987	41.6	4,823	27.5	5,292	25.8
Electricity purchases	15,410	58.4	12,710	72.5	15,220	74.2
Total(1)(2)(3)	26,396	100.0	17,533	100.0	20,512	100.0

(1) Electricity generation and electricity purchases may differ from total electricity sales because of transmission losses, the power plants’ own consumption, and technical losses.

(2) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

(3) In November 2021, EGP Brasil was merged into Enel Brasil.

The following table sets forth our electricity sales in Brazil by generation subsidiary:

ELECTRICITY SALES BY SUBSIDIARY IN BRAZIL (GWh)

	Year ended December 31,
	2021		2020		2019
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales Volume
Cachoeira Dourada	7,389	28.0	11,896	67.9	13,400	65.3
Fortaleza	5,014	19.0	3,636	20.7	4,742	23.1
EGP Volta Grande	1,512	5.7	2,000	11.4	2,370	11.6
Brazil NCRE Subsidiaries(1)(2)	12,481	47.3	—	—	—	—
Total electricity sales	26,396	100.0	17,533	100.0	20,512	100.0

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

(2) In November 2021, EGP Brasil was merged into Enel Brasil.

In 2021, Cachoeira Dourada sold 130 GWh to regulated customers, 2,900 GWh to unregulated customers, 1,380 GWh to the spot market, and 2,980 GWh to other generators. Its principal unregulated customers were (ordered alphabetically): Cencosud; Centurylink; Grupo Águas; and Volkswagen.

Fortaleza sold 1,967 GWh to unregulated customers, 357 GWh in the spot market, and 2,690 GWh to other generators. Its principal customer was Enel Distribution Ceara (our subsidiary).

EGP Volta Grande sold 852 GWh to regulated customers, 151 GWh in the spot market, and 509 GWh to other generators. Its principal customer was Cachoeira Dourada (our subsidiary).

Enel Brasil sold 2,440 GWh to regulated customers, 376 GWh to unregulated customers, 2,582 GWh in the spot market, and 7,083 to other generators. It has 17 contracts with unregulated customers and 462 contracts with distribution companies. Its principal customers were (ordered alphabetically): AD-Diper; Atmo; Boven; Comerc; Deal; Minerva; Prime; and Tradener.

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Operations in Colombia

We participate in electricity generation in Colombia through our subsidiaries Emgesa and EGP Colombia. As of December 31, 2021, we had 37 generation units, with a total net installed capacity of 3,589 MW, representing 20.2% of the Colombian National Interconnected System’s (“Colombian NIS”) total installed capacity in 2021, according to Expertos de Mercado S.A. E.S.P. (“XM”).

Emgesa owns 29 hydroelectric and seven thermal generation units, with a total net installed capacity of 3,097 MW and 406 MW, respectively. EGP Colombia owns one solar generation plant, with a net installed capacity of 86 MW. For information on the installed generation capacity for each of our subsidiaries, see “Item 4. Information on the Company — D. Property, Plant, and Equipment—Property, Plant, and Equipment of Generating Companies.”

During 2021, the electricity demand throughout the Colombian NIS increased by 5.0% to 73,907 GWh in 2021, from 70,420 GWh in 2020. Our total generation in Colombia amounted to 13,209 GWh in 2021, which represents 17.9% of the total demand in 2021.

Our hydroelectric generation in Colombia accounted for over 97.4% of our total generation in Colombia in 2021, reaching 12,868 GWh, a decrease of 3% compared to 2020, while our thermal generation accounted for 1.8% of our total generation in Colombia in 2021, a decrease of 65% compared to 2020, in each case mainly due to lower spot prices and higher hydrology aligned with our commercial strategy. Our solar energy generation accounted for 0.7% of our total generation in Colombia in 2021, reaching 97 GWh.

Our generation by type in Colombia is shown in the following table:

ELECTRICITY GENERATION IN COLOMBIA (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric generation(1)	12,868	97.4	13,314	95.0	14,620	95.9
Solar generation(2)	97	0.7	—	—	—	—
Thermal generation	244	1.9	696	5.0	630	4.1
Total generation	13,209	100.0	14,009	100.0	15,250	100.0

(1) The Rionegro power plant was sold in 2020. Prior period figures include 44 MWh for 2020 and 20.4 GWh for 2019.

(2) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

The following table sets forth our electricity generation and purchases in Colombia:

ELECTRICITY GENERATION AND PURCHASES IN COLOMBIA (GWh)

	Year ended December 31,
	2021		2020		2019
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	13,209	75.1	14,009	80.6	15,250	83.0
Electricity purchases	4,378	24.9	3,370	19.4	3,126	17.0
Total(1)(2)	17,587	100.0	17,379	100.0	18,376	100.0

(1) Electricity generation and electricity purchases may differ from total electricity sales because transmission losses, the power plants’ own consumption and technical losses have already been deducted.

(2) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

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The following table sets forth our electricity sales in Colombia by generation subsidiary:

	Year ended December 31,
	2021		2020		2019
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales Volume
Emgesa	17,589	99.4	17,539	100.0	18,376	100.0
EGP Colombia(1)	97	0.5	—	—	—	—
Total electricity sales	17,686	100.0	17,539	100.0	18,376	100.0

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

In 2021, Emgesa sold 3,942 GWh of electricity to unregulated customers, 10,991 GWh to regulated customers, and sales in the spot market totaled 2,656 GWh. Emgesa had 497 contracts with unregulated customers and 21 contracts with distributions companies. Its principal customers were (ordered alphabetically): Air-e; Caribemar de la Costa S.A.S. E.S.P.; Celsia Tolima; Codensa (our subsidiary); EGP Colombia (our subsidiary); Empresas Municipales de Cali, Empresas Públicas de Medellín (EPSA).

EGP Colombia sold 97 GWh of electricity to regulated customers. It had two contracts with distribution companies and its principal customer was: Emgesa (our subsidiary)

Operations in Peru

We participate in electricity generation in Peru through our subsidiaries Enel Generation Peru, Enel Generation Piura, and EGP Peru. As of December 31, 2021, we had 32 power units in Peru, with a total net installed capacity of 2,294 MW, representing 17.2% of the Peruvian SEIN’s total installed capacity in 2021, according to the Committee of Economic Operation of the Peruvian System (“COES” in its Spanish acronym).

Enel Generation Peru owns 17 hydroelectric and seven thermal generation units, with a total net installed capacity of 593 MW and 857 MW, respectively. Chinango owns three hydroelectric units with a total net installed capacity of 199 MW. Enel Generation Piura owns three thermal generation units with a total net installed capacity of 333 MW. EGP Peru owns one solar and one wind generation unit, with an installed capacity of 179 MW and 132 MW, respectively. For information on the installed generation capacity for each of our subsidiaries, see “Item 4. Information on the Company — D. Property, Plant, and Equipment—Property, Plant, and Equipment of Generating Companies.”

During 2021, the electricity demand throughout the Peruvian SEIN increased by 9.8% to 53,985 GWh in 2021, from 49,179 GWh in 2020. Our total generation in Peru amounted to 9,338 GWh in 2021, which represents 17.3% of the total demand in 2021.

Our hydroelectric generation in Peru represented 47.3% of our total generation in Peru in 2021, reaching 4,417 GWh, an increase of 1% compared to 2020, while our thermal generation accounted for 44.0% of our total generation in Peru in 2021, reaching 4,108 GWh, an increase of 22% compared to 2020, in each case mainly due to lower demand in 2020 as a result of the Covid-19 pandemic.

Our generation by type and subsidiary in Peru is shown in the following table:

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ELECTRICITY GENERATION IN PERU (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (Enel Generation Peru)	4,417	47.3	4,358	56.4	4,311	52.3
Solar generation (EGP Peru)	333	3.6	—	—	—	—
Wind generation (EGP Peru)	481	5.1	—	—	—	—
Thermal generation (Enel Generation Peru and Enel Generation Piura)	4,108	44.0	3,364	43.6	3,933	47.7
Total generation(1)	9,339	100.0	7,722	100.0	8,244	100.0

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

The following table sets forth our electricity generation and purchases in Peru:

ELECTRICITY GENERATION AND PURCHASES IN PERU (GWh)⁽¹⁾

	Year ended December 31,
	2021		2020		2019
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	9,339	81.7	7,722	75.3	8,244	73.6
Electricity purchases	2,096	18.3	2,536	24.7	2,955	26.4
Total(2)	11,435	100.0	10,258	100.0	11,199	100.0

(1) The values include sales to distribution companies without contracts.

(2) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

The distribution of our electricity sales in Peru by subsidiary is shown in the following table:

ELECTRICITY SALES BY SUBSIDIARY IN PERU (GWh)

	Year ended December 31,
	2021		2020		2019
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales Volume
Enel Generation Peru	9,905	86.6	9,642	94.0	10,541	94.1
Enel Generation Piura	716	6.3	616	6.0	658	5.9
EGP Peru(1)	814	7.1	—	—	—	—
Total electricity sales	11,435	100.0	10,258	100.0	11,199	100.0

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

In 2021, Enel Generation Peru sold 3,408 GWh to regulated customers, 4,552 GWh to unregulated customers, and 1,945 GWh in the spot market. Enel Generation Peru had 82 contracts with unregulated customers and 72 with distribution companies. Its principal customers were (ordered alphabetically): Chinalco; Enel Distribution Peru (our subsidiary); and Las Bambas.

Enel Generation Peru has long-term gas supply, transportation, and distribution contracts for its Ventanilla and Santa Rosa facilities. It has also signed transport capacity transfer agreements with other generators, which allows it to trade transport capacity to operate as instructed by COES and optimize the use of the natural gas transport system.

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Enel Generation Piura sold 415 GWh to regulated customers, 61 GWh to unregulated customers, and 240 GWh in the spot market. Enel Generation Piura had three contracts with unregulated customers and 29 with distribution companies. Its principal customers were (ordered alphabetically): Enel Distribution Peru (our subsidiary) and Luz del Sur.

Enel Generation Piura also had five long-term sales and purchase agreements for “wet” gas (4) and “dry” gas (1), which is mixed with other hydrocarbons. Enel Generation Piura purchases “wet” gas and converts it into “dry” gas used for electric generation at its Malacas Power Plant. The conversion from “wet” gas to “dry” gas is performed by the Pariñas processing plant. The gas is also sold to the Talara refinery (owned by Petroperu, the Peruvian National Oil Company). On July 24, 2019, Gases del Norte del Perú S.A.C. (“GASNORP”) was designated by the government as the sole gas distribution concessionaire to supply gas to the Piura region. However, for administrative reasons and operational processes, they were unable to cover the refinery's demand. As a result, very short-term gas sales amendments were signed with Talara Refinery (until December 2021) on a temporary basis until GASNORP is able to supply the demand.

EGP Peru has sold 814 GWh in the spot market. It did not have contracts with unregulated customers or distribution companies.

Operations in Costa Rica, Guatemala, and Panama (“Central America”)

We participate in electricity generation in Central America through our subsidiaries EGP Costa Rica, EGP Guatemala, and EGP Panama. As of December 31, 2021, we had 23 power units with a total installed capacity of 646 MW, representing 5.6% of Central America’s total installed capacity in 2021.

EGP Costa Rica owns four hydroelectric units, with a total net installed capacity of 81 MW, EGP Guatemala owns nine hydroelectric units, with a total net installed capacity of 164 MW, and EGP Panama owns ten solar units, with a total net installed capacity of 401 MW, respectively. For information on the installed generation capacity for each of our subsidiaries, see “Item 4. Information on the Company — D. Property, Plant, and Equipment—Property, Plant, and Equipment of Generating Companies.”

During 2021, the electricity demand throughout Central America increased by 6.6% to 33.8 TWh in 2021, from 31.7 TWh in 2020. Our total generation in Central America amounted to 2,106 GWh in 2021, representing 6.2% of the total demand in Central America in 2021.

Our hydroelectric generation in Central America represented 96.6% of our total generation in Central America in 2021, reaching 2,035 GWh, while our solar generation accounted for 3.4% of our total generation in 2021, reaching 71 GWh.

Our generation by type and subsidiary in Central America is shown in the following table:

ELECTRICITY GENERATION IN CENTRAL AMERICA (GWh)

	Year ended December 31,
	2021		2020		2019
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (EGP Costa Rica, EGP Guatemala, EGP Panama)	2,035	96.6	—	—	—	—
Solar generation (EGP Panama)	71	3.4	—	—	—	—
Total generation(1)	2,106	100.0	—	—	—	—

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

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The following table sets forth our electricity generation and purchases in Central America:

ELECTRICITY GENERATION AND PURCHASES IN CENTRAL AMERICA (GWh)

	Year ended December 31,
	2021		2020		2019
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	2,106	79.9	—	—	—	—
Electricity purchases	531	20.1	—	—	—	—
Total(1)	2,637	100.0	—	—	—	—

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

The distribution of our electricity sales in Central America by subsidiary is shown in the following table:

ELECTRICITY SALES PER SUBSIDIARY IN CENTRAL AMERICA (GWh)

	Year ended December 31,
	2021		2020		2019
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales Volume
EGP Costa Rica	168	6.4	—	—	—	—
EGP Guatemala	950	36.0	—	—	—	—
EGP Panama	1,519	57.6	—	—	—	—
Total electricity sales(1)	2,637	100.0	—	—	—	—

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

EGP Costa Rica sold 168 GWh of electricity to the Costa Rican Electricity Institute (“ICE” in its Spanish acronym).

EGP Guatemala sold 416 GWh of electricity to unregulated customers, 176 GWh in the spot market, and 358 GWh to other generators. It had 18 contracts with unregulated customers and eight contracts with distribution companies. Its principal customers were (ordered alphabetically): BlueFields; Cargill; Coca-Cola; Comercializadora para el Desarrollo; Cova Energy; Distribuidora de Electricidad del Occidente; Distribuidora de Electricidad del Oriente; Econoenergía; EDECSA; Empresa Eléctrica de Guatemala; GRS; Grupo EDA; La Ceiba; Multiquímica; Plastimax; Solaris; and Tropilight.

EGP Panama sold 796 GWh of electricity to regulated customers and 723 GWh in the spot market. It had 73 contracts with unregulated customers and ten contracts with distribution companies. Its principal customers were (ordered alphabetically): EDECHI; EDEMET; ENSA; and Petroterminal de Panamá & Manzanillo Internacional.

Electricity Transmission Business

Our electricity transmission operations are conducted through Cien, a wholly owned subsidiary of Enel Brasil and us. Cien consolidates CTM and TESA, which operate the Argentine side of the interconnection line between Argentina and Brazil. The local authority recognizes Cien as a “regulatory asset” and as part of the Brazilian grid. Therefore, it is entitled to receive fixed payments called Permitted Annual Compensation (RAP).

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Cien enables the energy integration of Mercosur and the import and export of electricity between Argentina and Brazil. It is responsible for the operation of transmission lines covering a distance of approximately one thousand kilometers, with a total transmission capacity of 2,200 MW. Cien operates each transmission line under the Cien I and Cien II concessions granted by the Brazilian government. The Cien I concession’s term expired in June 2020 and the Cien II concession’s term expires in July 2022. However, with regard to the Cien I concession, the Brazilian Ministry of Mines and Energy (“MME”) issued an official act in June 2020 designating Cien to continue operating the facilities covered by the Cien I concession until a new operator is appointed through an upcoming bid process, which may occur by the end of 2022. In the meantime, Cien will receive an annual income calculated based on current criteria and methodology. We are negotiating with the Brazilian MME to extend Cien’s concessions for 10 years. Cien’s subsidiaries, CTM and TESA, have concessions granted by the Argentine government, which expire in 2087.

Electricity Distribution Business

Our electricity distribution business is conducted in Argentina through Edesur; in Brazil through Enel Distribution Rio, Enel Distribution Ceara, Enel Distribution Goias, and Enel Distribution Sao Paulo; in Colombia through Codensa; and in Peru through Enel Distribution Peru. For the year ended December 31, 2021, electricity sales increased by 4.0% compared to 2020, totaling 119,845 GWh. 

Edesur (Argentina)

Edesur operates in a concession area of 3,304 square kilometers in the south-central part of the Buenos Aires metropolitan area, serving approximately 2.5 million customers under a 95-year concession granted by the Argentine government, which expires in 2087. As of December 31, 2021, residential, commercial, industrial, and other customers, primarily public and municipal, represented 46%, 22%, 8%, and 24%, respectively, of Edesur’s total electricity sales of 16,735 GWh.

The following table sets forth Edesur’s primary operating data for each of the periods indicated:

	Year ended December 31,
	2021	2020	2019
Electricity sales (GWh)	16,735	15,888	16,798
Residential	7,666	7,282	5,842
Commercial	3,684	3,466	3,106
Industrial	1,271	1,179	4,331
Other customers(1)	4,114	3,962	3,520
Number of customers (thousands)	2,549	2,508	2,490
Residential	2,255	2,216	2,195
Commercial	272	271	274
Industrial	20	20	20
Other customers	2	1	1
Energy purchased (GWh)(2)	20,416	13,094	13,747
Total energy losses (%)(3)	18.0	18.9	15.5
SAIDI (hours)	13.3	14.0	20.2
SAIFI (times)	4.9	4.5	6.0
Collection rate (%)(4)	96.9	96.1	95.8

(1) The figures for other customers include tolls.

(2) Edesur purchased all of its energy from CAMMESA, the governmental agency that regulates and acts as an intermediary between generation and distribution.

(3) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines and technical losses.

(4) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

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In 2021, Edesur’s principal unregulated customers were (ordered alphabetically): A.F.I.P.; Arcos Dorados Argentina S.A; AYSA S.A.; Banco Nación Argentina; Banco Santander Río S.A.; Cerámica Canuelas S.A.; Cerámica Quilmes S.A.; Coca-Cola; FEMSA S.A.; Curtiembres Fonseca S.A.; DIA ARGENTINA S.A.; Hoteles Sheraton de Argentina; JUMBO Retail Argentina S.A.; Los Cipreses S.A.; Metrovias S.A.; Reginal LEE S.A.I.C.; Roca Argentina S.A.; Telecom Argentina S.A.; Telefónica Argentina S.A.; Telefónica Mov. Argentina S.A.; and Valenciana Argentina.

Enel Distribution Rio (Brazil)

Enel Distribution Rio operates in a concession area of 32,615 square kilometers, distributing electricity to municipalities located in the State of Rio de Janeiro and serving approximately 3.0 million customers under a 30-year concession granted by the Brazilian government, which expires in December 2026. The company is entitled to a concession renewal under Brazilian law and must file its intention to renew the concession 36 months prior to its expiration. As of December 31, 2021, residential, commercial, industrial, and other customers represented 44%, 13%, 1%, and 42%, respectively, of Enel Distribution Rio’s total sales of 11,489 GWh.

The following table sets forth Enel Distribution Rio’s primary operating data for each of the periods indicated:

	Year ended December 31,
	2021	2020	2019
Electricity sales (GWh)	11,489	11,228	11,568
Residential	5,065	4,825	4,839
Commercial	1,472	1,562	1,927
Industrial	149	180	227
Other customers(1)	4,803	4,662	4,574
Number of customers (thousands)	3,031	2,948	2,940
Residential	2,801	2,528	2,691
Commercial	136	132	155
Industrial	4	4	4
Other customers	90	284	90
Energy purchased (GWh)	14,444	14,414	14,920
Total energy losses (%)(2)	20.5	22.1	22.5
SAIDI (hours)	9.3	10.5	13.2
SAIFI (times)	4.6	6.1	8.0
Collection rate (%)(3)	94.5	94.2	97.4

(1) The data for other customers includes tolls.

(2) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines and technical losses.

(3) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

In 2021, Enel Distribution Rio’s primary unregulated customers were (ordered alphabetically): CRH Cantagalo; Michelin; Rio Polimeros; Tecab; and Votorantim.

Enel Distribution Ceara (Brazil)

Enel Distribution Ceara operates in a concession area of 148,895 square kilometers, distributing electricity to municipalities located in the state of Ceará and serving approximately 4.0 million customers under a 30-year concession granted by the Brazilian government, which expires in May 2028. As of December 31, 2021, residential, commercial, industrial, and other customers represented 41%, 12%, 4%, and 43%, respectively, of Enel Distribution Ceara’s total electricity sales of 12,731 GWh.

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The following table sets forth Enel Distribution Ceara’s primary operating data for each of the periods indicated:

	Year ended December 31,
	2021	2020	2019
Electricity sales (GWh)	12,731	11,866	12,197
Residential	5,178	4,910	4,610
Commercial	1,534	1,676	1,953
Industrial	563	596	666
Other customers(1)	5,456	4,684	4,968
Number of customers (thousands)	4,059	4,011	3,956
Residential	3,247	3,176	3,114
Commercial	174	183	187
Industrial	6	6	6
Other customers	632	646	649
Energy purchased (GWh)	15,177	14,103	14,186
Total energy losses (%)(2)	16.1	15.9	14.0
SAIDI (hours)	11.4	15.9	13.9
SAIFI (times)	4.7	6.0	5.4
Collection rate (%)(3)	98.7	100.3	97.4

(1) The data for other customers includes tolls.

(2) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines and technical losses.

(3) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

In 2021, Enel Distribution Ceara’s primary unregulated customers were (ordered alphabetically): Cagece Eta Gaviao; Gerdau Aços Longos S/A; Nova Fiação Indústria Textil; TBM - Textil Bezerra de Menezes S/A; and Vicunha Textil S/A.

Enel Distribution Goias (Brazil)

Enel Distribution Goias operates in a concession area of 337,002 square kilometers, distributing electricity to municipalities located in the state of Goiás and serving approximately 3.3 million customers under a concession granted by the Brazilian government, which expires in July 2045. As of December 31, 2021, residential, commercial, industrial, and other customers accounted for 37%, 13%, 4%, and 46%, respectively, of Enel Distribution Goias’ total electricity sales of 15,076 GWh.

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The following table sets forth Enel Distribution Goias’ primary operating data for each of the periods indicated:

	Year ended December 31,
	2021	2020	2019
Electricity sales (GWh)	15,076	14,469	14,365
Residential	5,617	5,382	5,066
Commercial	1,976	1,972	2,260
Industrial	532	654	821
Other customers(1)	6,951	6,461	6,217
Number of customers (thousands)	3,291	3,207	3,114
Residential	2,834	2,753	2,730
Commercial	212	219	222
Industrial	9	9	9
Other customers	236	227	153
Energy purchased (GWh)	16,996	16,330	16,382
Total energy losses (%)(2)	11.3	11.4	12.3
SAIDI (hours)	18.1	15.9	22.5
SAIFI (times)	8.4	8.5	9.7
Collection rate (%)(3)	100.4	97.5	98.1

(1) The data for other customers includes tolls.

(2) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines and technical losses.

(3) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

In 2021, Enel Distribution Sao Goias’primary unregulated customers were (ordered alphabetically): BRF Rio Verde; Cimpor; Copebras; Mineração Serra Grande; and Ultrafertil.

Enel Distribution Sao Paulo (Brazil)

Enel Distribution Sao Paulo operates in a concession area of 4,526 square kilometers, distributing electricity to municipalities located in the Sao Paulo metropolitan area and serving approximately 8.0 million customers under a concession granted by the Brazilian government, which expires in June 2028. As of December 31, 2021, residential, commercial, industrial, and other customers accounted for 40%, 19%, 5%, and 36%, respectively, of Enel Distribution Sao Paulo’s total electricity sales of 41,087 GWh.

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The following table sets forth Enel Distribution Sao Paulo’s primary operating data for each of the periods indicated:

	Year ended December 31,
	2021	2020	2019
Electricity sales (GWh)	41,086	40,350	43,148
Residential	16,569	16,074	16,365
Commercial	7,836	9,375	10,516
Industrial	2,169	2,620	2,772
Other customers(1)	14,512	12,281	13,496
Number of customers (thousands)	8,052	7,896	7,777
Residential	7,544	7,392	7,286
Commercial	448	445	438
Industrial	29	30	28
Other customers	31	30	25
Energy purchased (GWh)	45,819	45,154	47,804
Total energy losses (%)(2)	10.3	10.6	9.6
SAIDI (hours)	6.6	7.4	6.3
SAIFI (times)	3.4	3.6	3.5
Collection rate (%)(3)	100.3	99.6	100.6

(1) The data for other customers includes tolls.

(2) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines and technical losses.

(3) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

In 2021, Enel Distribution Sao Paulo’s primary unregulated customers were (ordered alphabetically): Bridgestone; Cisper; Pirelli; Sabesp; and Walter Torre.

Codensa (Colombia)

Codensa operates in a concession area of 26,093 square kilometers in Bogotá and 130 other municipalities in the province of Cundinamarca, serving approximately 3.7 million customers. Under Colombian law, since no concessions are granted, administrative authorization is required to provide distribution service. In the case of Codensa, the authorization is of indefinite duration.

Since 2001, Codensa has only provided services to regulated customers. The unregulated market is serviced directly by our generation company, Emgesa, except for public lighting in Bogotá. As of December 31, 2021, residential, commercial, industrial, and other customers accounted for 37%, 15%, 7%, and 41%, respectively, of Codensa’s total electricity sales of 14,598 GWh.

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The following table sets forth Codensa’s primary operating data for each of the periods indicated:

	Year ended December 31,
	2021	2020	2019
Electricity sales (GWh)	14,598	13,834	14,307
Residential	5,385	5,407	5,113
Commercial	2,216	2,035	2,508
Industrial	1,021	927	1,044
Other customers(1)	5,976	5,464	5,642
Number of customers (thousands)	3,708	3,615	3,527
Residential	3,312	3,222	3,144
Commercial	330	327	322
Industrial	49	49	49
Other customers	17	17	12
Energy purchased (GWh)(2)	15,786	14,964	14,368
Total energy losses (%)(3)	7.5	7.6	7.7
SAIDI (hours)	6.7	7.8	11.1
SAIFI (times)	5.2	5.6	6.8
Collection rate (%)(4)	101.6	100.0	100.9

(1) The data for other customers includes tolls.

(2) In 2021, 48.3% of the electricity purchased without tolls was acquired from Emgesa, compared to 52.8% in 2020, and 51.6% in 2019.

(3) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines and technical losses.

(4) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

Enel Distribution Peru (Peru)

Enel Distribution Peru operates in a concession area of 1,602 square kilometers, distributing electricity in the northern part of the Lima metropolitan area, some provinces in the Lima region, including Huaral, Huaura, Barranca, and Oyón, and the adjacent province of Callao and serving approximately 1.5 million customers under a concession granted by the Peruvian government of indefinite duration.

As of December 31, 2021, residential, commercial, industrial, and other customers accounted for 39%, 9%, 23%, and 29%, respectively, of Enel Distribution Peru’s total energy sales of 8,130 GWh.

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The following table sets forth Enel Distribution Peru’s principal operating data for each of the periods indicated:

	Year ended December 31,
	2021		2020	2019
Electricity sales (GWh)	8,130		7,578	8,211
Residential	3,185		3,188	3,068
Commercial	719		666	814
Industrial	1,838	��	1,557	1,937
Other customers(1)	2,388		2,167	2,392
Number of customers (thousands)	1,493		1,456	1,434
Residential	1,400		1,377	1,359
Commercial	61		47	47
Industrial	2		2	2
Other customers	30		30	27
Energy purchased (GWh)(2)	8,885		7,040	7,649
Total energy losses (%)(3)	8.5		8.8	8.2
SAIDI (hours)	6.9		7.0	7.0
SAIFI (times)	2.3		2.6	2.8
Collection rate(4)	101.0		95.8	99.8

(1) The data for other customers includes tolls.

(2) In 2021, 25.8% of the electricity purchased was acquired from Enel Generation Peru, Chinango, and Enel Generation Piura, compared to 33.5% in 2020 and 34.5% in 2019.

(3) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines and technical losses.

(4) The collection rate is seasonally adjusted. It corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. It may be greater than 100% due to the collection of unpaid bills from previous periods.

In 2021, Enel Distribution Peru’s primary unregulated customers were (ordered alphabetically): AGP Peru S.A.C.; Ajinomoto Del Peru S.A.; APM Terminals Callao Sociedad Anonima; Cía. Industrial Nuevo Mundo S.A.; Cía. Minera Agregados Calcareos S.A.; Corporación Lindley S.A.; DP World Callao S.R.L.; Filasur S.A.; Lima Airport Partners S.R.L.; Minera Colquisiri S.A.; Nestlé Perú S.A.; Owens Illinois Peru S.A.C.; and Productos Tissue del Peru S.A.C.

For further details regarding the regulation of the distribution business, see “Item 4. Information on the Company— B. Business Overview — Electricity Industry Regulatory Framework.” For further details regarding the financial impact, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2021, and 2020.”

Seasonality

Seasonal changes in energy demand directly influence the distribution business. Although the price at which a distribution company purchases electricity can change seasonally and has an impact on the price at which it is sold to end-users, it does not have an effect on our profitability since the cost of electricity purchased is passed on to end-users through tariffs that are set for multi-year periods. However, in the case of regulated customers, an increase in tariffs due to rate adjustments may not happen immediately, which could affect our profitability in the short term.

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ELECTRICITY INDUSTRY REGULATORY FRAMEWORK

Argentine Electricity Regulatory Framework

1. Industry Overview and Structure

In the Argentine Wholesale Electricity Market (“MEM” in its Spanish acronym), there are four categories of local agents (generators, transmitters, distributors, and large customers) and two external agents (traders of generation and traders of demand) who are allowed to buy and sell electricity and related products. CAMMESA is the autonomous entity responsible for operating the Argentine MEM.

Argentina’s electricity industry has one main interconnected system, the Argentine NIS. The Argentine MEM manages the electricity market in the Argentine NIS.

The following chart shows the relationships among the various participants in the Argentine MEM:

Generation

The generation segment is comprised of companies that own electricity generation power plants that sell their energy to the market at a price established by the regulator. Hydroelectric generators with a normal generation capacity exceeding 500 kW must obtain a concession to use public water sources. Concessions may be granted for a fixed or indefinite term. Concession holders may also appropriate private properties within the concession area to operate hydroelectric power plants. The El Chocón and Arroyito power plants operate under this type of concession, which expires in August 2023. Thermal power plants do not require a concession but must receive authorization to connect to the grid and are only regulated with respect to public safety and environmental protection.

Transmission

The transmission sector is a public service that operates under monopoly conditions and comprises companies that have been granted concessions by the Argentine government. One concessionaire operates and maintains the highest voltage facilities. In contrast, eight concessionaires operate and maintain high- and medium-voltage facilities to which generation plants, distribution systems, and large customers are connected. Transmission companies are authorized to charge different tolls for their services.

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Distribution

Distribution is a public service that operates under monopoly conditions and comprises companies that have been granted concessions according to their national, provincial, or municipal jurisdiction. Distribution companies must make electricity available to regulated end customers within a specific concession area. Distributors have regulated tariffs and are subject to quality service specifications. Distributors may sign contracts for electricity with generators or other distributors at freely negotiated prices. They may also buy electricity in the Argentine MEM’s spot market at the so-called “seasonal price,” defined by the Argentine Secretary of Energy (“SEE” in its Spanish acronym) as the maximum electricity cost purchased by distributors that can be passed on to regulated customers.

Customers

Distributors supply regulated and unregulated customers. Regulated customers are defined as those that demand up to 30 kW of capacity, and unregulated customers are defined as those who demand at least 30 kW of capacity. The latter are classified into three categories: major large (demand of power of at least 1MW), minor large (demand of power between 30 kW and 2,000 kW), and large private customers (demand of power between 30 kW and 100 kW). Major large customers are required to purchase 50% of their demand through supply contracts and 50% in the spot market, while minor large and large private customers must purchase all demand through supply contracts.

Limits on Integration and Concentration

Vertical and horizontal integration restrictions apply to companies that intend to participate simultaneously in different segments of the electricity market. The vertical integration restrictions under Law No. 24,065 of 1991, known as the “Electricity Framework,” are applied differently to each segment.

A transmission company and any of its controlled or controlling companies are prohibited from buying and selling electricity, and they cannot own or control a generation or a distribution company. Likewise, neither a generation nor a distribution company, nor any of its controlled or controlling companies, can be an owner, majority shareholder, or the controlling entity of a transmission company. Furthermore, a distribution company cannot own generation units. However, the shareholders of an electricity distributor may own generation units either directly or through any other entity created to own or control generation units. Since a distribution company cannot own generation units, a holder of generation units cannot own distribution concessions. However, an electricity generator’s shareholders may own an entity that holds distribution units, either by themselves or through any other entity created to own or control distribution units.

Transmission and distribution companies may merge with or into another company in the same segment, only with the express approval of the Argentine National Regulatory Authority for the Energy Sector (“ENRE” in its Spanish acronym). Such approval is also necessary when a transmission company intends to acquire shares of another transmission company.

Electricity Markets

In the Argentine MEM, generators sell electricity to other generators, distributors, traders, and unregulated customers in two different markets: the contracts market (“mercado a término”) and the spot market. Quantities, prices, and terms are freely negotiated. In the spot market, electricity surpluses from the contracts market are traded. There are two different kinds of prices (hourly spot price and seasonal price) at which the electricity is sold, depending on whether the counterparty is a distributor. The hourly spot price is the marginal cost to produce an additional MWh and changes according to demand and availability of power plants. This is the price generators pay to other generators and traders. Given the difficulty for distribution companies to calculate a rate for the end user based on hourly marginal prices, the SEE, based on CAMMESA’s projections, approves a seasonal or stabilized price every six months (season) subject to quarterly revisions. As a result, the seasonal price becomes the price distributors pay to generators in the spot market.

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2. Electricity Sector Laws

Private companies originally developed the Argentine electricity industry. The Argentine government began to intervene in the sector in the 1950s and initiated a nationalization process. The electricity industry was first regulated by Law No. 15,336 of 1960, which allowed the construction and expansion of power plants controlled by government-owned corporations. The Electricity Framework was enacted to replace the vertically integrated system based on a centralized state monopoly with a competitive system based on market conditions.

A renewable energy framework was established by Law No. 25,019 of 1998 and Law No. 27,191 of 2015. Under Law No. 27,191, hydroelectric plants with a capacity of up to 50 MW qualify as “renewable” in this context. The law establishes that large customers need to meet their demand through contracts associated with renewable technologies according to the following schedule: 16% by 2021, 18% by 2023, and 20% by 2025.

3. Principal Regulatory Authorities

Responsible for Setting Policy

The SEE is responsible for promoting and setting policies and regulations to manage the electricity industry. The Electric Power Federal Council advises on the electricity legislation, guides the executive branch and provincial governments on electricity industry topics, and manages dedicated electricity sector funds.

Responsible for Regulation

ENRE, an entity within the SEE, supervises and regulates the industry, setting tariffs and promoting free access, investments, and competitiveness within the sector.

System Operator

CAMMESA is an autonomous entity that coordinates the operation of the Argentine NIS to guarantee safety and quality. It manages and executes the dispatch of electricity, organizes supply at the minimum cost, controls the acquisition of fuel and its supply to generators, establishes wholesale prices, and oversees the execution of free contracts between generators, distributors, and large users. These functions are designed to ensure transparency through the participation and regulation of all stakeholders.

4. Remunerations and Tariffs

Remuneration for Generators

SEE Resolution No. 31/2020 established a remuneration scheme in Argentine pesos for all existing renewable energy sources. It also defined a minimum remuneration for electricity generation by technology and scale according to power availability, generation, and delivery of electricity. As per the resolution, the remuneration values would be updated monthly based on the consumer price index and the wholesale price index. In May 2021, SEE Resolution No. 440/2021 updated the remuneration scheme established in the SEE Resolution 31/2020 to increase remuneration by 29%, retroactive to February 2021. In November 2021, SEE Resolution No. 1,037/2021 updated the remuneration scheme established in SEE Resolution No. 440/2021, establishing an additional remuneration benefit to thermal and hydraulic generators that export energy to neighboring interconnected countries, applicable to transactions between September 1, 2021, and February 28, 2022.

Distribution Tariffs

The concessions contracts of the distributors under ENRE’s jurisdiction contain public service tariffs made up of two variables: (i) the purchase price in the MEM (seasonal price and transportation costs) and (ii) the value added for distribution (“VAD”). The VAD corresponds to the remuneration received by the distributors for their operations and includes development and investment costs in networks, operation and maintenance, and commercialization, as well as depreciation and a fair and reasonable profit margin on capital investment. Its calculation is subject to an Integral Rate Revision mechanism approved by ENRE for each distributor. The tariffs are approved for a five-year period, in which they can vary according to the purchase price in the MEM, but the VAD cannot be modified.

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The current VAD and tariffs for Edesur, effective as of March 1, 2022, were established by ENRE Resolution 75/2022. The current seasonal price was established by SEE Resolution 105/2022.

The government reached an agreement with the International Monetary Fund, which demanded a reduction in energy subsidies, to increase rates on consumers in 2022 and 2023. The rate increases will be tied to the variation in wages and follow a tiered pricing scheme.

The top 10% of wage earners will no longer receive subsidies for consumption. Consumers receiving the social rate (“tarifa social”) will be subject to an increase equivalent to 40% of the salary variation coefficient (“CVS” in its Spanish acronym) from the previous year. The remaining consumers will be subject to a total increase for each calendar year equivalent to 80% of the CVS from the previous year.

Large users, including businesses and industries, will pay the full rate for industrial consumers. All other consumers will be subject to a rate review.

Stabilization Fund

CAMMESA manages a stabilization fund established by the Electricity Framework to absorb the difference between distributors’ purchases at seasonal prices and payments to generators for energy sales at the spot price. When the spot price is lower than the seasonal price, the stabilization fund increases. When the spot price is higher than the seasonal price, the stabilization fund decreases. The outstanding balance of this fund at any given time reflects the accumulation of differences between the seasonal price and the hourly energy price in the spot market. The stabilization fund must maintain a minimum balance to cover payments to generators if prices in the spot market during the quarter exceed the seasonal price.

The stabilization fund has been adversely affected due to modifications to the spot price and the seasonal price made by the emergency regulations, under which seasonal prices were set below spot prices resulting in large deficits in the stabilization fund. The Argentine government has financed these deficits through loans to CAMMESA and with funds from FONINVEMEM, a fund managed by CAMMESA created to encourage electricity capacity within the Argentine MEM. Still, these actions have been insufficient to cover the differences between the spot price and the seasonal price.

Transmission Tariffs

The transmission sector is regulated by the electricity framework and the terms of the concession granted to Transener S.A., the primary operator of transmission lines in Argentina, under Decree 2,743. Due to technological reasons, the transmission sector is heavily affected by economies of scale that limit competition. As a result, the transmission sector operates under monopoly conditions and is subject to considerable regulation. In accordance with Resolution No. 196 of the Argentine government, ENRE completed the RTI before January 31, 2017.

In November 2017, the SEE published Resolution No. 1,085, which approved the new methodology to distribute the remuneration cost of transmission. The resolution stated that as of December 1, 2017, the cost of the transmission system has to be proportionately paid in terms of demand, and generators have to pay for direct connection costs. It instructed CAMMESA to perform the calculations of the Argentine MEM’s public electricity transportation service prices for its distribution agents based on the approved methodology, including the adjustments required when seasonal prices are revised. This rule determined that charges and bonuses did not depend more on the facilities’ use but on regional allocation.

5. Environmental Regulations

Electricity facilities are subject to federal and local environmental laws and regulations, including Law 24,051, the “Hazardous Waste Law,” and ancillary regulations. Certain reporting and monitoring obligations and emission standards are imposed on the electricity sector. Failure to satisfy these requirements entitles the Argentine government to impose penalties such as suspension of operations that, in the case of public services, could result in the cessation of concessions.

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6. Other Regulations and Measures

Regulatory Issues Due to the Covid-19 Pandemic

As a result of the Covid-19 pandemic, the government of Argentina ordered: (i) the closure of all commercial offices for an indefinite term starting in March 2020; (ii) the restriction of suspension of essential services as of March 2020 for 180 days, including for users with current notices of service cuts outstanding; (iii) allowance for users who suffered a 50% or greater reduction in their power demand to suspend payment of energy bills or make them in installments until demand reached 70% of normal demand; (iv) charges to residential tier one users during periods without meter readings (from March 2020 to May 2020) should be equal to the lowest consumption of energy recorded in the same month during the last three years; and (v) the creation of a solidarity account to finance tasks, construction, or modifications related to connection and guaranteed access to electrical energy for customers (as defined in Article 1 of Law No. 27,351), which account is funded by fines charged for poor service quality and product and commercial deficiencies.

Incentives

The so-called Energy Plus Service Program is provided by generators that have (i) installed new generation capacity or (ii) connected previously unconnected existing generation capacity to the Argentine NIS. All large customers with higher demand than their base demand as of November 1, 2006, were required to enter into a contract with the Energy Plus Service Program to cover their excess demand. The primary purpose of the Energy Plus Service Program is to encourage large customers with a need greater than or equal to 300 kW to sign a contract with a fast installation thermal generation power plant and to penalize those who consume above their historical levels and do not have a contract with a fast installation thermal generation power plant. Large customers who do not enter into such agreements must pay additional amounts for any consumption that exceeds base demand. The authorities must approve the prices under the contracts with the Energy Plus Service Program. Unregulated customers who cannot secure an Energy Plus Service contract can request that CAMMESA conduct an auction to satisfy their demand.

Fuel procurement

In the years following Resolution 95/2013, which placed significant constraints on the normal functioning of the electricity market, CAMMESA took control of fuel supply and procurement. Resolution 70/2018 was designed to normalize the fuel market for thermal generation gradually. The resolution allowed generators to obtain fuel on their own only if the fuel price was lower than the reference price set by CAMMESA. All generators that opt out of the fuel purchase by CAMMESA and fail to obtain the required fuel to operate are sanctioned under Resolution 1/2019.

In December 2019, through Resolution 12/2019, the Argentine government repealed Resolution 70/2018, which allowed generators to obtain their own fuel. As a result, generators must now purchase fuel directly from CAMMESA.

Energy Purchases

Distribution companies must satisfy 100% of customer demand in their concession area under specific regulated service quality standards and prices. To do so, distributors must ensure the reliability and quality of their energy supply. Distribution companies purchase energy on the Argentine MEM, which may be commercialized through either the spot market, the seasonal market, or contracts. In the spot market, electricity prices change hourly according to demand and the availability of power plants. The seasonal market works by identifying two six-month seasons within each year related to hydrology: one from May 1 and the other from November 1. A stabilized energy price is determined for each season according to the expected generation costs during those six-month periods. Distributors purchase energy at that price, and the price difference, compared to the spot market, is added to the following period. Distributors may also sign contracts with generators at freely negotiated prices that may include clauses regarding duration, delivery, payment, breach, and respective compensation.

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Brazilian Electricity Regulatory Framework

1. Industry Overview and Structure

There are six types of participants in the Brazilian electricity market: generators, transmitters, distributors, traders, regulated customers, and unregulated customers. Brazilian law establishes an unbundled system where generation, transmission, distribution, and trading are different activities.

Brazil’s electricity industry is organized into one large, interconnected electricity system, the Brazilian NIS, which provides coverage to more than 99% of the Brazilian population. There are four sub-market divisions (different from the geographical division) within the Brazilian NIS: South-East/Center-West, South, Northeast, and North. The Brazilian National Electric System Operator (“ONS” in its Portuguese acronym) is responsible for managing and operating the Brazilian NIS.

The following chart shows the relationships among the various participants in the Brazilian NIS:

Generation

The generation sector is organized on a competitive basis, with independent power producers (IPPs) or concessionaires that enter into purchase power agreements (PPAs) with regulated distributors, traders, or unregulated customers. Hydroelectric plants with an installed capacity of up to 50 MW must obtain governmental authorizations while hydroelectric plants with an installed capacity of more than 50 MW must obtain a water rights concession and environmental licenses. Wind and solar farms must obtain authorization from government authorities and are generally subject to simplified environmental licenses and their respective surveys and archeological permits.

Transmission

The transmission sector operates under public/private monopoly conditions with auctioned concession contracts. ANEEL fixes the annual revenues for all transmitters with operations in Brazil. The transmission network comprises any transmission facility operating above 230 kV.

Distribution

Distribution is a public service that operates under monopoly conditions. Companies allowed to operate the distribution service have a concession to act in a geographically defined concession area. Distributors must satisfy their electricity supply needs through contracts. Tariffs are defined by ANEEL under the price cap regulatory regime.

Concessions

In Brazil, companies or consortia that intend to build or operate transmission networks or hydroelectric power plants with a capacity exceeding 50 MW need to participate in a public tender process. Law No. 8,987/1995 (“Concessions Law”) grants concessions and authorizations to generate, transmit, or distribute electricity in a defined concession area for a certain period. New generation concessions or authorizations depend on the source of energy production and are

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limited to a maximum of 35 years, while new transmission or distribution concessions are limited to 30 years. Existing concessions for transmission, distribution, and hydro and thermal generation may be renewed by the government, through the sole discretion of the Brazilian MME for a period up to the duration of their initial term.

Trading

Laws, decrees, and resolutions governing the sale and purchase of electricity, including Law No. 10,848, Decrees 5,163 and 5,177 relating to the Electricity Trading Chamber (“CCEE” in its Portuguese acronym) and the role of ANEEL, and Resolution 109, which introduced the Electricity Trading Convention, define the terms, rules, and procedures for trading at the CCEE.

These regulations introduced two alternatives for the execution of the PPAs: (i) regulated contracts between power generators or traders and distributors; and (ii) unregulated market contracts between energy generators, energy traders, importing and exporting agents, and unregulated customers.

PPAs govern commercial relations between the participants in the CCEE. It is mandatory for free customers, energy generators, traders, and distributors to register contracts with the CCEE, including information about the volume of traded energy and the agreement’s terms. There is no obligation to register energy prices of unregulated PPAs.

Customers

Regulated Customers

Only customers that demand more than 500 kW are free to choose their energy supplier. Therefore, the regulated market comprises all customers that demand less than 500 kW and those that demand more than 500 kW that opt ​​for the regulated market.

Unregulated Customers

The unregulated market includes the electricity trade between power generation concessionaires, independent producers, self-producers, energy traders, importers of electricity, and unregulated customers.

In Brazil, the customers with a demand of more than 500 kW may choose an energy supplier from renewable sources in addition to the local distributor in their area, and customers with a demand of more than 1,500 kW may choose an additional energy supplier from any source (including renewable), but this is an option, not an obligation.

Pursuant to MME Ordinance 465/2019, the 1,500-kW limit for energy supply from conventional sources and was lowered to 1,000 kW on January 1, 2022, and will be lowered further to 500 kW on January 1, 2023, ending the current market reserve for renewable sources.

Limits on Integration and Concentration

Generation, transmission, and distribution companies in Brazil are not permitted to perform activities related to other segments, or to hold, directly or indirectly, any equity interest in any other company, corporation, or partnership. Distribution companies are not permitted to develop activities unrelated to their respective concessions, except for those permitted by law, approved by the regulator, or established in the relevant concession agreement.

Electricity Markets

The wholesale energy market is composed of generation companies, traders, and distribution companies. The purchase and sale of electricity are freely negotiated. In the short-term market, electricity sales and purchases are carried out at spot market prices set by the CCEE. These prices are calculated every hour on a marginal cost basis (hourly Settlement Price for Differences “PLD” in its Portuguese acronym), modeling future operating conditions and establishing a merit order curve with variable costs for thermal units and opportunity costs for hydroelectric plants, which results in one price for each subsystem currently set for the week after its determination.

2. Electricity Sector Laws

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The current legislative framework was established by Law No. 10,848/2004 (“Brazilian Electricity Law”). The Brazilian Electricity Law encourages competition and private capital. It introduced independent power producers (IPPs) to open the electricity sector to private sector investment. IPPs are individual agents, or agents acting in a consortium, who receive a concession, permit, or authorization from the Brazilian government to generate and sell electricity.

3. Principal Regulatory Authorities

Responsible for Setting Policy

The MME is responsible for setting national energy policies, guidelines, and regulations for the sector. Within the MME, the National Energy Policy Council oversees developing and proposing national energy policies for the president of Brazil, and the Energy Sector Monitoring Committee monitors and evaluates the continuity and security of the country’s electricity supply.

Responsible for Regulation

ANEEL is responsible for regulating the government’s policies and guidelines for the generation, transmission, and distribution of electricity. ANEEL promotes the efficient use of electricity at the regional level by regulating service quality and safety standards, tariffs, and the research and development of energy efficiency projects.

System Operator

The ONS is a private non-profit entity that operates under ANEEL’s authorization. Its fundamental role is to optimize the Brazilian NIS and other isolated systems, focusing on ensuring an adequate supply of electricity at reasonable costs.

Responsible for Trading

The CCEE is a non-profit private entity regulated and supervised by ANEEL. Its role is to provide an environment for energy trading activities and operations, improving solutions according to market needs with integrity, transparency, and accountability. The CCEE consists of public service generation companies, independent producers, self-producers, distributors, traders, importers and exporters of energy, and free and particular consumers from all over the country.

4. Tariffs

Remuneration for Generators

The generators trade the differences between production and sales (demand) on the short-term market or spot market at the PLD. The PLD’s purpose is to find an optimal equilibrium between the current benefit obtained from the water use and the future benefit resulting from its storage, measured in terms of the savings from the use of fuels for thermal plants.

The Electricity Reallocation Mechanism (“MRE” in its Portuguese acronym) is used by hydroelectric generators that seek to re-allocate hydrological risk by offsetting differences between the plant’s firm energy and its actual production. The MRE provides financial protection against hydrological risks to hydroelectric generators by ensuring them optimally supplied hydrological resources by taking advantage of Brazil’s geographic reach and its diversity in different rain regimes. The MRE guarantees that, notwithstanding the centralized dispatch, all hydroelectric generators will have a share of the total national hydroelectric production proportional to their “firm energy” or maximum firm energy (physical guarantee), which is the electricity that a hydroelectric generation plant can deliver continually during a year, considering poor hydrological conditions.

The MRE allows each hydroelectric producer to fulfill its contracts before buying energy in the spot market, to purchase cheaper energy at a price that covers the incremental costs of operation, the maintenance of hydroelectric plants, and the financial compensation for the use of water. The system’s total hydroelectric production is more stable and reliable than a single hydroelectric power plant. Therefore, the MRE is an efficient mechanism to reduce individual power plant generation volatility and hydrological risk. Energy contracts in Brazil are only financial instruments, and electricity production is disassociated from contracted energy.

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In recent years, however, insufficient rainfall, an increase in the number and relevance of run-of-the-river plants with consequential loss of regulation capacity, and, above all, a distorted use of the MRE to cope with non-hydrological risks led to hydroelectric generation plants frequently being under their firm energy levels (generating scaling factor < 1). Due to the lack of a regulatory solution, generation companies filed a lawsuit and obtained an injunction against exposure to the short-term market.

After a lengthy legal and judicial process to resolve this dispute, in September 2020, Law 14,052/2020 established new conditions for the renegotiation of hydrological risk. On December 1, 2020, ANEEL published Normative Resolution No. 895/2020 to regulate the compensation of non-hydrological risks assumed by hydroelectric plants between 2013 and 2020. After the determination of regulatory assets by the CCEE and ANEEL during the first half of 2021, the generation companies signed the renegotiation agreement and withdrew from the judicial proceedings. Next, ANEEL must publish orders to postpone the end of authorization grants and sign amendments to postpone the end of concession contracts.

Transmission Tariffs

Transmission revenue is a fixed fee that does not depend on the amount of electricity flowing through the network. Similar to distribution companies, transmission companies have (i) an ordinary tariff review every four years; (ii) an annual tariff adjustment due to inflation and annually allowed revenues (a fixed amount paid by consumers and generators); and (iii) an extraordinary tariff review if extraordinary events take place.

Distribution Tariffs

Distribution tariffs to end customers are subject to review every 3 to 5 years, annual adjustments, and reviews by ANEEL to reflect changes in energy purchase costs and market conditions. For adjusting distribution tariffs, ANEEL divides the costs of distribution companies into (i) costs beyond the control of the distributor, such as energy purchases and taxes (“Parcel A costs”), and (ii) costs under the control of distributors (“Parcel B costs”), the VAD. Each distribution company’s concession agreement provides for an annual adjustment.

Distribution companies’ pricing is intended to maintain constant operating margins for the concessionaire. It allows for tariff changes due to Parcel A costs and the concessionaire to retain any efficiency gains achieved for defined periods. Tariffs to end customers are also adjusted according to the variation of costs incurred in purchasing electricity. If there is a substantial change in its operating costs, the law guarantees a company’s economic and financial equilibrium. If Parcel A cost components increased significantly within the period between two annual tariff adjustments, the concessionaire would request ANEEL to transfer those costs to end customers.

The Concessions Law establishes ordinary tariff reviews according to the concession contract of each distributor, annual inflation adjustments, and extraordinary tariff reviews.

On January 7, 2022, Law No. 14,300/2022 was enacted, updating Normative Resolutions Nos. 482/2012 and 687/2015, which established the legal framework for distributed generation (“DG”). DG allows consumers to deduct from their electricity bill the amount of energy produced by their generation plants (net metering). Consumers receive credits, which must be used within five years if they produce more energy than they consume in a given month.

The law guarantees the maintenance of the current tariff rules until 2045 for plants already in operation or to be installed within 12 months. Additionally, it creates a transition period for new DG plants that are connected up to 18 months after the publication of the law. After the transition period, consumers with DG must pay 100% of the network toll (tariff for use of the distribution network), net of the systemic benefits generated by DG, which must be calculated by the Regulator in the next 18 months.

Revenue from Tariff Flags

ANEEL applies an additional monthly charge to customer tariffs whenever the system’s actual marginal cost has been higher than the defined marginal cost. The regulator’s objective is to provide the consumer with the real cost of generation considering the anticipated additional tariff rate to the distributor, as described in the chart below, that otherwise would have been reflected in the following annual tariff adjustment review. This mechanism is composed of the following levels: green, yellow, red, and water scarcity. On August 31, 2021, the Brazilian MME, through Chamber

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of Exceptional Rules for Hydropower Management Resolution 3/2021, determined that ANEEL implement a new flag rate for water scarcity in the amount of R$ 0.1420/kWh, valid from September 2021 to April 2022.

Since its creation, the cost ranges and additional tariffs have changed according to new expectations of the marginal cost of generation. As of the date of this Report, the tariffs are as follows:

	Description	Additional Tariff Rate (R$/kWh)
Green	Favorable generation conditions	No additional rate
Yellow	Less favorable generation conditions	+0.01874
Red Level 1	Expensive generation conditions	+0.03971
Red Level 2	Expensive generation conditions	+0.09492
Water Scarcity	Most expensive generation conditions	+0.1420

Energy Development Account

The Energy Development Account (“CDE” in its Portuguese acronym) is a sectoral fund that finances several public policies in the Brazilian electricity sector, such as universalization of the electric energy service throughout Brazil; granting of tariff discounts to several users of the service (low income, rural, irrigating, public water, sewage and sanitation services, incentive energy generation and consumption, etc.); low tariff for isolated electrical systems (Fuel Consumption Account - CCC); and competitiveness of electricity generation from the national coal source, among others.

CDE resources are collected mainly from the annual dues paid by all distribution companies that sell electricity to end consumers through a tariff charge included in the tariffs for the use of energy distribution and transmission systems.

Since the CDE is a sector charge, it is economically neutral to distribution companies once ANEEL collects it via a regulatory tracking account. However, since tracking account validation occurs only once a year, financial timing mismatch may occur.

Between January 1, 2017, and December 31, 2029, the CDE charges will be gradually balanced in Brazilian regions. As of January 1, 2030, the annual cost per MWh will be prorated according to the customer’s connected tension level.

In 2020, within the set of measures to cope with the effects of the Covid-19 pandemic, the government implemented a financial mechanism called the “Covid Account.” The CCEE began lending funds to distribution companies for short-term cash purposes. Customers will be charged an additional CDE fee from 2021 to 2026 to repay the funds lent to distribution companies.

Transfers from Other Transmission Facilities (“DIT”) for Distribution Companies

On February 13, 2017, ANEEL issued Resolution No. 758, establishing the conditions required to transfer installations with voltage less than 230 kV (Basic Network referred to as “DIT”) from electricity transmission companies to distribution concessionaires. Enel Distribution Rio will receive DITs during its next ordinary tariff review in March 2023. Enel Distribution Ceara, Enel Distribution Goias, and Enel Distribution Sao Paulo will not receive any DITs.

5. Environmental Regulations

Article 225 of the Federal Constitution establishes the Brazilian environmental legal system. In brief, it operates: (i) preventively, through environmental licensing rules, policies aimed at protecting natural resources, and environmental standards set by the National Environmental Council, at a federal level, and by bodies of the National Environmental System at the state level; and (ii) reactively, through criminal and administrative penalties, and mechanisms for compensation of environmental damages caused.

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The installation and development of potentially polluting activities are contingent upon prior environmental licensing. The environmental bodies will verify whether proper measures are being taken to protect the environment and require the implementation of such actions. Federal and state rules can regulate environmental licensing.

The environmental legislative system in Brazil can be regulated by federal, state, or municipal rules. If any of the environmental protection rules are found to have been breached, the inspecting authority shall impose the administrative and criminal penalties prescribed by law.

6. Other Regulations and Measures

Covid-19 pandemic - Financial Measures

On June 23, 2020, ANEEL approved the regulation establishing the “Covid Account”. This regulation sets forth criteria for a syndicated loan to distribution companies to guarantee sufficient cash flow during the pandemic and to avoid subsequent tariff adjustments.

The CCCE receives the loan amount for the “Covid Account”, which ANEEL subsequently approves, and the funds are transferred to the distribution companies. As of 2021, distribution companies pass on the loan repayment to consumers within five years by charging an additional fee to the energy development account.

On November 23, 2021, ANEEL approved the rules for evaluating requests for economic rebalancing as a result of the impacts of the Covid-19 pandemic.

On January 13, 2022, the federal government, through Decree 10,939/2022, authorized the CCEE to create and manage the water scarcity account, allocating resources to cover the total or additional costs for distribution companies due to the water situation in 2021.

Covid-19 pandemic - Operational Measures

ANEEL implemented provisional rules to adapt to the Covid-19 pandemic. It approved Resolution No. 878/2020, which was in force from March 25, 2020, to July 31, 2020. The main measures were:

● temporary suspension of face-to-face service to the public to preserve the health of employees and the population at large;

● suspension of the term limit for claiming compensation for damages to equipment;

● suspension of the obligation to deliver printed invoices to consumers’ addresses;

● permission to bill electronically;

● permission for distribution companies to use consumption readings at intervals different from customary or to provide means for the consumer to provide meter readings;

● prohibition of suspension of electricity supply due to default by urban and rural residential consumer and for essential services and activities; and

● the interruption of any services or service channels by distribution companies being required to be preceded by broad communication to the public through publication on the company’s website.

Incentives for Renewable Energy

Under the current regulatory framework, a “new electricity production project” benefits from regulated long-term PPAs (20 years for wind and solar and 30 years for hydroelectric). The price levels for each technology are a means to attract investment in capacity expansion and allow reasonable project finance conditions. Existing power plants, including depreciated assets, sell their energy at lower prices and under contracts with shorter terms.

Laws Nos. 10,438 and 14,120 regulated an incentive for renewable energy generation or extension projects that request concessions until March 2022 and must go into operation within 48 months. The incentives consist of a discount of up to 50% on distribution or transmission tariffs. As of March 1, 2022, the incentive applies only for new hydroelectric generation projects with an installed capacity of up to 30 MW. The discount will remain at 50% for five

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additional years and at 25% for the following five years. The compensation for eliminating the incentive for other renewable projects will be a mechanism that will consider the environmental benefits of the project.

Colombian Electricity Regulatory Framework

1. Industry Overview and Structure

The Colombian Wholesale Electricity Market (“MEM” in its Spanish acronym) is based on a competitive market model and operates under open access principles. For its effective operation, the Colombian MEM relies on a central agency, XM, which oversees the market’s central dispatch through the National Dispatch Center (“CND”) and the management of the commercial exchange system through the Commercial Exchange System Authority.

There are two categories of participants, generators and traders, who are allowed to buy and sell electricity and related products in the MEM. All the electricity supply offered by generation companies connected to the Colombian NIS and all of the electricity requirements of end-customers, whose demand is represented by trading companies, are traded on the MEM. There are also several isolated regional and smaller systems that provide electricity to specific areas.

The following chart shows the relationships among the various participants in the Colombian MEM:

Generation

Generation activity consists of electricity production through hydroelectric, thermoelectric, and renewable energy plants connected to the Colombian NIS. Generators sell electricity on the spot market or through private contracts with large customers, other generators, traders, and distributors. Generators with capacities of at least 20 MW are required to participate in the MEM by connecting all their generation plants or units to the Colombian NIS. Plants with an installed capacity of less than 20 MW are called “minor plants” or “not centrally dispatched plants,” and they are dispatched as a first priority. Generators declare their energy availability and sale price, with the CND centralizing the dispatch of this electricity.

Transmission

The transmission system operates under monopoly conditions with a guaranteed annual fixed income determined by the new replacement value of the networks and equipment and the resulting value of bidding processes awarding new

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projects to expand the Colombian NIS. This value is allocated among the participants of the Colombian NIS in proportion to their energy demand.

Distribution

Distributors (or network operators) operate under monopoly conditions and are responsible for planning, investing, operating, and maintaining electricity networks under 220 kV. These include regional transmission systems and local distribution systems. Any customer may access the distribution network by paying a connection fee. Under this scheme, the distributor is responsible for operating the distribution network, including the transportation and control of energy losses.

Concessions

The Colombian government is not legally allowed to participate in the execution and exploitation of generation projects unless no agent is prepared to undertake these activities under comparable conditions.

To operate or initiate projects, whether thermal, hydro, solar, or wind, agents must obtain all applicable concessions, environmental, sanitation, water rights, and other municipal permits and licenses from the competent authorities. All economic agents may build generation plants and their respective connection lines to the interconnection and transmission networks. Concessions are awarded for up to 30 years for all activities and may be renewed for up to 20 years.

Trading

Trading consists of intermediation between generation, transmission, and distribution services to customers, whether or not that activity is carried out together with other electricity sector activities. Parties freely agree on trading prices for unregulated customers. Electricity transactions in the MEM are carried out under (i) energy spot market: short-term daily market; (ii) bilateral contracts: medium- and long-term markets; and (iii) “Firm Energy.”

“Firm Energy” refers to the maximum electric energy that a generation plant can deliver continually during a year with poor hydrological conditions. The generator that acquires a Firm Energy commitment (“OEF” in its Spanish acronym) receives a fixed remuneration during the commitment period.

Limits on Integration and Concentration

Market share for generators and traders is capped at certain maximum levels. The Colombian Commission for the Regulation of Energy and Gas (“CREG” in its Spanish acronym) uses Firm Energy as its principal metric to regulate the market share each market participant holds. The limit for generators is 25% of the Colombian system’s Firm Energy. Additionally, if a generation company’s share of Colombia’s total Firm Energy ranges from 25% to 30%, such company becomes subject to monitoring by the Superintendence of Domestic Public Services. If an electricity generation company’s share of Colombia’s total Firm Energy exceeds 30%, such company may be required to sell its share exceeding the 25% threshold.

Similarly, a trader may not account for more than 25% of the Colombian NIS trading activity. Limitations for traders take into account international energy sales. Market share is calculated monthly according to the trader’s commercial demand, and traders have up to six months to reduce their market share when the limit is exceeded.

Such limits apply to economic groups, including companies controlled by, or under common control with, other companies. Also, generators may not own more than a 25% interest in a distributor, or vice versa. However, this limitation only applies to individual companies and does not preclude cross-ownership by companies within the same corporate group. A distribution company can hold more than 25% of an integrated company’s equity if the latter company’s market share accounts for less than 2% of the national generation business.

A generator, distributor, trader, or an integrated company (i.e., a firm combining generation, transmission, and distribution activities) cannot own more than 15% of the equity in a transmission company if the latter represents more than 2% of the national transmission business in terms of revenues.

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Electricity Market

The MEM is divided into regulated and unregulated customers. Customers in the regulated market are industrial, commercial, governmental, and residential customers that have regulated tariffs that can be supplied by any distributor or trader in the market. Large customers in the unregulated market may enter freely and directly into electricity supply contracts in the MEM with a generator or a distributor, acting as traders, or with a pure trader. Unregulated customers are required to have a six-month average monthly power demand of at least 0.1 MW or a minimum of 55 MWh monthly average electricity demand over the prior six months.

2. Electricity Sector Laws

In 1994, Law No. 143 (“Colombian Electricity Act”), the basic legal framework that regulates the Colombian electricity sector, was enacted. It granted access to private sector participants, segregated the electricity sector into generation, transmission, distribution, and trading activities, created an open and competitive wholesale electricity market, established transmission and distribution activities as regulated monopolies, and adopted universal open access principles applicable to transmission and distribution networks. Under the Colombian Electricity Act, any company existing before 1994, domestic or foreign, may undertake any activity in the electricity sector. Companies established after such date could engage exclusively in only one of such activities. Trading could be combined with either generation or distribution. In 2019, Law No. 2,055 (“National Plan Act”) was enacted to establish rules similar to those under the Colombian Electricity Act with regard to the rights of association between electrical activities. As a result, under the National Plan Act companies created after 1994 can integrate activities, with regard to the prohibitions established by the Colombian Electricity Act.

The development and regulation of a framework that encourages the incorporation of renewable energy in the Colombian national energy grid started in 2014 with Law No. 1,715 and its accompanying regulations, including a national fund that fosters research on related topics and defines the methodology for self-generation. It also establishes incentives on taxes and import tariffs for investors. Decree 2,143 of 2015 detailed guidelines for implementing these incentives. Several regulations related to renewable energy have since been published.

3. Principal Regulatory Authorities

Responsible for Setting Policy

The Colombian Ministry of Mines and Energy is responsible for electricity sector policy, promoting the efficient use of the mining and energy resources available in Colombia and contributing to the country’s social and economic development. The Colombian Energy and Mining Planning Unit (“UPME” in its Spanish acronym) is responsible for planning the expansion of the generation and transmission networks.

Responsible for Regulation

CREG implements the industry principles set out by the Colombian Electricity Act. It is empowered to issue regulations that govern technical and commercial operations and sets tariffs for regulated activities.

The National Operations Council is responsible for establishing technical standards to facilitate efficient integration and operation in the NIS. It is a consultative entity composed of the CND’s Director and generation, transmission, and distribution company representatives.

The Commercialization Advisory Committee is an advisory body that assists CREG with the MEM’s commercial aspects.

System Operator

XM operates the NIS and manages the MEM, performing the functions of the CND, the Administrator of the Commercial Exchange System (“Administrador del Sistema de Intercambios Comerciales”), and the Accounts Administrator (“Liquidador y Administrador de Cuentas”). Additionally, XM manages short-term electricity transactions with Ecuador.

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The CND receives price bids each day from all generators participating in the MEM. These bids indicate prices and the available capacity per hour for the following day. Based on this information, the CND, guided by an “optimal dispatch” principle, which assumes an infinite transmission capacity through the network, ranks the dispatch optimized during the 24-hour period, taking into consideration initial operating conditions, and determining which generators will be dispatched the following day to satisfy expected demand. The price for all generators is set as the most expensive generator dispatched during each hourly period under optimal dispatch. This price-ranking system is intended to ensure that national demand, increased by the total amount of energy exported to other countries, will be satisfied at the lowest cost combination of available generating units in the country.

Responsible for Supervision

The Superintendence of Domestic Public Services is responsible for the oversight of all public utility service companies. The Superintendence monitors the efficiency of all utility companies and the quality of services and can assume control over utility companies when the availability of utility services or such companies’ viability is at risk. Other duties include enforcing regulations, imposing penalties, generally overseeing public utility companies’ financial and administrative performance, providing accounting norms and rules for public service companies, and, in general, organizing information networks and databases of public utilities.

4. Remuneration and Tariffs

Remuneration for Generators

The energy surpluses that have not been committed under contracts are traded in the MEM. For this, an hourly spot price for all dispatched units is established in the wholesale market based on the offer price of the highest-priced energy dispatched unit for that period.

In the unregulated market, generation companies and unregulated customers sign contracts at freely negotiated prices and conditions. Typically, these agreements establish that the customer pays for the energy they consume each month without a minimum or maximum. The prices are fixed in Colombian pesos and indexed monthly to the Colombian PPI.

In the regulated market, traders are required to buy energy through procedures that ensure free-market competition. Traders evaluate bids based on prices, technical conditions, and commercial objectives. As a result, traders enter into agreements in which they negotiate different terms. Prices are denominated in Colombian pesos and are indexed monthly to the Colombian CPI. Generators can also sell their energy to other generators at freely negotiated prices and conditions.

Generators connected to the NIS can also receive “reliability payments,” by auctions or managed energy allocations, which are a function of the OEF provided to the system. An OEF is a commitment by generation companies, backed by their physical resources, to produce firm energy during scarcity periods. A generator that acquires an OEF will receive fixed compensation during the commitment period, whether or not the fulfillment of its obligation is required. For a generator to receive reliability payments, it must participate in firm energy bids by declaring and certifying such firm energy.

Distribution Tariffs

CREG regulates distribution prices that allow distribution companies to recover costs, including operating, maintenance, and capital costs under efficient operations. CREG also sets distribution charges for each company based on the Regulatory Asset Base (RAB) of the distribution assets, the investment plan, the cost of capital, and an incentive scheme for losses, quality incentives, and operational and maintenance costs that depend on the voltage level.

Tariffs to End Customers

Traders are responsible for charging a tariff to end customers and transferring their payments to the industry’s agents. The trading tariffs are under the “regulated freedom regime,” applied to regulated customers are calculated according to a formula established by CREG for the trading activity, thereby mitigating spot price volatility and providing an efficiency signal to the market. Traders transfer costs from transmission, distribution, trading, and losses to

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the regulated market. Since CREG approves limits on costs, traders in the regulated market may set lower tariffs for economic reasons that must be applied to all customers. Conversely, parties freely agree on trading prices for unregulated customers.

5. Environmental Regulations

Any entity planning to develop projects or activities related to generation, interconnection, transmission, or distribution of electricity that may result in environmental deterioration must first obtain environmental permits and licenses and establish environmental management plans, as established in Decree 1,076 of 2015. Depending on the project’s nature, licenses are conferred by the National Authority of Environmental Licenses, Regional Autonomous Corporations, municipalities, districts, and metropolitan areas whose urban population exceeds one million inhabitants. For the licensing processes, environmental alternative diagnosis studies and environmental impact studies must be submitted to the relevant environmental authority according to the authorities’ terms of reference. These studies are subject to the issuance of technical concepts by competent environmental authorities.

Additionally, any project that requires an environmental license and involves water taken directly from natural sources for any activity must allocate not less than 1% of the total investment for the recovery, conservation, preservation, and monitoring of the watershed that feeds the respective water source.

All hydroelectric generation plants with an installed capacity of more than 10 MW in their operation stage are required to contribute to the environment’s conservation. These resources are called “transfers” and consist of payment from each plant of 6% of its annual production at a rate established by CREG. Half of each payment is allocated to the municipalities where the project is located. The other half to the Regional Autonomous Corporation to fund hydro basin recovery plans and páramo ecosystems from which water comes. In thermal generation, “transfers” represent 4% of their annual production, of which 1.5% is allocated to municipalities where the project is located and 2.5% to the Regional Autonomous Corporation to protect the plant’s environment. The energy produced by renewable sources referred to in Law 1,955 of 2019, whose plants with a total installed capacity exceeding 10,000 kW, must transfer the equivalent of 4% of their electricity generation’s gross energy sales, following the rate for block sales indicated by the Energy and Gas Regulatory Commission.

6. Other Regulations and Measures

Covid-19 Pandemic Regulatory Issues - Energy and Gas Sector

Due to the Covid-19 pandemic, the government of Colombia established a special line of credit for energy companies from April 2020 to December 2020. As of May 2020, the Colombian MME established a mechanism of voluntary contribution, called “Comparto Mi Energía”, aimed at level 4, 5, and 6 customers and commercial and industrial customers. The companies collecting the resources use them to cover the unsubsidized consumption of level 1 and 2 residential customers. In April 2020, the Colombian government created a deferred payment plan for energy bills from April 2020 to July 2020, declaring that level 1 and 2 residential customers, representing approximately 44% of the customer base, could defer the payment of energy bills for up to 36 months, and level 3 and 4 residential customers, representing approximately 40% of the customer base, could defer payment of energy bills for 24 months, without penalty or risk of a cut in service.

Renewable Energy

The development and regulation of a framework that encourages the incorporation of renewable energy in the Colombian national energy grid started in 2014 with Law No. 1,715 (the “Renewable Energy Law”) and its accompanying regulations, including incentives on taxes and import tariffs for investors. Decree 2,143 of 2015 detailed guidelines for implementing these incentives.

In 2018, Decree 570 established public policy guidelines for the long-term contracting of generation projects, with the primary purpose of focusing on the following aspects:

● the need to supply domestic demand;

● the aim for efficient, safe, and reliable operation in sector activities;

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● the incorporation of advances in science and technology;

● the diversification of the Colombian electric power generation mix due to the high degree of concentration of hydroelectric generation;

● the support for the compliance with Colombia’s commitments regarding the reduction of greenhouse gas emissions by 20% concerning the projected emissions for the year 2030 in the business-as-usual scenario; and

● the complementary relationship between renewable energy resources and conventional hydroelectric resources, especially during seasonal periods of low hydrology.

In 2021, Law No. 2,099 (the “Energy Transition Law”) modified the Renewable Energy Law by establishing a new regulatory framework for power generation from non-conventional renewable sources (“NCRS”), as well as legally establishing green hydrogen and blue hydrogen as NCRS. The Energy Transition Law also maintains and extends previously existing tax incentives projects for power generation from NCRS and creates a new set of regulations for geothermic projects.

Energy Efficiency

Since 2001, Law No. 697 has promoted energy efficiency in Colombia. The law has been the framework for efficiency programs, including the program for rational and efficient energy use. In May 2014, the Renewable Energy Law established a general legal framework and created a fund intended to promote the development of renewable energy, energy efficiency, and programs designed to reduce electricity demand. One of its main objectives is the progressive replacement of diesel generation in non-interconnected and isolated areas to reduce energy costs and greenhouse gas emissions. This law also gives tax incentives for electric mobility and smart metering.

Peruvian Electricity Regulatory Framework

1. Industry Overview and Structure

In the Peruvian Wholesale Electricity Market (“MME” in its Spanish acronym) there are three categories of participants: generators, distributors and major unregulated customers.

The Peruvian National Interconnected Electric System (“SEIN”) is the only interconnected system in Peru, though several smaller isolated systems provide electricity to specific areas.

The following chart shows the relationships among the various participants in the SEIN:

Generation

The generation segment is comprised of companies that own electricity generation power plants. This segment is a competitive market in which prices reflect the marginal cost of production. Electricity generators may enter into

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contracts to sell their capacity and electricity to distributors and unregulated customers or may participate in tender offers to sell their electricity to distributors. Generators can buy deficits or transfer surpluses between contracted energy and actual production in the spot market at the spot price.

Generation companies that own or operate hydroelectric or renewable source power plants with an installed capacity of more than 500 kW require a concession granted by the Peruvian Ministry of Energy and Mines (“MINEM” in its Spanish acronym). A concession for electricity generation activity is a unilateral permit granted to the generator for an unlimited period, while generation concessions obtained in tender processes are restricted to a 30-year term. On the other hand, to operate a thermoelectric power plant an indefinite authorization issued by the MINEM is required.

Transmission

The transmission system comprises transmission lines and substations with a voltage higher than 60 kV, and equipment to transmit electricity from power plants to consumption centers or distribution points. Transmission companies require a concession if the facilities affect State-owned assets or require an easement granted by the State.

Transmission assets were initially divided into two categories; “principal system,” which are for common use and allow the flow of electricity through the national grid, and “secondary system,” which connect a power plant to the national grid or directly to certain end customers. Law No. 28,832 later defined “guaranteed transmission system” and “complementary transmission systems” as applicable to projects commissioned after the law was enacted. Guaranteed system lines are the result of a public bid. Complementary system lines are freely constructed and exploited as private projects and must be presented to and approved by the Energy and Mining Investment Supervisory Authority (“OSINERGMIN” in its Spanish acronym). Principal and guaranteed system lines are open to all generators and allow electricity to be delivered to all customers. These concessionaires receive an annual fixed income, payable through a variable tariff revenue and connection tolls per kW. The secondary and complementary system lines are open to all generators but serve only specific customers who must pay for using the system.

Distribution

Electricity distribution is carried out by distribution companies in concession areas demanding more than 500 kW. Distributors buy energy through tender processes that are regulated by Law No. 28,832 or directly from generators under freely negotiated terms subject to a price cap called “Tarifa en Barra” referred to in Article 47 of the Law 25,844 and settled every May by OSINERGMIN. Distributors sell electricity mainly to regulated residential customers at fixed prices and to unregulated customers through contracts at negotiated prices.

Customers

Customers are divided into regulated and unregulated segments. Regulated customers are those who demand less than 200 kW of capacity. The following criteria apply:

(i) Customers with a capacity demand between 200-2,500 kW may choose to be regulated or unregulated customers.

(ii) Once customers choose a segment, they cannot change segments for at least three years. If customers want to change from regulated to unregulated, or vice versa, they must give advance notice of at least one year.

(iii) Customers with a capacity demand of more than 2,500 kW are mandatory unregulated customers.

Major unregulated customers have a contract for at least 10 MW, or they may also be comprised of a group of unregulated customers with a demand of at least 10 MW.

Limits on Integration and Concentration

The Electricity Concession Law establishes that generation, transmission, and distribution activities cannot be carried out by the same concessionaire or by any of its controlling entities except in cases permitted by law (art. 122°).

Furthermore, on January 6, 2021, Law No. 31,112 was enacted, which establishes and regulates the procedures for business concentration transactions, which are subject to authorization by the antitrust authority (Instituto Nacional de Defensa de la Competencia y de la Protección de la Propiedad Intelectual, “INDECOPI” in its Spanish acronym).

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Electricity Markets

In the Peruvian MME, generators sell electricity in the short-term market, also known as the spot market, to three types of participants: (1) generators meeting their supply contracts; (2) distributors serving their unregulated customers for up to 10% of the maximum demand; (3) major unregulated customers purchasing up to 10% of their maximum demand.

In the spot market, electricity is sold at the marginal cost that is calculated every half hour based on each power plant’s variable production cost. Since July 2021, new regulations require electricity costs from natural gas power plants to be determined at their audited costs.

2. Electricity Sector Laws

Law No. 25,844 of 1992, known as the Electricity Concessions Law, its regulations, amendments, and complimentary norms divided the Peruvian electricity sector into generation, transmission, and distribution segments, and established general provisions for operating the system.

Law No. 28,832 of 2006 established guidelines for the tender offer process for energy, participation in the spot market, functions and corporate governance of the Committee of Economic Operation of the Peruvian System (“COES” in its Spanish acronym), and adjusted the legal framework of the transmission segment.

Legislative Decree No. 1,002 of 2008, promotes renewable energy generation through auctions for biomass, wind, solar, geothermal, tidal, and hydroelectric power plants with an installed capacity lower than 20 MW with a guaranteed income mechanism paid by demand through a tariff charge in the connection toll. The decree establishes the goal that up to 5% of national demand must be satisfied by electricity generated from renewable energy sources. The goal is set every five years and has remained unchanged since 2008. It also gives renewable energy generators priority electricity dispatch and access to transmission and distribution networks.

Legislative Decree 1,221 of 2015 improves electricity distribution regulation to encourage access to electricity in Peru. It establishes the following main modifications: (i) VAD and internal rate of return (IRR) calculations are defined for each distribution company with more than 50,000 customers; (ii) MINEM defines a technical responsibility area for each distributor, with the possibility to extend their concession areas to nearby rural areas; and (iii) distributors must guarantee their regulated demand for 24 months.

3. Principal Regulatory Authorities

Responsible for Setting Policy

MINEM defines national energy policies, regulates environmental matters applicable to the energy sector, and oversees the granting, supervision, maturity, and termination of licenses, authorizations, and concessions for generation, transmission, and distribution activities.

Responsible for Regulations

The General Electricity Office (“Dirección General de Electricidad”) is the technical regulatory entity responsible for regulating the electricity sector. It proposes necessary regulations for the development of electricity generation, transmission, and distribution activities.

Supervisory Body

OSINERGMIN, an autonomous public regulatory entity, controls and enforces compliance with (i) legal and technical regulations related to electrical, hydrocarbon, and mining activities; and (ii) the obligations stated in the concession contracts. OSINERGMIN’s Tariff Regulatory Bureau has the authority to publish regulated tariffs. It also supervises the tender or bidding processes required by distribution companies to purchase energy from generators.

System Operator

COES is a private non-profit entity responsible for coordinating the operation of generation units to satisfy demand at the minimum cost and with a focus on safety. COES also plans the development of the transmission segment and manages the spot market.

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COES annually determines a firm capacity for each power plant. Firm capacity is the highest capacity that a generator may supply to the system at certain peak hours, considering statistical information and accounting for time out of service for maintenance purposes and hydrological conditions.

4. Remuneration and Tariffs

Remuneration for Generators

COES controls the coordination of electricity dispatch operations and the control and management of economic transactions that take place in the SEIN. Generators can sell energy to unregulated customers at the spot price; to unregulated customers at mutually agreed prices and conditions; to distributors at prices determined in tenders or at a contracted price in bilateral contracts (with a price cap – “Tarifa en barra”); and to other generators based on firm capacity limits. Depending on the relationship between firm capacity and the company’s contractual requirements, the generation company may be required to purchase or sell capacity in the spot market.

Distribution Tariffs

The maximum tariff for regulated customers consists of three variables: (i) the purchase price of electricity (generation cost); (ii) transmission costs; and (iii) the VAD. OSINERGMIN determines the VAD for each distributor every four years. It includes costs passed on to the users, energy distribution losses, a rate of return on their network investments, and operations and maintenance charges. Technology innovation and service quality projects require OSINERGMIN’s approval and are included as an extra charge.

Supreme Decree No. 028-2021-EM amends Supreme Decree No. 018-2016-EM regarding the recognition of investment and operations and maintenance (O&M) expenses related to smart meters.

The rate of return on investment for a distribution company depends on its performance relative to the standards chosen by OSINERGMIN for a theoretical model company. The tariff system allows for a greater return for distribution companies that are more efficient than the model company. Distribution companies perform tariff studies, and OSINERGMIN tests preliminary tariffs to ensure that they provide an average annual IRR between 8%-16% on the replacement cost of electricity-related distribution assets.

5. Environmental Regulations

The environmental legal framework applicable to energy-related activities in Peru is established, among others, in Environmental Law No. 28,611 and the Regulation for Environmental Protection regarding Electricity Activities, Supreme Decree 014-2019-EM.

MINEM dictates specific environmental legal dispositions applicable to electricity activities. According to the Environmental Law, the Peruvian Ministry of Environment has as its principal duties: (i) to design the general environmental policies applicable to every productive activity; and (ii) to establish the main guidelines of the different government authorities for their specific environmental sector regulations. Currently, the Environmental Assessment and Inspection Agency (“OEFA”, in its Spanish acronym) is responsible for the supervisory functions regarding the application and implementation of the Environmental Law’s dispositions.

6. Other Regulations and Measures

Covid-19 Pandemic Regulations

Due to the Covid-19 pandemic, the Peruvian government declared a national state of emergency on March 15, 2020, which remains in effect as of the date of this Report. At the start of the state of emergency, electric utility companies were allowed to suspend readings of meters and bill customers based on their average consumption over the prior six months. Distribution companies were allowed to suspend attention on customer service centers and the delivery of paper bills, although companies were authorized to distribute bills by digital means. The government also implemented a one-time subsidy (“Bono Electricidad”) of up to 160 soles for low-income residential consumers with a consumption of up to 125 kWh/month (some exclusions applied) that was directly applied to consumers’ electricity bills.

During 2021, the government did not implement any new regulations or measures with respect to Covid-19 regarding the electricity sector.

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Incentives

Law No. 28,832 and Supreme Decree No. 052-2007-EM (“General Regulations of the Supply Auctions”) state that if auctions are called for more than three years in advance, distributors will receive incentive payments that will be added to the generator’s auction price and then passed on to customers. These payments cannot be more than 3% of the energy price obtained during the tender process.

Central America Electricity Regulatory Framework

1. Industry Overview and Structure

The electricity sectors in Costa Rica, Guatemala, and Panama (collectively, “Central America”) are composed of a National Interconnected System (“NIS”) and some isolated systems containing generators, transmitters, and distributors. Government regulations in Central America separate electricity activities, requiring the generation, transmission, and distribution of electricity to be carried out by different companies. Each NIS is subject to governmental laws and regulations.

Additionally, in 1996 six countries (Costa Rica, El Salvador, Guatemala, Honduras, Nicaragua, and Panama) signed a treaty to establish the Regional Electricity Market (“MER” in its Spanish acronym). The MER acts as a seventh market, integrating existing national markets with regional regulation in which authorized agents carry out international electricity transactions in the six-country region.

Generation

In Central America, we participate in the electricity sector through generation activities using hydroelectric and solar power plants.

In Guatemala and Panama, the generation activity operates under free-market conditions, where generators can sell energy in the spot market or directly to distributors and large customers at freely negotiated contractual prices. The spot market settles the differences between contractual provisions and the actual generation of each plant.

In Costa Rica, only rural electrification cooperatives and municipal companies can sell the energy they generate directly to customers in their concession area. Privately owned power plants are limited to a maximum installed capacity of 50 MW and can sell their energy only through the public tender system or to ICE, a State-owned company and the largest generator in the country. Private generators that sell power to ICE do not pay to use the transmission grid; however, they must assume the cost and construction of the interconnection line from their plant to the assigned interconnection point, which can be a distribution center or a substation.

Customers

In Guatemala and Panama, customers requiring more than 100 kW are classified as large customers and can freely negotiate prices and conditions of supply with any generation company. Large customers may also purchase energy in the spot market.

In Costa Rica, customers are classified into the following categories: residential, general trade, industrial, preferential of a social nature, medium voltage, and large. Each category is subject to an applicable tariff. Customers contractually purchase energy from a distribution company based on the type of service required and its corresponding tariff. Distribution companies may have different rates.

Concessions

Operating a generation power plant in Central America requires compliance with regulations and authorization from the relevant government authority in each country.

In Costa Rica, generators must obtain a concession from either the Regulatory Authority for Public Services (“ARESEP” in its Spanish acronym), for the sale of electricity to ICE, or the Ministry of Environment and Energy (“MINAE” in its Spanish acronym), for the sale of electricity to all other entities.

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In Guatemala, a concession is required for generation power plants located on public lands that have an installed capacity greater than 5 MW. Generators with an installed capacity under 5 MW are only required to report connectivity to the distributor and the regulator.

In Panama, hydroelectric generators require a concession while wind, solar, and thermal generators must obtain a generation license. Both authorizations must be obtained from the National Public Services Authority (“ASEP” in its Spanish acronym).

2. Electricity Sector Laws

The electricity sectors in Central America are governed by State laws, decrees, and regulations. They establish regulatory authorities and underlying principles, coordinate the operation of the NIS, promote the use of renewable resources for energy generation, as well as market terms and conditions that must be met for the purchase and sale of electricity, among others.

In Costa Rica, Law No. 449 of 1949 created ICE, requiring it to meet the national demand for electricity. Law No. 7,593 classifies the generation, transmission, distribution, and commercialization of electricity as public services. Laws Nos. 7,200 and 7,508 established the participation of private entities other than cooperatives in the generation of electricity.

In Guatemala, the General Electricity Act of 1996 (Ley General de Electricidad) established a legal and regulatory framework to privatize the sector and separate the generation, transmission, and distribution of electricity, requiring each activity to be carried out by different companies.

In Panama, Law No. 6 of 1997 and its amendments create the basic framework for the electricity sector. It establishes the regime under which the generation, transmission, distribution, and commercialization of electricity are classified as public services. It also establishes economic regulations and normative and coordination activities for the expansion and integrated operation of the NIS.

3. Principal Regulatory Authorities

Responsible for Setting Policies

In Costa Rica, the Minister of Environment is in charge of planning the energy subsector, relying on the Secretariat of Subsectoral Energy Planning (“Secretaría de Planificación del Subsector Energía”), which is responsible for coordinating the planning, communication, monitoring, and evaluation of sectoral policies.

In Guatemala, the Ministry of Energy and Mines (“MEM” in its Spanish acronym) is responsible for formulating and coordinating policies, national planning, establishing programs relating to the electricity subsector, and applying electricity laws and regulations.

In Panama, the National Secretariat of Energy (“Secretaría Nacional de Energía”) defines energy policy to guarantee the competitive, sufficient, economically viable, and environmentally sustainable supply of energy resources. It oversees the planning, investigation, direction, supervision, operation, and control of global policies, and defines the operational strategies of the sector.

In the MER, the Director Council of the Regional Electricity Market (“Consejo Director del MER”) is the political body responsible for developing the MER, ensuring compliance with treaty regulations, and coordinating with other regional bodies.

Responsible for Regulation

In Costa Rica, ARESEP is responsible for regulating and supervising the quality and price related to the generation, transmission, distribution, and trading of public electricity services.

In Guatemala, the National Electric Energy Commission (“Comisión Nacional de Energía Eléctrica”) is the technical body of the MEM that regulates the system. It enforces electricity laws and imposes sanctions, ensures compliance with awardees and concessionaires, protects users, prevents conduct that violates free competition, defines rates subject to regulation, settles disputes, and issues technical standards, among others.

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In Panama, the National Agency of Public Services (“Autoridad Nacional de los Servicios Públicos”) is an autonomous body that controls, regulates, orders, and supervises the provision of public services. In the electricity sector, it is responsible for the approval of distribution and transmission tariffs, allocation of concessions and generation licenses, expansion plans of the national electricity system, tenders, and award of contracts for the supply of customers of distribution companies.

In the MER, the Regional Electric Interconnection Commission (“Comisión Regional de Interconexión Eléctrica”) acts as the system regulator. It is responsible for setting tariffs and regulating commercial relations between public and private institutions that connect to the system.

System Operator

In Costa Rica, the National Energy Control Center (“Centro Nacional de Control de Energía”) is in charge of the dispatch of generation to satisfy national demand. It is responsible for, in coordination with ICE, establishing and maintaining an information system that integrates operating data on daily pre-dispatch, availability, maintenance programs, demand, failure regime, and safety of the national generation park.

In Guatemala, the Wholesale Market Administrator (“AMM” in its Spanish acronym) is a private non-profit company that operates the NIS and wholesale market by maintaining continuity and security in the country’s electricity supply. It ensures demand coverage and oversees the expansion of the generation, transmission, and distribution of the national grid.

In Panama, the National Dispatch Center (“Centro Nacional de Despacho”) is a non-profit agency that coordinates the operations and national and regional commercial transactions that occur between participants in the wholesale market. It focuses on ensuring an integrated, safe, reliable, and economical operation of the NIS and providing a timely and correct commercial administration service to market participants.

In the MER, the Regional Market and System Operator (“Ente Operador Regional”) is responsible for the dispatch and exchanges of energy between treaty countries.

4. Remunerations and Tariffs

Remuneration for Generators

In Costa Rica, ICE carries out contract negotiations with private generators for the purchase and sale of energy. Given the State scheme of ICE as the only buyer of electricity in Costa Rica, there are no concepts such as the spot market or free customers for public or private generators in Costa Rica. The rates paid to generators are set annually by ARESEP based on the principle of service at cost, which only considers the costs necessary to provide the service that promotes competitive remuneration and guarantees adequate generation to satisfy demand.

In Guatemala and Panama, the system operator oversees spot prices for energy transfers between participants in the wholesale market. Spot prices are set according to the variable generation rates to cover all associated costs, such as fuel and operation and maintenance.

In the MER, commercial transactions are carried out through opportunity exchanges resulting from regional economic dispatch and through contracts between market agents. The remuneration depends on the type of transaction and contract.

5. Environmental Regulations

Each government in Central America establishes the basic principles and standards for the protection and conservation of the environment, the promotion of sustainable use of natural resources, and the integration of social and economic objectives to achieve the sustainable human development of its citizens. Projects in the energy sector are subject to and must comply with environmental standards and regulations established by different government bodies. Failure to comply with legal requirements empowers the governments to impose sanctions such as fines and the suspension of operations that, in the case of public services, could lead to the cessation of concessions.

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C.  Organizational Structure.

Principal Subsidiaries and Affiliates

We are part of an electricity group controlled by Enel S.p.A., an Italian company and our controlling shareholder that beneficially owned 82.3% of our shares as of December 31, 2021. Enel is a multinational power company and a leading integrated player in the global power and renewables markets. It is one of the largest European utility companies with operations in over 30 countries worldwide, and a consolidated installed capacity of approximately 90 GW. Enel distributes electricity through a network of over 2.2 million kilometers to 75 million end users. It is one of the world’s largest network operators and has one of the most extensive customer bases. Enel’s shares are listed on Euronext Milan organized and managed by Borsa Italiana S.p.A.

Enel Américas Simplified Organizational Structure⁽¹⁾

As of the date of this Report

(1) Only principal operating subsidiaries are presented here. The percentage listed in the box for each of Enel Américas’ consolidated subsidiaries represents our economic interest in such subsidiary. Please refer to “Presentation of Information” for an explanation of the calculation of economic interest.

(2) In November 2021, EGP Brasil was merged into Enel Brasil. The Brazilian subsidiaries holding the NCRE generation assets in Brazil formerly held by EGP Brasil are now subsidiaries of Enel Brasil.

(3) In March 2022, Codensa, EGP Colombia, and ESSA2 merged into Emgesa. The new corporate name of the merged companies is Enel Colombia. As a result of the merger, Enel Colombia conducts the generation and distribution activities of Emgesa and Codensa, respectively.

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We consolidated the companies listed in the following tables as of December 31, 2021. In the case of subsidiaries, our economic interest is calculated by multiplying our percentage economic interest in a directly held subsidiary by the percentage economic interest of any entity in the chain of ownership of such ultimate subsidiary.

Principal Subsidiaries and Country of Operations	% Economic Ownership of Enel Américas	Consolidated Assets of Each Main Subsidiary	Revenues and Other Operating Income of Each Main Subsidiary
	(in %)	(in millions of US$)	(in millions of US$)
Electricity Generation, Transmission, and Distribution
Electricity Generation
Costanera (Argentina)	75.6	312	105
Dock Sud (Argentina)	41.3	301	80
Enel Generation El Chocón (Argentina)	65.7	318	42
Cachoeira Dourada (Brazil)	99.8	376	1,429
Brazil NCRE Subsidiaries (Brazil)(1)(2)	100.0	3,975	540
EGP Volta Grande (Brazil)	100.0	303	81
Fortaleza (Brazil)	100.0	226	327
Emgesa (Colombia)	48.5	2,225	1,262
EGP Colombia	100.0	410	30
EGP Costa Rica (Costa Rica)(1)	100.0	359	17
EGP Guatemala (Guatemala)(1)	100.0	635	108
EGP Panama (Panama)(1)	100.0	1,062	149
Chinango (Peru)	66.9	143	47
EGP Peru (Peru)(1)	100.0	510	33
Enel Generation Peru (Peru)	83.6	1,030	431
Enel Generation Piura (Peru)	96.5	191	74
Electricity Transmission
Cien (Brazil)	100.0	153	55
Electricity Distribution
Edesur (Argentina)	72.1	2,159	794
Enel Distribution Ceara (Brazil)	74.1	2,107	1,512
Enel Distribution Goias (Brazil)	99.9	3,484	1,820
Enel Distribution Rio (Brazil)	99.7	2,986	1,581
Enel Distribution Sao Paulo (Brazil)	100.0	6,675	3,849
Codensa (Colombia)	48.3	2,285	1,707
Enel Distribution Peru (Peru)	83.2	1,446	895

(1) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A by means of a merger. Prior to the merger, EGP Américas S.p.A., held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

(2) In November 2021, EGP Brasil was merged into Enel Brasil.

D. Property, Plant, and Equipment.

Our property, plant, and equipment is concentrated in electricity generation, distribution, and transmission assets in the four countries in which we operate.

Property, Plant, and Equipment of Generating Companies

We conduct our generation business through our generation subsidiaries Costanera, El Chocón, and Dock Sud in Argentina; Cachoeira Dourada, EGP Volta Grande, Enel Brasil, and Fortaleza in Brazil; Emgesa and EGP Colombia in Colombia; Enel Generation Piura, Enel Generation Peru, its subsidiary Chinango, and EGP Peru in Peru; and EGP Costa Rica, Guatemala, and Panama in Central America. As of December 31, 2021, through these subsidiaries, we own 87 power plants in Latin America, with a consolidated net installed capacity of 15,926 MW.

The following table identifies the power plants that we own, at the end of each year, organized by country and technology.

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			Installed Capacity(1) As of December 31,
Country/Company	Power Plant Name	Power Plant Type(2)	2021	2020	2019
			(in MW)
Argentina
Costanera
	Costanera Steam Turbine	Steam Turbine/Natural Gas+Fuel Oil	1,062	1,062	1,062
	Costanera Combined Cycle II	Combined Cycle/Natural Gas+Diesel Oil	851	851	851
	Buenos Aires Combined Cycle I	Combined Cycle/Natural Gas	297	297	297
	Total Costanera		2,210	2,210	2,210
El Chocón
	Chocón	Reservoir	1,200	1,200	1,200
	Arroyito	Run-of-the-river	128	128	128
	El Chocón DE	Diesel Engines (Diesel Oil + Fuel Oil)	34	34	34
	Total El Chocón		1,362	1,362	1,362
Dock Sud
	Dock Sud CC	Combined Cycle/Natural Gas+Diesel Oil	775	775	775
	Dock Sud GT	Gas Turbine/Natural Gas+Diesel Oil	72	72	72
	Total Dock Sud		847	847	847
Total Capacity in Argentina			4,419	4,419	4,419
Brazil
Cachoeira Dourada	Cachoeira Dourada	Run-of-the-river	655	655	655
	Total Cachoeira Dourada		655	655	655
EGP Volta Grande
	Volta Grande	Run-of-the-river	380	380	380
	Total EGP Volta Grande		380	380	380
Fortaleza
	Fortaleza	Combined Cycle/Gas	319	319	319
	Total Fortaleza		319	319	319
Brazil NCRE Subsidiaries(3)(4)
	Various	Wind	2,156	—	—
	Various	Solar	1,233	—	—
	Various	Run-of-the-river and Reservoir	235	—	—
	Total Enel Brasil		3,624	—	—
Total Capacity in Brazil			4,978	1,354	1,354
Colombia
Emgesa
	Guavio	Reservoir	1,260	1,260	1,260
	Betania	Reservoir	540	540	540
	Quimbo	Reservoir	400	400	400
	La Guaca	Run-of-the-river	324	324	324
	Paraíso	Reservoir	276	276	276
	Termozipa	Steam Turbine/Coal	226	225	225
	Cartagena	Steam Turbine/ Natural Gas	180	184	184
	Dario Valencia	Run-of-the-river	150	150	150
	Minor plants(5)	Run-of-the-river	112	112	112
	Salto II	Run-of-the-river	35	35	35
	Total Emgesa		3,503	3,506	3,506
EGP Colombia(3)
	El Paso	Solar	86	—	—
	Total EGP Colombia		86	—	—
Total Capacity in Colombia			3,589	3,506	3,506
Peru
Enel Generation Peru
	Ventanilla	Combined Cycle/Natural Gas	459	460	460
	Santa Rosa	Gas Turbine/Diesel Oil	397	402	400
	Huinco	Reservoir	276	276	276
	Matucana	Run-of-the-river	133	133	133
	Callahuanca(6)	Run-of-the-river	84	84	83
	Moyopampa	Run-of-the-river	69	69	69
	Huampani	Run-of-the-river	31	31	31
	Her1	Run-of-the-river	1	1	1
	Total Enel Generation Peru		1,450	1,455	1,453
Chinango
	Chimay	Reservoir	157	157	157
	Yanango	Run-of-the-river	42	42	42
	Total Chinango		199	199	199
Enel Generation Piura
	Malacas(7)	Gas Turbine/Natural Gas+Diesel Oil	333	336	336
	Total Enel Generation Piura		333	336	336
EGP Peru(3)
	Rubi	Solar	179	—	—
	Wayra I	Wind	132	—	—
	Total EGP Peru		311	—	—
Total Capacity in Peru			2,294	1,990	1,987

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Central America(3)
EGP Costa Rica
	Chucas	Run-of-the-river	50	—	—
	Rio Volcan	Run-of-the-river	17	—	—
	Don Pedro	Run-of-the-river	14	—	—
	Total EGP Costa Rica		81	—	—
EGP Guatemala
	Palo Viejo	Run-of-the-river	87	—	—
	Occidente	Run-of-the-river	47	—	—
	Matanzas/San Isidro	Run-of-the-river	16	—	—
	Montecristo	Run-of-the-river	13	—	—
	Total EGP Guatemala		164	—	—
EGP Panama
	Enel Fortuna	Solar	300	—	—
	Progreso Solar	Solar	26	—	—
	Jaguito Solar	Solar	13	—	—
	PV Chiriqui	Solar	12	—	—
	Llano Sanchez Solar Power Tres	Solar	11	—	—
	Llano Sanchez Solar Power One	Solar	10	—	—
	Generadora Estrella Solar	Solar	8	—	—
	Llano Sanchez Solar Power Cuatro	Solar	8	—	—
	Sol Real Istmo	Solar	8	—	—
	Generadora Solar Caldera	Solar	5	—	—
	Total EGP Panama		401	—	—
Total Capacity in Central America			646	—	—
Consolidated Capacity			15,926	11,269	11,267

(1) The installed capacity corresponds to the net installed capacity, which considers the MW that each power plant consumes for its operation.

(2) “Reservoir” and “run-of-the-river” refer to hydroelectric plants that use the force of a dam or a river, respectively, to move the turbines that generate electricity. “Steam” refers to thermal power plants fueled with natural gas, coal, diesel, or fuel oil to produce steam that moves the turbines. “Gas Turbine” (“GT”) or “Open Cycle” refers to thermal power plants that use either diesel or natural gas to produce gas that turns the turbines. “Combined Cycle” refers to a thermal power plant fueled with natural gas, diesel oil, or fuel oil to turn the first turbine and then recovers the heat to generate steam to turn a second turbine.

(3) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

(4) In November 2021, EGP Brasil was merged into Enel Brasil.

(5) The small plants have an aggregate capacity of 112 MW. As of December 31, 2021, Emgesa owns and operates four small plants: Charquito (19 MW), El Limonar (18 MW), Laguneta (18 MW), and Tequendama (57 MW). 

(6) On June 14, 2017, with the approval of the regulatory entity (COES), the Callahuanca hydroelectric power plant was removed from commercial operation due to a catastrophic event (flooding of the facilities) that occurred on March 16, 2017. The Callahuanca hydroelectric power plant resumed full operations in March 2019.

(7) Malacas includes the installed capacity (189 MW) of the Reserva Fría de Talara power plant.

Property, Plant, and Equipment of Transmission and Distribution Companies

We conduct our distribution business through Edesur in Argentina, Enel Distribution Rio, Enel Distribution Ceara, Enel Distribution Goias, and Enel Distribution Sao Paulo in Brazil, Codensa in Colombia, and Enel Distribution Peru in Peru. We conduct our transmission business through Cien in Brazil.

We have significant property, plant, and equipment assets in electricity distribution. The following tables describe the main property, plant, and equipment of our distribution businesses, such as transmission lines, substations, and transformers, and distribution networks.

TABLE OF DISTRIBUTION FACILITIES

Distribution Network - Transmission Lines⁽¹⁾

			Transmission Lines
	Location	Concession Area	2021	2020	2019
		(in km2)	(in kilometers)
Edesur	Argentina	3,304	1,041	1,041	1,039
Enel Distribution Goias	Brazil	337,002	6,083	6,010	6,004
Enel Distribution Ceara	Brazil	148,895	5,452	5,381	5,293
Enel Distribution Rio	Brazil	32,615	3,457	3,455	3,429
Enel Distribution Sao Paulo	Brazil	4,526	1,838	1,834	1,830
Codensa	Colombia	26,093	1,341	1,340	1,319
Enel Distribution Peru	Peru	1,602	726	727	716
Total		554,037	19,938	19,788	19,630

(1) The transmission lines consist of circuits with voltages in the 35-500 kV range.

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Power and Interconnection Substations and Transformers from High to Medium Voltage ⁽¹⁾⁽²⁾

	Year ended December 31,
	2021			2020			2019
	Number of Substations	Number of Transformers	Capacity (MVA)	Number of Substations	Number of Transformers	Capacity (MVA)	Number of Substations	Number of Transformers	Capacity (MVA)
Edesur	70	184	13,028	67	180	12,876	68	182	12,956
Enel Distribution Goias	351	502	6,246	346	476	5,784	348	470	5,636
Enel Distribution Sao Paulo(3)	213	461	15,522	213	460	15,468	231	463	15,420
Enel Distribution Rio	138	283	5,967	137	281	5,867	137	281	5,786
Enel Distribution Ceara	121	196	3,614	118	195	3,587	118	195	3,587
Codensa	174	460	11,620	171	446	11,628	173	435	11,295
Enel Distribution Peru	48	155	5,176	41	153	5,053	49	150	4,924
Total	1,115	2,241	61,173	1,093	2,191	60,263	1,124	2,176	59,604

(1) The transformers’ voltage is in the range of 500 kV (in - high voltage, “hv”) and 1 kV (out - medium voltage, “mv”).

(2) The reported figures correspond to kilometers at the line circuit-level instead of at the line track-level.

(3) The number of Enel Distribution Sao Paulo’s substations includes 51 units of hv/hv without capacity for transmission (only capacity for operation).

Distribution Network - Medium and Low Voltage Lines⁽¹⁾

	Year ended December 31,
	2021		2020		2019
	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage
			(in kilometers)
Edesur	8,811	18,322	8,717	18,167	8,312	18,039
Enel Distribution Goias	189,627	33,954	184,676	33,415	182,446	33,085
Enel Distribution Ceara	93,568	58,490	92,481	57,652	90,664	56,619
Enel Distribution Rio	37,927	19,839	37,667	19,642	37,400	19,817
Enel Distribution Sao Paulo	21,435	20,902	21,395	20,799	21,339	20,665
Codensa	30,281	43,181	31,455	43,113	29,681	42,524
Enel Distribution Peru(2)	5,133	13,540	5,053	13,345	4,945	24,016
Total	386,782	208,228	381,444	206,133	374,787	214,765

(1) Medium voltage lines: 1 kV – 34.5 kV; low voltage lines: 110 – 380 V.

(2) The low voltage network includes street lighting.

Transformers from Medium to Low Voltage for Distribution⁽¹⁾

	Year ended December 31,
	2021		2020		2019
	Number of Transformers	Capacity (MVA)	Number of Transformers	Capacity (MVA)	Number of Transformers	Capacity (MVA)
Edesur	19,621	8,295	19,356	7,618	17,308	6,773
Enel Distribution Goias	235,214	6,714	225,937	6,433	221,702	6,303
Enel Distribution Ceara	157,006	4,441	153,812	4,249	149,853	3,982
Enel Distribution Sao Paulo	144,150	15,726	142,608	15,419	141,472	15,245
Enel Distribution Rio	130,379	6,023	129,047	5,881	127,726	5,737
Codensa	69,909	7,471	72,762	7,332	68,386	6,832
Enel Distribution Peru	10,837	2,161	11,369	2,088	11,287	2,042
Total	767,116	50,831	754,891	49,020	737,734	46,914

(1) These transformers’ voltage is in the range of 34.5 kV (in - medium voltage, “mv”) and 380-110 V (out - low voltage, “lv”).

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Insurance

Our electricity generation and transmission and distribution facilities are insured against damage due to natural disasters such as earthquakes, floods, other acts of god (but not for droughts, which are not considered force majeure risks and are not covered by insurance), or due to fire, or due to mechanical failure, based on the appraised value of the facilities as determined from time to time by an independent appraiser. Our companies are also insured from damages due to third-party claims.

Claims under our subsidiaries’ insurance policies are subject to customary deductibles and other conditions. We also maintain business interruption insurance, providing coverage for up to 24 months, including the deductible period, when following an insured failure of any of our facilities. The insurance coverage taken for our properties considers the quality of the insurance companies and the needs, conditions, and risk evaluations of each facility, and general corporate guidelines. All insurance policies are purchased from reputable international insurers. We continuously monitor and meet with the insurance companies to obtain, yearly, what is the most commercially reasonable insurance coverage.

We are also insured against damage to substations, transformers within the substations, and portions of the distribution network up to one kilometer from the substations, towers, or poles. Risks covered include losses caused by fire, explosions, earthquakes, floods, lightning, and damages to machinery and others. Liability insurance policies also protect our companies from claims made by third parties.

Project Investments

We continuously analyze potential growth opportunities in the countries where we operate. The study and profitability assessment of our project portfolio is an ongoing effort. Industry technology is allowing for smaller, less environmentally damaging power plants. These plants can be built more quickly, allow greater flexibility to activate or deactivate according to system needs, and are generally preferred by the community. We favor renewable energy technology for our new power plant investments and seek opportunities by building new greenfield projects or modernizing existing brownfield assets and improving operational or environmental performance. Each project’s expected start-up is assessed and is defined based on the commercial opportunities and our financing capacity to fund these projects. All of our projects are financed with internally generated funds. Our project investments are ordinarily submitted for internal approval in U.S. dollars, but occasionally they may be approved in another currency, including euros. The total amount invested as of the last fiscal year is presented in U.S. dollars, while the total approved investment is in the currency in which the project investment was approved, which may be different.

Below we list our most important projects under development. However, any decision related to construction will depend on commercial opportunities foreseen in the upcoming years, including future tenders for supplying the regulated market and the evolution of the regulatory framework (mainly in Argentina).

Budgeted amounts include connecting lines that could be owned by third parties and paid as tolls unless otherwise indicated.

Projects Completed in 2021

Argentina – Costanera Thermoelectric Power Plant – Wastewater Treatment System

The project consisted of a new wastewater treatment system for the Costanera power plant, connected to different collection points in the power plant. The new treatment system allows the discharge of wastewater in compliance with the environmental approvals for the Costanera power plant.

Construction began on May 10, 2019, and the project was completed on April 10, 2021. The total investment was US$ 21.2 million as of December 31, 2021.

Brazil – Cumaru Wind Farm

Cumaru is a new wind project located in the State of Rio Grande do Norte. It consists of five subparks, with 49 wind turbines–200 meters high–and a 28-km extension to an existing 230 kV transmission line. Cumaru has a total installed

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capacity of 206 MW and can generate 966 GWh annually. It also benefits from operational synergies with our nearby Modelo wind farm.

Construction began in May 2020 and was completed in October 2021, reaching commercial operation in November 2021. The total investment was US$ 181 million.

Brazil – Fontes dos Ventos II Extension

The project is an extension of our Fontes dos Ventos wind farm, located in the State of Pernambuco. The project consists of two subparks and 18 wind turbines, adding 99 MW of installed capacity. The extension can generate 421 GWh annually.

Construction began in July 2020, and the project was completed in November 2021, reaching commercial operation in December 2021. The total investment was US$ 86.7 million.

Brazil – Lagoa dos Ventos I and II Wind Farm

Lagoa dos Ventos I and II is a new wind farm, located in the State of Piaui. The project consists of Lagoa dos Ventos I (595 MW) and the Lagoa dos Ventos II extension (121 MW), adding a total of 716 MW of new installed capacity from 230 wind turbines capable of generating 3.3 TWh per year.

Construction began in February 2019, and the project was completed in March 2021. The total investment was US$ 639.7 million.

Projects under Construction in 2021

Brazil – Lagoa dos Ventos III Extension

Lagoa dos Ventos III is an extension of our Lagoa dos Ventos wind farm, located in the State of Piaui. The extension project consists of eight subparks, 72 wind turbines, and a 40-km transmission line, as well as building a new substation and interconnection bay to connect to the transmission line at 500 kV. The project will add 396 MW of new installed capacity to the farm and will be capable of generating 1.7 TWh annually.

Construction began in November 2020, and we expect the project to be completed in September 2022. The total approved investment is R$ 2,250.3 million, of which US$ 255.9 million had been incurred as of December 31, 2021.

Brazil – Morro do Chapeu Sul II

Morro do Chapeu Sul II is a wind project consisting of nine subparks, 84 wind turbines, and a 24-km transmission line. Upon completion, Morro do Chapeu Sul II will have an installed capacity of 353 MW and will be able to generate more than 1,800 GWh annually.

Construction began in June 2021, and the project was completed in February 2022. The total approved investment is R$ 1,924.2 million, of which US$ 329.0 million had been incurred as of December 31, 2021.

Brazil – Paranapanema Hydroelectric Power Plant – Spillway Upgrade

The project is being executed within our existing Paranapanema power plant, located in the State of Sao Paulo. Paranapanema is a hydroelectric power plant with 31.5 MW of installed capacity and generates on average more than 200 GWh of electricity annually. The project consists of upgrading the existing dam by creating a new spillway downstream that will increase the capacity of spillway flow. The upgrade to the dam is mandatory and originates from a commitment with the Brazilian federal and state regulatory agencies.

Construction began in December 2020, and we expect the project to be completed in June 2022. The total approved investment is R$ 100.3 million (US$ 18.3 million), of which US$ 12.4 million had been incurred as of December 31, 2021.

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Brazil – Sao Goncalo III Extension

Sao Goncalo III is an extension of our existing Sao Goncalo solar park, located in the State of Piaui. The project consists of five subparks and 639,360 bifacial solar panels, a technology expected to improve production efficiency by 18%. The extension project can generate 651 GWh annually and will add 256 MW of new installed capacity, increasing the total installed capacity of the solar park to 864 MW.

Construction began in January 2020, and we expect the project to be completed in June 2022. The total approved investment is approximately R$ 869.8 million, of which US$ 169.7 million had been incurred as of December 31, 2021.

Colombia – La Loma Solar Park

The La Loma solar park is located in the Department of El Cesar in northern Colombia. It consists of more than 400,000 photovoltaic panels, with an installed capacity of 187 MW. The project is capable of generating 423 GWh annually. The park will be interconnected through the La Loma substation at 110 kV via a new 1.4-km transmission line.

Construction began in March 2021, and we expect the project to be completed by the end of 2022. The total approved investment is US$ 111.1 million, of which US$ 82 million had been incurred as of December 31, 2021.

Colombia – Termozipa Thermoelectric Power Plant - Best Environmental Practices (BEPP) and Life Extension Project

The BEPP project in Termozipa aims to achieve high standards for gas emissions for coal-fired power plants by reducing the following components: Nitrogen oxide (NOx), sulfur dioxide (SO₂), and particulate emissions. The project also includes improvements to the ash extraction system and the refrigeration water discharge system.

The Life Extension Project contemplates improvements to the boilers, mills, turbines, generators, demi plant, water intake, medium- and low-voltage systems, electrostatic precipitators, and ancillary systems, to extend the power plant life for an additional 15 years (or 100,000 hours) of operation.

Construction began on December 1, 2016. As of December 31, 2021, 100% of Life Extension activities had been completed. The remaining BEPP activities have been suspended indefinitely pending further information regarding new emissions regulations. The total approved investment is approximately EUR 134 million (US$158 million), of which US$ 85.6 million had been incurred as of December 31, 2021.

Colombia – Windpeshi Wind Farm

Windpeshi wind farm is located in the territories of indigenous communities in the Department of La Guajira in northern Colombia. The wind farm has an installed capacity of 205 MW and an estimated generation of 995 GWh annually. It consists of 41 wind turbines and a step-up substation on-site and will connect to the Cuestecita substation at 220 kV via a new 65-km transmission line and an existing transmission line.

Construction began in January 2021, and we expect the project to be completed in 2023-2024. The total approved investment is US$ 318 million, of which US$ 196.1 million had been incurred as of December 31, 2021.

Panama – La Esperanza Cluster - Phase I (Jaguito & Esperanza Solar)

Phase I of the La Esperanza Cluster comprises two new PV solar parks, with a combined 39 MW of installed capacity. Jaquito has 13 MW of installed capacity and is located in the Province of Cocle next to our Estrella Solar power plant, currently in operation. Esperanza Solar has 26 MW of installed capacity and is located in the Province of Chiriqui near our Sol Real Cluster, which includes the Caldera and Sol de David solar parks, also currently in operation. Due to the proximity of the plants to other operating plants, each project will create operational synergies through the shared use of existing infrastructure such as access roads, security services, and operation and maintenance centers.

Construction on Jaguito and Esperanza Solar began in September 2020 and October 2020, respectively, and we expect the projects to be completed in 2022. The total approved investment for both projects is US$ 31 million (Jaguito –

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US$ 10.3 million and Esperanza Solar – US$ 20.7 million), of which US$ 28.4 million (Jaguito – US$ 9.9 million and Esperanza Solar – US$ 18.5 million) had been incurred as of December 31, 2021.

Panama – Madre Vieja Solar Park

The Madre Vieja project is a new PV solar park in the Province of Chiriqui near the La Esperanza Cluster. It has an installed capacity of 31 MW, consisting of 66,580 monofacial PV modules. A new 3.8-km transmission line will be built to interconnect the project to the Progreso substation at 34.5 kV. Madre Vieja will exploit existing nearby infrastructure to create operational synergies.

Construction began in March 2021, and we expect the project to be completed in August 2022. The total approved investment is US$ 20.0 million, of which US$ 7.7 million had been incurred as of December 31, 2021.

Projects under Development in 2021

We are currently evaluating the development of the following projects, which we classify as “under development.” We will decide whether to proceed or not with each project depending on the commercial and other opportunities foreseen in upcoming years and future tender prices for supplying the regulated market’s energy requirements and negotiations with existing or new unregulated customers.

Argentina – Dock Sud Thermoelectric Power Plant – High-Efficiency Upgrade

The project is being carried out in our Dock Sud power plant, which is located in Buenos Aires and has 775 MW of installed capacity. Components of the gas, steam, and auxiliary turbines will be upgraded to increase capacity and efficiency for improved performance and market competitiveness. We expect to increase installed capacity by 87 MW and improve efficiency by 1.6%. The improved efficiency is expected to reduce CO2 and NOx emissions by 3% and 29%, respectively, as well as decrease total water consumption by 35%. We also expect generation to increase by 1 TWh per year.

We expect construction to begin in September 2022 and the project to be completed in 2022. The total approved investment is EUR 13.2 million (US$15.5 million), none of which had been incurred as of December 31, 2021.

Brazil – Aroeira Wind Farm

The Aroeira wind farm is located in the State of Bahia. The project consists of eight subparks, 81 wind turbines, and a 17.5 km 500 kV transmission line, with a total installed capacity of 348 MW. It will be able to generate 1,800 GWh annually for the free market.

Construction began in April 2022, and we expect the project to be completed in September 2023. The total approved investment in the project is R$ 2,562 million, of which US$ 32.3 million had been incurred as of December 31, 2021.

Brazil – Lagoa dos Ventos V

Lagoa dos Ventos V is a wind project with an installed capacity of 399 MW, consisting of nine subparks, and 70 wind turbines, capable of generating more than 1,600 GWh annually.

Construction began in February 2022, and we expect the project to be completed in July 2023. The total approved investment is R$ 2,503 million, of which US$ 87 million had been incurred as of December 31, 2021.

Brazil – Pedra Pintada Wind Farm

The Pedra Pintada wind farm is located in the State of Bahia. The project will have an installed capacity of 194 MW and is expected to generate 880 GWh annually. The wind farm will be connected to the Ourolandia II substation at 500 kV via a new 21-km transmission line.

We expect construction to begin in 2023 and the project to be completed in 2024. The total approved investment is US$ 269 million, of which US$ 5.2 had been incurred as of December 31, 2021.

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Colombia – Fundacion Solar Park

Fundacion is a solar project located in the Department of Magdalena in northern Colombia. The project will utilize more than 200,000 photovoltaic modules, reaching an installed capacity of 132 MW and generating 266 GWh annually. Fundacion will be connected to the Fundacion substation at 110 kV via a new 7-km transmission line.

We expect construction to begin in April 2022 and the project to be completed in 2023. The total approved investment is COP$ 446.7 billion, of which US$ 2.9 had been incurred as of December 31, 2021.

Colombia – Guayepo I & II Solar Park

This solar project is located in the Department of Atlantico in northern Colombia. It consists of two subparks, with more than 800,000 photovoltaic modules and a combined installed capacity of approximately 487 MW, each park with 243.35 MW of installed capacity. The parks will be built in two phases–Guayepo I (phase I) and Guayepo II (phase II)–and will connect to the Sabanalarga substation at 500 kV via a new 9.7-km transmission line.

Construction began in March 2022, and we expect phase I and phase II to be completed in 2023. The total approved investment is US$ 166.5 million, of which US$ 11.8 had been incurred as of December 31, 2021.

Panama – Baco Solar Park

Baco solar park is in the Province of Chiriqui and consists of more than 50,436 monofacial PV modules, 128 string inverters, and four conversion units. Baco has an installed capacity of 30 MW and is expected to generate 48 GWh annually. The project will create operating synergies with other projects and connect to Madre Vieja, a neighboring solar project, via a 400-meter transmission line, which will subsequently connect to the Progreso substation at 34.5 kV via a new overhead 3.8-km transmission line.

We expect construction to begin in the first quarter of 2022 and the project to be completed in 2022-2023. The total approved investment is US$ 19.1 million, of which US$ 2.0 had been incurred as of December 31, 2021.

Peru – Callahuanca Hydroelectric Power Plant – Repowering Project

The Callahuanca repowering project involves our existing 84 MW Callahuanca power plant in Peru. Callahuanca is a run-of-the-river hydroelectric power plant with four generation units that use water coming from the Rimac and Santa Eulalia Rivers. The project involves improvements to unit No. 4, increasing the plant’s capacity by 1 MW and the annual generation by at least 23 GWh.

We expect construction to begin in August 2022 and the project to be completed by December 2022. The total approved investment is US$ 4.4 million, of which US$ 1.2 million had been incurred as of December 31, 2021.

Peru – Clemesi Solar Park

Clemesi is a solar project in the Department of Moquegua, with an installed capacity of 123 MW. The project consists of 229,140 PV modules and will expand our Rubi I step-up substation. Clemesi is located next to our existing Rubi I solar park (179 MW) and will benefit from operational synergies with this park. There are also potential commercial synergies with Wayra II, another project that is being evaluated, see below.

Construction began in April 2022, and we expect the project to be completed in 2023. The total approved investment is US$ 73.4 million, of which US$ 5.2 million had been incurred as of December 31, 2021.

Peru – Santa Rosa and Malacas Thermoelectric Power Plants – Closure of Open Cycle of Gas Turbines.

We are analyzing the potential closure of the open cycle of certain gas turbines in Santa Rosa (gas turbine #8) and Malacas (gas turbines #4 and #6), converting these power plants from open-cycle gas turbines to combined cycle. This conversion may increase the power plants’ installed capacity and improve their efficiency, which may help better position them in priority order for dispatch.

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We expect construction to begin in 2024 and the projects to operate at full capacity by 2026-2027. The total estimated investment of these projects is US$ 400 million, of which none had been incurred as of December 31, 2021.

Peru – Ventanilla Thermoelectric Power Plant – Cooling System

We are analyzing improvements in the Ventanilla power plant’s cooling system to reduce raw water utilization from underground water wells.

We expect construction to begin in 2024 and the project to operate at full capacity by 2026. The total estimated investment is US$ 12.4 million, of which US$ 0.6 million had been incurred as of December 31, 2021.

Peru – Wayra II Extension

The Wayra II project is an extension of our existing Wayra I (132 MW) wind farm in the Department of Ica. Wayra II (177 MW) will increase the total installed capacity of the farm to 309 MW. The extension consists of 30 wind turbines and the expansion of the Wayra I step-up substation. The project will enjoy some operational synergies with Wayra I and will potentially have commercial synergies with the Clemesi, another project that is being evaluated, see above.

Construction began in January 2022, and we expect the project to be completed in 2023. The total approved investment is US$ 188.5 million, of which US$ 18.6 million had been incurred as of December 31, 2021.

Major Encumbrances

Costanera’s supplier debt with Mitsubishi Corporation (“MC”) is for the remaining payments on equipment purchased from MC in November 1996, which was refinanced in November 2021. The value of the assets pledged to secure this debt was US$ 30.3 million as of December 31, 2021.

Item 4A. Unresolved Staff Comments

None

Item 5.  Operating and Financial Review and Prospects

A. Operating Results.

Introduction

The following selected consolidated financial data should be read in conjunction with our consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2021, and 2020 and for the three years ended December 31, 2021, are derived from our audited consolidated financial statements included in this Report. Our consolidated financial statements were prepared in accordance with IFRS, as issued by the IASB.

Our consolidated financial statements are presented in U.S. dollars because our functional currency is the U.S. dollar. For further information about our functional currency, please refer to Note 2.8 of the Notes to our consolidated financial statements. The Observed Exchange Rate, which is reported and published daily on the Central Bank of Chile’s web page, corresponds to the weighted-average exchange rate of the previous business day’s transactions in the Formal Exchange Market. For more information concerning historical exchange rates, see “— Exchange Rates” below. The tables are expressed in millions of U.S. dollars, except for ratios, operating data, and data for shares and American Depositary Shares (“ADSs”).

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The following tables set forth our selected consolidated financial data for the years indicated and the operating data of our principal subsidiaries:

	For the year ended December 31,
	2021	2020	2019
	(in millions of US$  except per share and per ADS data)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income(1)	16,192	12,292	14,387
Raw materials and consumables used	(10,451)	(7,556)	(8,541)
Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense	(3,077)	(2,584)	(3,004)
Operating income from continuing operations	2,664	2,152	2,842
Financial results(2)	(727)	(412)	(451)
Other gains	3	5	14
Share of profit (loss) of associates and joint ventures accounted for using the equity method	1	3	1
Income from continuing operations before income tax	1,941	1,748	2,406
Income tax expenses, continuing operations	(806)	(567)	(236)
Net Income from continuing operations	1,135	1,181	2,170
Profit after tax from discontinued operations	—	—	—
Net income	1,135	1,181	2,170
Net income attributable to the parent Company	741	825	1,614
Net income attributable to non-controlling interests	394	356	556
Basic and diluted earnings from continuing operations per average number of shares (US$ per share)	0.007	0.011	0.025
Basic and diluted earnings from continuing operations per average number of ADS (US$ per ADS)	0.372	0.542	1.233
Basic and diluted earnings from discontinued operations per average number of shares (US$ per share)	―	―	―
Basic and diluted earnings from discontinued operations per average number of ADS (US$ per ADS)	―	―	―
Total basic and diluted earnings per average number of shares (US$ per share)	0.007	0.011	0.025
Total basic and diluted earnings per average number of ADSs (US$ per ADS)	0.372	0.542	1.233
Cash dividends per share (US$ per share)	0.007	0.011	0.008
Cash dividends per ADS (US$ per ADS)	0.372	0.530	0.419
Weighted average number of shares of common stock (millions)	99,588	76,086	65,481
Other Consolidated Financial Data
Capital expenditures (CAPEX)(3)	3,012	1,553	1,659
Depreciation, amortization and impairment losses(4)	1,438	1,100	1,225

(1) During 2021, we reclassified from financial income to operating income the value to be recovered of certain financial assets related to the concession contracts of the electricity distribution subsidiaries in Brazil. As a consequence of such reclassification, we retrospectively reclassified in the consolidated statements of comprehensive income the amounts of ThUS$ 99,071 and ThUS$ 73,345 from financial income to operating income for the years ended December 31, 2020, and 2019, respectively. Please refer to Note 2.2.c of the Notes to our consolidated financial statements for further detail.

(2) Financial results represent (+) financial income, (-) financial expenses, (+/-) foreign currency exchange differences, and net gains/losses from indexed assets and liabilities.

(3) CAPEX figures represent cash flows used to purchase property, plant, and equipment, and intangible assets for each year.

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(4) Please refer to Note 30 of the Notes to our consolidated financial statements for further detail.

	As of December 31,
	2021	2020
	(in millions of US$)
Consolidated Statement of Financial Position Data
Total assets	34,959	26,934
Non-current liabilities	12,133	9,323
Equity attributable to the parent company	12,833	8,106
Equity attributable to non-controlling interests	2,197	2,228
Total equity	15,030	10,334
Capital stock(1)	15,799	9,763

(1) Capital stock represents issued capital.

Exchange Rates

Fluctuations in the exchange rate between the Chilean peso and the U.S. dollar will affect the U.S. dollar equivalent of the price in Chilean pesos of our shares of common stock on the Santiago Stock Exchange (Bolsa de Comercio de Santiago) and the Chilean Electronic Stock Exchange (Bolsa Electrónica de Chile). These fluctuations in the exchange rate affect the price of our ADS and the dividends we pay (see “Item 8. Financial Information — A. Consolidated Statements and Other Financial Information — Dividends”). Also, to the extent that significant financial liabilities are denominated in foreign currencies, fluctuations in the foreign currency exchange rate may significantly impact our earnings.

For further details regarding fluctuation in the exchange rates between the U.S. dollar and the local currency in each of the countries in which we operate, please refer to “— B. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — d. Economic Conditions — Local Currency Exchange Rate”, below.

General

The following discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in Item 18 in this Report, and the selected financial data included above. Our audited consolidated financial statements as of December 31, 2021, and 2020 and for each of the years in the three-year period ended December 31, 2021, have been prepared under IFRS, as issued by the IASB.

1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company

We are an electricity company headquartered in Chile that owns and operates generation, transmission, and distribution companies in Argentina, Brazil, Colombia, Costa Rica, Guatemala, Panama, and Peru. Substantially all our revenues, income, and cash flows come from the operations of our subsidiaries and associates in these countries.

Factors such as (i) hydrological conditions, (ii) fuel prices, (iii) regulatory developments, (iv) exceptional actions adopted by governmental authorities, and (v) changes in economic conditions in countries in which we operate may materially affect our financial results. Our results from operations and financial condition are affected by variations in the exchange rates between the U.S. dollar and the currencies of the countries in which we operate. These exchange variations may materially impact the consolidation of the results of our companies. We also have certain critical accounting policies that affect our consolidated operating results.

Our risk diversification strategy aims to balance the impact of significant changes in one country with opposing changes in other countries and among our different business segments in generation, transmission, and distribution. For the years covered by this Report, the impact of these factors on us is discussed below.

As of December 31, 2021, we directly held 48.48% and 48.30% of the equity interests and 56.43% and 57.15% of the voting shares of Emgesa and Codensa, respectively. We exercised control over Emgesa and Codensa through shareholder agreements with Grupo Energía Bogotá S.A. (GEB), which owns both entities’ remaining equity interests. We have the right to appoint the majority of Emgesa’s and Codensa’s board members and consolidate Emgesa and

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Codensa in our consolidated financial statements presented in this Report. On March 1, 2022, Codensa, Enel Green Power Colombia S.A.S. ESP and ESSA2 SpA were merged with and into Emgesa, which is the surviving corporation and was renamed Enel Colombia S.A. ESP. Following the merger, we own 57.345% of Enel Colombia and control Enel Colombia, GEB owns 42.515% and minority holders own 0.140%.

On April 1, 2021, EGP Américas S.p.A. merged with and into Enel Américas, which thereby acquired all of the assets and liabilities of EGP Américas, including the non-conventional renewable energy (“NCRE”) generation business and assets that EGP Américas owned in Central and South America (except Chile). As a consequence, all the shareholders and equity of EGP Américas were incorporated into Enel Américas, and EGP Américas was dissolved without liquidation. Please refer to Note 5 of the Notes to our consolidated financial statements for further detail.

On November 4, 2021, Enel Green Power Brasil Participacoes Ltda. (“EGP Brasil”) merged with and into Enel Brasil S.A., with the latter as the surviving corporation holding the NCRE generation subsidiaries formerly held by EGP Brasil (the “Brazil NCRE Subsidiaries”).

a.Generation and Transmission Business.

As of December 31, 2021, our electricity generation and transmission businesses were conducted: in Argentina through Costanera, El Chocón, Dock Sud, and Enel Green Power Argentina S.A.; in Brazil through EGP Cachoeira Dourada, Fortaleza, EGP Volta Grande, and the Brazil NCRE Subsidiaries; in Costa Rica through Enel Green Power Costa Rica S.A.; in Colombia through Emgesa and Enel Green Power Colombia S.A.S. ESP; in Guatemala through Enel Green Power Guatemala S.A.; in Panama through Enel Green Power Panama S.R.L.; and in Peru through Enel Generation Peru, Enel Generation Piura, and Enel Green Power Peru S.A.C. The electric power transmission business is mainly carried out through an interconnection line between Argentina and Brazil operated by Enel CIEN, a subsidiary of Enel Brasil, with a 2,200 MW transmission capacity. A substantial part of our generation capacity depends on the hydrological conditions prevailing in the countries where we operate. Our net installed capacity as of December 31, 2021, 2020, and 2019 was 15,926 MW, 11,269 MW, and 11,267 MW, respectively. Our renewable energy installed capacity represented 68.6%, 55.5%, and 55% of our total net installed capacity in 2021, 2020, and 2019, respectively. See “Item 4. Information on the Company — D. Property, Plants and Equipment.”

Our hydroelectric generation was 24,704 GWh, 25,143 GWh, and 25,604 GWh in 2021, 2020, and 2019, respectively. In 2021, our hydroelectric generation decreased by 1.7% compared to 2020, primarily due to adverse hydrological conditions in Colombia.

In the countries where we operate, hydrological conditions can range from very wet to extremely dry. There is a wide range of possible hydrological conditions between these two extremes, and their final effect on us often depends on accumulated hydrology. For instance, a new year with drought conditions has a smaller impact on us if it follows several abundant rainfall periods instead of exacerbating a prolonged drought. Likewise, an excellent hydrological year has a smaller effect after several wet years than after a prolonged drought.

In Argentina, the months that typically have the most precipitation are May through August. The months when snow and ice in the mountains melt at higher levels is during the warmer months, from October through December, providing water flow to the Collón Curá and Limay Rivers, which feed El Chocón’s reservoir and hydroelectric plant, located in southwestern Argentina, in the Comahue region. Therefore, depending on weather conditions, water availability can peak during two seasons in a year, both winter and summer.

In Brazil, the MRE provides financial protection against hydrological risks for hydroelectric generators. The market operator defines which hydroelectric plants generate electricity to minimize the system cost. The generators with deficits buy energy from the generators with surpluses at a specified price with a marginal operating cost set annually by ANEEL. All hydroelectric generators that participate in the MRE participate in the overall hydroelectric generation dispatched in proportion to their assured energy, regardless of their contracted sales. In 2021, due to the intensification of the water crisis, the hydroelectric generation of Cachoeira Dourada and EGP Volta Grande was affected and decreased compared to 2020. In 2020, the hydroelectric generation of Cachoeira Dourada and EGP Volta Grande increased compared to 2019 due to better hydrological conditions.

Fortaleza is a thermal plant, and its results depend mainly on selling long-term PPAs, thermal generation, generation costs, energy purchase costs, and commercial policy.

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The Brazil NCRE Subsidiaries held by EGP Brasil contributed an installed capacity of 3,624 MW from renewable sources: wind (2,156 MW), solar (1,233 MW), and run-of-the-river hydroelectric (235 MW). Their energy production depends on the prevailing climatic conditions in the area where they are located. The prices differ according to the type of technology used and the terms agreed to in the contracts. Enel Brasil, through the Brazil NCRE Subsidiaries, is currently building 692 MW of installed capacity from solar (São Gonçalo III) and wind projects (Lagoa dos Ventos III, Morro do Chapéu Sul II, Fontes dos Ventos II, Cumaru and Aroeira). These clean energies were essentially commercialized in the free market. The Brazil NCRE Subsidiaries have been consolidated into Enel Américas as of April 2021.

Hydrological conditions in Colombia vary significantly throughout the different regions and depend on geographical conditions and topography. There are two rainfall patterns. One pattern is characterized by two rainy periods separated by a drier season. The Andean region in the center of the country is one of the most populated areas and the center of economic activity. It is where all our hydroelectric plants, except the Guavio plant, are located. The second pattern is characterized by a rainy season followed by a drier season in the Orinoquia region, in eastern Colombia, where our largest hydroelectric plant, Guavio (1,260 MW), is located.

EGP Colombia contributed an installed capacity of 86 MW from its El Paso solar park. Its energy production depends on the prevailing climatic conditions in the area where it is located. EGP Colombia has been consolidated into Enel Américas of April 2021.

EGP Peru contributed an installed capacity of 311 MW from renewable sources: Rubí solar park (179 MW) and Wayra I wind farm (132 MW). Its energy production depends on the prevailing climatic conditions in the area where it is located. EGP Perú has been consolidated into Enel Américas as of April 2021.

Hydrological conditions in Peru also vary significantly depending on the location and the seasonality. The Pacific hydrographic region, which concentrates most of the population and economic activity, typically has less rainfall than the rest of the country. The Rimac River basin is located in this region and the flow is provided by the rainfall from the Andean mountains from December through March and also from the regulated system for the dry season, feeding five of our seven hydroelectric plants. The Amazonian hydrographic region has a greater water supply due to abundant rainfall in the same period, providing flow for the Tarma and Tulumayo River basins, where our other two hydroelectric plants are located.

With the incorporation of EGP Américas, Enel Américas also added 646 MW of installed capacity from 100% renewable energy sources from EGP Costa Rica, EGP Guatemala, and EGP Panama.

EGP Costa Rica contributed 81 MW of installed capacity from hydroelectric power plants: Chucas (50 MW), Río Volcan (17 MW), and Don Pedro (14 MW). The Chucas plant was promoted by ICE to take advantage of the waters of the Grande de Tárcoles River. A Costa Rican state company, ICE is the largest generator in the country and the only buyer of energy. To date, only rural electrification cooperatives and municipal companies can sell the energy they generate directly to customers in their concession area, according to Law No. 8,345. The setting of rates for ICE and its generation system is governed by Law No. 7,593, which establishes that the rates set by ARESEP will be based on the principle of service at cost, which consists of calculating an average accounting cost and adding a percentage of utility, also called revenue for development. ICE is required to submit at least one rate study per year, which includes a detailed justification for each of the items listed above

EGP Guatemala contributed 163 MW of installed capacity from hydroelectric power plants: Palo Viejo (87 MW), Occidente (47 MW), and other smaller hydroelectric plants (29 MW). Palo Viejo allows for the efficient use and exploitation of water from the Cotzal, Irrigation, Escondido, and Desengaño Rivers to generate electricity. Occidente has purified the waters of the Samalá River, one of the most polluted in the country. As a result of the purification system installed by EGP Guatemala, farmers can use the water to irrigate their fields. The system operator and market administrator work as a private non-profit company that operates the NIS and wholesale market by maintaining continuity and security in the country’s electricity supply. The wholesale market is made up of generators, carriers, marketers, distributors, importers, exporters, and large users. This market has functioned as a free market since 1996 when the activities of the electricity industry were separated, and the generation and sale of energy were opened to free competition. Transmission and distribution function as regulated activities where private and public companies participate to provide the service, granted through public bidding. In addition, the General Electricity Law establishes the

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separation of functions in the electrical activity, that is, generation, transmission, and distribution must be carried out through different companies.

In Guatemala, the electricity sector is made up of the NIS and some isolated systems. The operation of the NIS and all its electrical elements is one of the responsibilities of the AMM and is governed by the Commercial Coordination Regulations and Operational Coordination Regulations. These regulations are intended to guarantee the coordination of the operation of the NIS to supply demand at a minimum cost, maintaining the continuity and quality of the service, and are approved by the National Electric Energy Commission.

EGP Panama contributed 401 MW of installed capacity from hydroelectric power plants: Fortuna (300 MW) and other smaller plants (101 MW). Fortuna’s main source of water supply is the Chiriquí River, and its tributaries originate in the Fortuna Forest Reserve, which is mostly covered by tropical rain forest. The Chiriquí River rises in the Valle de la Sierpe and runs 75 kilometers to its mouth in the Pacific Ocean.

Law No. 6 of 1997 and its amendments establish the regulatory and institutional framework for the provision of public electricity service. The law regulates the generation, transmission, distribution, and commercialization of electricity. ASEP is the entity in charge of regulating, supervising, and ensuring excellence in the provision of public services for regulated customers and end users, compliance with regulations current legislation, respecting their rights, and fulfilling their obligations. Generators are made up of self-generators, and co-generators. When distributors sell their own generation surpluses to third parties, they have several options to participate in the Panamanian market.

The value of the water used in reservoir hydroelectric plants is calculated by the CND in accordance with the commercial rules and the technical and operational rules of the operation regulations and the detailed methodologies. This water value depends on a stochastic analysis carried out by the operator where all system variables are considered: flow projections, plant maintenance, transmission network, etc. The import price offered in the interconnection, which in the case of contracts is the one declared to the CND by the National Participant, and in the case of second-hand imports, will be the one reported by the Regional Operator Entity.

In Panama, a large client is considered to be any natural or legal person, with a maximum demand greater than 100 kW per site, whose purchases of power and energy can be made in the wholesale electricity market (large authorized customer) or from distributors. As of July 2014, authorized large customers have the option to freely negotiate the supply of energy with a generator or buy energy on the spot market. Otherwise, energy must be purchased from a distribution company at the approved rate.

Hydrological conditions affect electricity market prices, generation costs, spot prices, tariffs, and the mix of conventional hydroelectric, thermal, or renewable generation. The market operator is constantly defining the mix to minimize the operating cost of the entire system. Hydroelectric and renewable generation are almost always the least expensive generation technologies and typically have a marginal cost close to zero. However, authorities might assign an opportunity cost for the use of reservoir water, which may lead to hydroelectric generation not necessarily being the lowest marginal cost at a particular time. The thermal generation cost does not depend on hydrological conditions but on international commodity prices for LNG, coal, diesel, and fuel oil.

Spot prices primarily depend on hydrological conditions and commodity prices and, to a lesser extent, on renewable generation availability. Under most circumstances, abundant hydrological conditions decrease spot prices, while dry conditions usually increase spot prices. Spot market prices affect our results because we must purchase electricity in the spot market when our contracted energy sales are more than our generation. We sell electricity in the spot market when we have electricity surpluses.

Hydrological conditions do not have an isolated effect but need to be evaluated in conjunction with other factors to understand the impact on our operating results better. Many different factors may affect our operating income, including the level of contracted sales, purchases and sales in the spot market, commodity prices, energy demand, technical and unforeseen problems that can affect the availability of our thermal power plants, location of power plants in relation to urban demand centers, and transmission system conditions, among others.

Argentina operates under a regulated market, with a defined tariff or remuneration scheme and no trading. The system defines the regulated remuneration of generation companies, providing compensation based on fixed and variable costs as well as additional operational and maintenance costs. Market prices are unrelated to hydrological conditions or

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commodity prices. There is a small spot market (approximately 5.2 TWh, or 4% of total demand per year during 2021 and 2020) because free bilateral trading has been suspended since 2013. Therefore, El Chocón sells most of its energy to the market operator at the regulated price, which is not affected by hydrological conditions. Our results depend mainly on our electricity generation. Hydrological conditions during 2021 were worse than in 2020. In 2021, El Chocón’s generation decreased compared to 2020, primarily due to worse hydrological conditions in the Limay River. Costanera and Dock Sud are thermal power plants whose operating results depend on their availability and their generation.

In Brazil, operating results decreased in 2021 compared to 2020 mainly due to lower revenues of Cachoeira Dourada due to (i) higher energy purchases at a higher cost and (ii) lower physical energy sales.

Fortaleza’s results increased in 2021 compared to 2020, mainly due to the higher selling long-term PPA price as a result of increases affected by high inflation perceived in Brazil (captured in its escalation formula).

EGP Brazil, due to its better weather conditions for wind, solar, and hydroelectric operations during 2021, obtained positive operating results, mainly due to higher physical sales of 12,281 GWh.

In Colombia, the hydrological conditions of the rivers that supplied the country’s hydroelectric plants during 2021 were more favorable compared to 2020. In 2021, sales increased due to higher demand in the regulated market as a result of the economic recovery. The higher operating income was mainly due to higher sales from fixed contracts indexed to the PPI (COP$ 256 per KWh in 2021, approximately 16% higher compared to 2020).

Despite the better weather conditions for the operations of El Paso solar park during 2021, and higher physical sales of 97 GWh, EGP Colombia operated at a loss, mainly due to the devaluation of the Colombian peso against the U.S. dollar.

In Peru, hydrology in the Rímac River basin was 17% above average in 2021 compared to 2020. However, the hydrology in the Tarma and Tulumayo Rivers, where our Yanango and Chimay power plants are located, respectively, was below average mainly from July to October in 2021. Spot energy prices rose approximately 82% on average compared to 2020, due to a regulatory change related to the treatment of fuel costs used for economic dispatch.

In Peru, the average irradiance resource in the Moquegua Region was 725 w/m² during 2021, better compared to 2020, which contributed to higher production in our Rubí solar power plant. The average wind velocity in the Ica Region during 2021 was 7.7 m/s, which benefited our Wayra wind farm.

EGP Costa Rica, due to better weather conditions for the operations of Chucas, Río Volcán, and Don Pedro power plants during 2021, operated at a profit mainly due to higher physical sales of 168 GWh.

EGP Guatemala, due to better weather conditions mainly for the operations of Palo Viejo and Occidente power plants during 2021, operated at a profit mainly due to higher physical sales of 950 GWh.

EGP Panama, due to better weather conditions for the operations of Fortuna and other smaller power plants during 2021, operated at a profit mainly due to higher physical sales of 1,519 GWh.

b.Distribution Business

During the year ended December 31, 2021, our electricity distribution business was conducted: in Argentina through Edesur; in Brazil through Enel Distribution Rio, Enel Distribution Ceara, Enel Distribution Goias, and Enel Distribution Sao Paulo; in Colombia through Codensa; and in Peru through Enel Distribution Peru. For the year ended December 31, 2021, electricity sales increased by 4.0% compared to 2020, totaling 119,845 GWh, mainly explained by higher physical sales in all subsidiaries of the distribution business. Our distributors serve the major cities of South America, providing electricity to approximately 26.2 million customers. These companies face an increasing electricity demand, partly due to population growth and higher consumption, which requires continuous investment.

Distribution revenues are mainly derived from the resale of electricity purchased from generators. Revenues associated with distribution include the recovery of the cost of electricity purchased and the resulting revenues from the VAD, plus the physical energy losses permitted by the regulator. Other revenues derived from our distribution services consist of transmission revenues, charges for new connections, and the maintenance and rental of meters, among others.

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It also includes revenues from public lighting, infrastructure projects mainly associated with real estate development, and energy efficiency solutions, including air conditioning equipment and LED lights.

Although these other revenue sources have increased, the core business continues to be the distribution of energy at regulated prices. Therefore, the regulatory framework has a substantial impact on our distribution business results, especially when the actions adopted by government authorities define or directly intervene with regulated customer tariffs or affect the price at which distributors can buy their energy. Our ability to purchase electricity relies heavily on generation availability and, to a lesser degree, regulation. Also, we are focusing on reducing physical losses, principally due to illegally tapped energy, especially in Brazil and Argentina, and improving our collection indices and efficiency, primarily through new automation technologies.

c.Selective Regulatory Developments

The regulatory framework governing our businesses in the countries where we operate has a material effect on our operating results. In particular, regulators set (i) energy prices in the generation business, considering factors such as fuel costs, reservoir levels, exchange rates, future investments in installed capacity, and demand growth, and (ii) distribution considering the costs of energy purchases paid by distribution companies (which distribution companies pass on to their customers) and the VAD, all of which are intended to reflect investments and operating costs incurred by distribution and generation companies, and allow our companies to earn a regulated level of return on their investments and guarantee service quality and reliability. Our electricity subsidiaries’ earnings are primarily determined by regulators, mainly through the tariff setting process. In Argentina, SEE Resolution No. 19/2017 set a U.S. dollar remuneration scheme for existing power generators (converted into Argentine pesos at the exchange rate published by the Argentine Central Bank), defining a minimum remuneration for power by technology and scale. On February 28, 2019, SRR and ME Resolution No. 1/2019 replaced SEE Resolution No. 19/2017, establishing the current guidelines for the remuneration of existing generation plants. On February 27, 2020, the Department of Energy published Resolution SE 31/2020, which replaced SRR and ME Resolution No. 1/2019, effective from February 1, 2020. Under this resolution, remuneration prices are subject to be remunerated in Argentine pesos at the exchange rate of Ar$ 60 per U.S. dollar and the resolution established updated values in Argentine pesos. Resolution SE 31/2020 defines a minimum remuneration based on the generator units’ scale and technology and according to actual availability. Additionally, for thermal units, it establishes the possibility of offering commitments of availability with equal differential remuneration for all technologies. CAMMESA will enable the thermal generator to file, up to 30 days before the beginning of each quarterly period, the power value to be committed to by each unit, differentiating among summer, winter, and the remainder of the year (adjustments can be made within the same period). The remuneration that a unit with power commitment will receive will be proportional to its compliance with its commitment, and the minimum value is calculated based on the minimum price. The power remuneration will be affected depending on the usage factor of thermal generation equipment.

In May 2021, SEE Resolution No. 440/2021 updated the remuneration scheme established in the SEE Resolution No. 31/2020 to increase remuneration by 29%, retroactive to February 2021. On November 2, 2021, SEE Resolution No. 1,037/2021 was published, which provided for an additional and temporary recognition in the remuneration of the generators included in Resolution No. 440/2021, which covered economic transactions between September 1, 2021, and February 28, 2022. On November 9, 2021, the Ministry of Energy and Mining sent the regulatory instruction to CAMMESA, within the framework of Article 4 of Resolution No. 1,037/21, instructing that, in the calculation of the economic transactions foreseen in Points 4 and 5 of Annex II of Resolution SEE No. 440/2021, it must be assumed that they have a constant Utilization Factor equal to 70% for the determination of the Power Availability Remuneration. Likewise, an additional amount of Ar$ 1,000/MWh was recognized, assigned in proportion to the monthly generated energy of each conventional and hydraulic thermal generator.

In Argentina, as a result of the regulatory agreement signed between Edesur and the Argentine government, the reciprocal claims that originated in the transition period 2006-2016 were settled, which meant recognizing US$ 203 million in results for 2019.

In 2020, the Province of Buenos Aires asked the Argentine Ministry of the Economy to initiate a bid process to correct the situation related to the electricity supply in low-income neighborhoods between October 2017 and December 2020. On December 22, 2020, the Argentine Ministry of the Economy, the Secretariat of Energy, ENRE, Edesur, and other distribution companies signed an agreement to create a mechanism to pay off debt corresponding to the framework agreement for the period, while the companies assume the commitment to allocate the funds to electric service works

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and maintain the network that supplies these neighborhoods with collective meters and other sensitive zones in the concession areas. According to the applicable regulations, this does not imply or extend downstream responsibility for those joint meters. In December 2020, Ar$ 1.5 billion (US$ 17.842 million) were recorded in other revenues as per this agreement. Subsequently, on December 9, 2021, through resolution No. 1,199, the Ministry of Energy and Mining approved the second disbursement of Ar$ 500 million corresponding to the Agreement for the Development of the Preventive and Corrective Work Plan of the Electricity Distribution Network of the Metropolitan Area of Buenos Aires, celebrated on December 22, 2020. Payment was made on December 29, 2021.

In March 2021, ENRE Resolution No. 79/2021 established a remuneration scheme, modifying only the Stabilized Seasonal Price, which was readjusted by 9% through resolution No. 106/2021, modifying on this occasion the Distribution Added Value that Edesur receives, pending the Comprehensive Tariff Renegotiation Process.

Through Resolution Nos. 263/2021 and 266/2021, ENRE achieved new rate schedules applied as of August 1, 2021, which only modified the Stabilized Seasonal Price for demands greater than 300 kWh per month provided under the Resolution of Secretary of Energy No. 748/2021. This did not change the VAD received by Edesur but increased the average rate from Ar$ 5,020 to Ar$ 5,176/kWh (+3.1%).

On April 22, 2021, ANEEL approved the tariff adjustment of Enel Distribution Ceara. As a result, the rate increased by 8.95% on average for all customers, including an average adjustment of 10.21% for medium- and high-voltage consumers, and 8.54% for low-voltage consumers.

On June 29, 2021, ANEEL approved the tariff adjustment of Enel Distribution Sao Paulo, effective as of July 4, 2021, resulting in a rate increase of 9.44% on average for all consumers, including an average adjustment of 3.67% for medium- and high-voltage consumers, and 11.38% for low-voltage consumers.

On October 21, 2021, ANEEL approved the rate adjustment of Enel Distribution Goias, effective as of October 22, 2021. The result led to a rate increase of 16.45% on average for all consumers, including an average adjustment of 14.21% for medium- and high-voltage consumers, and 17.32% for low-voltage consumers.

For additional information relating to the regulatory frameworks in the countries where we operate, see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework.”

d.Economic Conditions

Macroeconomic conditions, such as economic growth or recession, changes in employment levels, and inflation or deflation in the countries where we operate, may significantly affect our operating results. The variation of a local currency against the U.S. dollar may impact our operating results, as well as our assets and liabilities. For example, a devaluation of local currencies against the U.S. dollar increases capital expenditure plans and the cost of servicing U.S. dollar debt. For additional information, see “Item 3. Key Information — C. Risk Factors — South American economic fluctuations, political instability, and corruption scandals may affect our results of operations, financial condition, and the value of our securities.” and “—Foreign exchange risk may unfavorably affect our results and the U.S. dollar value of dividends payable to ADS holders.”

Local Currency Exchange Rate

Variations in the parity of the U.S. dollar and the local currency in each of the countries in which we operate may impact our operating results and overall financial position. The impact will depend on the level at which tariffs are pegged to the U.S. dollar, U.S. dollar-denominated assets and liabilities, and the translation of our foreign subsidiaries’ financial statements for consolidation purposes in the presentation currency, which is the U.S. dollar.

As of December 31, 2021, our consolidated debt totaled US$ 7,604 million (including US$ 1,269 million from Enel Brasil), of which 32.0% was denominated in reais, 27.1% in U.S. dollars, 21.7% in Colombian pesos, 10.2% in euro, 8.9% in soles, 0.1 in Chilean pesos (including UF), and none in Argentine pesos.

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The following table sets forth the closing and average local currencies per U.S. dollar exchange rates for the years indicated:

	Local Currency U.S. Dollar Exchange Rates
	2021		2020		2019
	Average	Year End	Average	Year End	Average	Year End
Argentina (Argentine pesos per U.S. dollar)	102.69	102.72	84.07	84.15	59.88	59.89
Brazil (Brazilian reais per U.S. dollar)	5.39	5.58	5.16	5.20	3.94	4.03
Colombia (Colombian pesos per U.S. dollar)	3,743.86	3,981.16	3,693.52	3,432.50	3,281.39	3,277.14
Peru (Peruvian soles per U.S. dollar)	3.88	4.00	3.50	3.62	3.34	3.32
Chile (Chilean pesos per U.S. dollar)	759.06	844.69	790.92	710.95	702.63	748.74

Sources: Central Bank of each country

The functional currency of the NCRE subsidiaries in Central America is the U.S. dollar.

The following table sets forth the effect recognized as “Foreign currency translation gains (losses)” in our consolidated statements of comprehensive income for translating the financial statements of our foreign subsidiaries for consolidation purposes to the presentation currency, which is the U.S. dollar:

	Foreign currency translation gains (losses)
	2021	2020	2019
	in thousands of US$
Argentina	(275,362)	(356,295)	(163,865)
Brazil	(331,529)	(1,646,889)	(295,801)
Colombia	(425,138)	(77,416)	(235,692)
Peru	(161,422)	(169,315)	(69,775)
Chile	—	—	128
Total	(1,193,451)	(2,249,915)	(765,005)

The financial statements of foreign companies with functional currencies other than the U.S. dollar |are translated as follows: (i) for assets and liabilities, the exchange rate on the closing date of the financial statements is used; (ii) for items in the comprehensive income statement, the average exchange rate for the period is used; (iii) equity remains at the historical exchange rate from the date of acquisition or contribution; and (iv) for retained earnings, the average exchange rate at the date of origination is used. However, in Argentina, due to the country’s recognition as a hyperinflationary economy, the treatment is different, as explained in further detail below.

Calculation of the appreciation or devaluation of foreign currencies against the U.S. dollar for one period with respect to the previous one is made by determining the percentage change between the reciprocals of the values of the U.S. dollar per any given foreign currency. It is a measure of the percent change between the two periods in the amount of foreign currency needed to exchange for one U.S. dollar. A positive percent change means that the foreign currency appreciated with respect to the U.S. dollar. A negative percent change implies that the foreign currency depreciated with respect to the U.S. dollar.

The following table shows the appreciation or depreciation of 2021 versus 2020 and 2020 versus 2019 for the closing and average local currencies per U.S. dollar:

	Appreciation/(Depreciation) per U.S. dollar (in %)
	2021/2020		2020/2019
	Average	Year End	Average	Year End
Argentine pesos	(18.1)	(18.1)	(28.8)	(28.8)
Brazilian reais	(4.3)	(6.9)	(23.6)	(22.4)
Colombian pesos	(1.3)	(13.8)	(11.2)	(4.5)
Peruvian soles	(9.8)	(9.4)	(4.6)	(8.5)
Chilean pesos	4.2	(15.8)	(11.2)	5.3

When the impacts of the appreciation or depreciation are significant, they are disclosed and explained in the analysis of results of operations below.

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Hyperinflation in Argentina

Since July 2018, the Argentine economy has been considered a hyperinflationary economy according to the criteria set out in the International Accounting Standard (IAS) 29, “Financial Information on Hyperinflationary Economies (“IAS 29”).” This determination was carried out based on qualitative and quantitative criteria that include an accumulated inflation rate of over 100% in three years. Please see Note 2.9 of the Notes to our consolidated financial statements for further information on the conversion policy of financial statements denominated in foreign currency.

The general price indices as of December 31, 2019, 2020, and 2021 are as follows:

Year	General Price Index
From January to December 2019	53.64%
From January to December 2020	36.13%
From January to December 2021	50.95%

For the year ended December 31, 2021, the application of IAS 29 resulted in a pre-tax gain on the indexation of assets and liabilities of US$ 30.7 million (US$ 76.7 million and US$ 124.5 million at year-end 2020 and 2019, respectively). See Note 32 of the Notes to our consolidated financial statements.

For consolidation purposes and as a result of the application of IAS 29, the results and the financial situation of our Argentine subsidiaries were converted to Argentine pesos at the closing exchange rate (Ar$/US$) as of December 31, 2021, and 2020, under IAS 21 “Effects of variations in foreign currency exchange rates” when referring to a hyperinflationary economy. Previously, the results of our Argentine subsidiaries were converted at an average exchange rate for the period, as is the case for the translation of the results for our subsidiaries in other countries whose economies are not considered hyperinflationary.

Considering that our presentation and functional currency do not correspond to a hyperinflationary economy according to the IAS 29 guidelines, restating comparative periods is not required in our consolidated financial statements.

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2. Analysis of Results of Operations for the Years Ended December 31, 2021, and 2020.

Consolidated Revenues and other operating income

Generation and Transmission Business

The following table sets forth the electricity sales of our subsidiaries and the corresponding changes for the years ended December 31, 2021, and 2020:

	Electricity sales during the year ended December 31,
	2021	2020	Change	Change
	(in GWh)			(in %)
Costanera (Argentina)	5,695	6,518	(823)	(12.6)
El Chocón (Argentina)	2,028	2,924	(896)	(30.6)
Dock Sud (Argentina)	5,378	4,461	916	20.5
EGP Cachoeira Dourada (Brazil)(1)	7,389	11,896	(4,507)	(37.9)
Fortaleza (Brazil)	5,014	3,636	1,378	37.9
EGP Volta Grande (Brazil)	1,512	2,000	(488)	(24.4)
Brazil NCRE Subsidiaries (Brazil)(2)	12,481	—	12,481	n.a.
Emgesa (Colombia)	17,589	17,539	50	0.3
EGP Colombia (Colombia)(3)	97	—	97	n.a.
Enel Generation Peru (Peru)	9,905	9,642	263	2.7
Enel Generation Piura (Peru)	715	616	99	16.1
EGP Peru (Peru)(3)	814	—	814	n.a.
EGP Costa Rica (Costa Rica)(3)(4)	168	—	168	n.a.
EGP Guatemala (Guatemala)(3)(4)	950	—	950	n.a.
EGP Panama (Panama)(3)(4)	1,519	—	1,519	n.a.
Total	71,254	59,232	12,022	20.3

(1) As of December 31, 2020, the figure reported was 19,660 GWh in cumulative terms, which included 7,764 GWh corresponding to the energy that EGP Cachoeira Dourada S.A. brokered in the Brazilian electricity market. As of 2021, this intermediation business is carried out by Enel Trading Brasil, so for comparative purposes, the aforementioned physical sales figures for 2020 have been excluded.

(2) Prior to the merger of EGP Brasil with and into Enel Brasil in November 2021, the Brazil NCRE Subsidiaries were held by EGP Brasil.

(3) Companies from Costa Rica, Guatemala, and Panama, participate in their local NIS (Costa Rica), NIS (Guatemala), and NIS (Panama) markets respectively, and additionally are part of the MER, which is a regional market that covers the 6 Central American countries.

(4) The market share of the EGP Américas companies that were incorporated on April 1, 2021, has not been incorporated, as nine months of operation are not representative of the actual market share held in each of their countries.

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Distribution Business

The following table sets forth the electricity sales of our subsidiaries, by country, and their corresponding variations for the years ended December 31, 2021, and 2020:

	Electricity sales during the year ended December 31,
	2021	2020	Change	Change
	(in GWh)			(in %)
Edesur (Argentina)	16,735	15,888	847	5.3
Enel Distribution Rio (Brazil)	11,489	11,228	261	2.3
Enel Distribution Ceara (Brazil)	12,731	11,866	865	7.3
Enel Distribution Goias (Brazil)	15,076	14,469	607	4.2
Enel Distribution Sao Paulo (Brazil)	41,087	40,350	737	1.8
Codensa (Colombia)	14,598	13,834	764	5.5
Enel Distribution Peru (Peru)	8,130	7,578	552	7.3
Total	119,846	115,213	4,632	4.0

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The following table sets forth the revenues and other operating income by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2021, and 2020:

	Year ended December 31,
	2021	2020	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	228	231	(3)	(1.3)
Costanera	105	113	(8)	(7.1)
El Chocón	42	49	(7)	(14.3)
Dock Sud	79	66	13	19.7
Other	2	3	(1)	(33.3)
Generation and Transmission Business in Brazil	2,550	1,106	1,444	130.6
EGP Cachoeira Dourada	1,428	812	616	75.9
Fortaleza	327	187	140	74.9
Cien	55	53	2	3.8
EGP Volta Grande	81	62	19	30.6
Brazil NCRE Subsidiaries(1)	540	-	540	n.a.
Enel Trading Brasil	827	-	827	n.a.
Other	(708)	(8)	(700)	(8,750.0)
Generation and Transmission Business in Colombia	1,266	1,159	107	9.2
Emgesa	1,262	1,159	103	8.9
EGP Colombia	30	-	30	n.a.
Other	(26)	-	(26)	n.a.
Generation and Transmission Business in Peru	573	505	68	13.5
Enel Generation Peru	431	408	23	5.6
Enel Generation Piura	74	63	11	17.5
Chinango	47	41	6	14.6
EGP Peru	33	-	33	n.a.
Other	(12)	(7)	(5)	(71.4)
Generation and Transmission Business in Central America	233	-	233	n.a.
EGP Costa Rica	17	-	17	n.a.
EGP Guatemala	108	-	108	n.a.
EGP Panama	149	-	149	n.a.
Other	(41)	-	(41)	n.a.
Total Generation and Transmission Business reportable segment	4,850	3,001	1,849	61.6
Distribution Business in Argentina	794	801	(7)	(0.9)
Edesur	794	801	(7)	(0.9)
Distribution Business in Brazil(2)	8,762	6,834	1,928	28.2
Enel Distribution Rio	1,581	1,253	328	26.2
Enel Distribution Ceara	1,512	1,166	346	29.7
Enel Distribution Goias	1,820	1,394	426	30.6
Enel Distribution Sao Paulo	3,849	3,021	828	27.4
Distribution Business in Colombia	1,707	1,547	160	10.3
Codensa	1,707	1,547	160	10.3
Distribution Business in Peru	895	887	8	0.9
Enel Distribution Peru	895	887	8	0.9
Total Distribution Business reportable segment	12,158	10,069	2,089	20.7
Less: consolidation adjustments and non-core activities	(816)	(778)	(38)	(4.9)
Total Revenues and other operating income	16,192	12,292	3,900	31.7

(1) Prior to the merger of EGP Brasil with and into Enel Brasil in November 2021, the Brazil NCRE Subsidiaries were held by EGP Brasil.

(2) During 2021, we reclassified from financial income to operating income the value to be recovered of certain financial assets related to the concession contracts of the electricity distribution subsidiaries in Brazil. As a consequence of such reclassification, we retrospectively reclassified in the consolidated statements of comprehensive income the amount of ThUS$ 99,071 from financial income to operating income for the year ended December 31, 2020. Please refer to Note 2.2.c of the Notes to our consolidated financial statements for further detail.

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Generation and Transmission Business: Revenues

In Argentina, revenues and other operating income decreased by US$ 3 million, or 1.2%, in 2021 compared to 2020, primarily due to lower revenues of:

(i) US$ 8 million, or 7.1%, from Costanera mainly due to lower revenues of:

a) US$ 23 million as a result of the devaluation of the Argentine peso against the U.S. dollar;

b) US$ 14 million from 823 GWh of lower volumes of physical energy sales as a result of lower generation stemming from lower dispatch requirement of CAMMESA mainly for combined cycle generation facilities; and

c) US$ 1 million as a result of Resolution No. 12/2019, which established that generation companies must rely on CAMMESA to supply them with fuel.

These decreases in revenues and other operating income were partially offset by higher revenues of:

d) US$ 26 million from the implementation of Resolution No. 440/2021, which established that the tariffs maintained in Argentine pesos for energy and power were adjusted by 29% as of February 2021; and

e) US$ 4 million due to the effect of inflation.

(ii) US$ 7 million, or 14.3%, from El Chocón mainly due to lower revenues of:

a) US$ 9 million as a result of the devaluation of the Argentine peso against the U.S. dollar; and

b) US$ 3 million as a result of Resolution No. 12/2019, which established that generation companies must rely on CAMMESA to supply them with fuel.

These decreases in revenues and other operating income were partially offset by higher revenues of:

c) US$ 5 million from the implementation of Resolution No. 440/2021, which established that the values of energy and power that are maintained in Argentine pesos can be readjusted retroactively by 29% from February 2021.

These decreases in revenues and other operating income were partially offset by:

(i) an increase of US$ 13 million, or 19.7%, from Dock Sud, which is mainly due to higher revenues of:

a) US$31 million from 917 GWh of higher volumes of energy sales of in conjunction with the increase of tariffs from the implementation of Resolution No. 440/2021, which established that the values of energy and power that are maintained in Argentine pesos can be readjusted retroactively by 29% from February 2021.

This increase in revenues and other operating income was partially offset by lower revenues of:

b) US$ 18 million as a result of the devaluation of the Argentine peso against the U.S. dollar.

In Brazil, revenues and other operating income increased by US$ 1,445 million, primarily explained by higher revenues of:

(i) US$ 616 million, or 75.9%, of higher volumes of physical energy sales from EGP Cachoeira Dourada mainly due to higher revenues of:

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a) US$ 854 million of higher sales to Brazil’s interconnected system as a result of energy imports from Argentina and Uruguay.

This increase in revenues and other operating income was partially offset by lower revenues of:

b) US$ 174 million from 4,507 GWh of lower volume of physical sales to the regulated market mainly due to the COVID-19 pandemic and the water crisis in Brazil; and

c) US$ 64 million as a result of the devaluation of the Brazilian real against the U.S. dollar

(ii) US$ 140 million, 74.9%, from Fortaleza mainly as a result of higher revenues of:

a) US$ 80 million from 1,378 GWh of higher volumes of physical energy sales due to an increase in demand that resulted in higher generation and a surplus of energy that was sold in the spot market;

b) US$ 68 million for price readjustments; and

c) US$ 7 million for recovery of PIS-COFINS taxes.

These increases in revenues and other operating income were partially offset by lower revenues of:

d) US$ 15 million due to the devaluation of the Brazilian real against the U.S. dollar.

(iii) US$ 540 million from the Brazil NCRE Subsidiaries mainly as a result of the addition of physical energy sales of 12,481 GWh from the merger of EGP Américas with Enel Américas in April 2021.

(iv) US$ 19 million, or 30.6%, from EGP Volta Grande mainly due to higher revenues of:

a) US$ 17 million due to the update of concession assets (Return for the Bonus Payment), stemming from the increase in the applicable CPI that in 2021 reached 10% compared to 5% in 2020; and

b) US$ 5 million from higher sales prices.

These increases in revenues and other operating income were partially offset by lower revenues of:

c) US$ 3 million resulting from the devaluation of the Brazilian real against the U.S. dollar.

(v) US$ 827 million in energy sales in the spot market in the second half of 2021 from Enel Trading Brasil as a result of the water crisis in Brazil.

These increases in revenues and other operating income were offset by lower revenues of:

(vi) US$ 700 million mainly due to the elimination of related party transactions between these companies.

In Colombia, revenues and other operating income increased by US$ 107 million, or 9.2%, in 2021 compared to 2020, mainly due to higher revenues of:

(i) US$ 119 million from Emgesa as a result of a higher average sales price;

(ii) US$ 30 million from EGP Colombia mainly as a result of the addition in 2021 of physical energy sales of 97 GWh due to the merger of EGP Américas with Enel Américas in April 2021; and

(iii) US$ 3 million from 50 GWh of higher volumes of physical energy sales by Emgesa.

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These increases in revenues and other operating income were partially offset by lower revenues of:

(iv) US$ 26 million mainly due to the elimination of related party transactions between these companies;

(v) US$ 16 million due to the devaluation of the Colombian peso against the U.S. dollar; and

(vi) US$ 3 million in insurance indemnity income received from General Electric in 2020 by Emgesa that did not recur in 2021.

In Peru, revenues and other operating income increased by US$ 68 million, or 13.5%, in 2021 compared to 2020, primarily due to higher revenues of:

(i) US$ 33 million from EGP Peru mainly as a result of the addition in 2021 of physical sales of 814 GWh due to the merger of EGP Américas with Enel Américas in April 2021.

(ii) US$ 23 million, or 5.4%, from Enel Generation Peru mainly due to higher revenues of:

a) US$ 64 million from 263 GWh of higher volumes of physical energy sales; and

b) US$ 4 million as a result of a higher average sales price.

These increases in revenues and other operating income were partially offset by lower revenues of:

c) US$ 45 million due to the devaluation of the new Peruvian sol against the U.S. dollar.

(iii) US$ 11 million, 17.5%, from Enel Generation Piura mainly due to higher revenues of:

a) US$ 12 million from 99 GWh of higher volumes of physical energy sales; and

b) US$ 6 million from the sale of gas to the Talara refinery.

These increases in revenues and other operating income were partially offset by lower revenues of:

c) US$ 7 million due to the devaluation of the new Peruvian sol against the U.S. dollar.

In Central America, other operating income increased by US$ 233 million in 2021, primarily due to the merger of EGP Américas into Enel Américas in April 2021, as follows:

(i) US$ 149 million from EGP Panama due to:

a) US$ 142 million from the addition in 2021 of physical energy sales of 1,519 GWh from the merger of EGP Américas with Enel Américas in April 2021; and

b) US$ 7 million from other operating revenues and other services.

(ii) US$ 108 million from EGP Guatemala mainly as a result of:

a) US$ 86 million from the addition in 2021 of physical energy sales of 950 GWh from the merger of EGP Américas with Enel Américas in April 2021; and

b) US$ 22 million from other operating revenues and other services.

(iii) US$ 17 million from EGP Costa Rica due to:

a) US$ 13 million from the addition in 2021 of physical energy sales of 168 GWh from the merger of EGP Américas with Enel Américas in April 2021; and

b) US$ 4 million from other operating revenues and other services.

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These increases in revenues and other operating income were offset by lower revenues of:

(iv) US$41 million mainly due to the elimination of related party transactions between these companies.

Distribution Business: Revenues

In Argentina, revenues and other operating income from Edesur decreased by US$ 7 million, or 0.9%, in 2021 compared to 2020, mainly due to lower revenues of:

(i) US$ 171 million due to the devaluation of the Argentine peso against the U.S. dollar;

This decrease in revenues and operating income was partially offset by higher revenues of:

(ii) US$ 118 million for tariff readjustments approved by the regulatory authority on a temporary basis, pending the next comprehensive tariff review. The readjustment established in ENRE Resolution No. 106 established an average readjustment of 9%, which led to a 21.8% increase in the VAD as of May 1, 2021; and

(iii) US$ 46 million from 847 GWh of higher volumes of physical energy sales.

In Brazil, revenues and other operating income increased by US$ 1,928 million, or 28.2%, in 2021 compared to 2020, due to higher revenues of:

(i) US$ 828 million, 27.4%, from Enel Distribution Sao Paulo due to higher revenues and other operating income of:

a) US$ 598 million due to an increase in tariffs as a result of the water crisis in Brazil;

b) US$ 215 million for 736 GWh of higher physical energy sales volumes and a higher average sales price due to an average tariff adjustment of 9.44% for all consumers, applied as of July 4, 2021;

c) US$ 128 million in other operating income mainly due to higher construction revenues recognized under the application of IFRIC 12 as a result of higher investments in the network compared to 2020; and

d) US$ 55 million in readjustments of the financial asset associated with IFRIC 12 as a result of a higher CPI registered in 2021 (10%) compared to 2020 (5%).

These increases in revenues and other operating income were partially offset by lower revenues of:

e) US$ 168 million as a result of the devaluation of the Brazilian real against the U.S. dollar.

(ii) US$ 426 million, or 30.6%, from Enel Distribution Goias mainly due to higher revenues and other operating income of:

a) US$ 272 million higher physical energy sales due to (x) US$ 186 million as a result of a higher average sales price due to the effects of inflation adjustments related to a 4.6% higher tariff adjustment in force since October 2020 and (y) US$ 86 million from 607 GWh of higher volumes of physical energy sales for as a result of the country's economic recovery;

b) US$ 163 million in other operating income, which is mainly explained by the increase in construction income due to the application of IFRIC 12 as a result of higher investments in the network compared to 2020; and

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c) US$ 72 million as a result of the compensatory CVA revenues (Compensation of Values of Lot A) due to regulations in Brazil applied during the water crisis in 2021.

These increases in revenues and other operating income were partially offset by lower revenues of:

d) US$ 81 million lower revenues due to the devaluation of the Brazilian real against the U.S. dollar.

(iii) US$ 346 million, or 29.7%, from Enel Distribution Ceara primarily due to higher revenues and other operating income of:

a) US$ 221 million as a result of a higher average sales price resulting from inflation and tariff readjustments;

b) US$ 87 million from 865 GWh of higher volumes of physical energy sales;

c) US$ 37 million of higher construction revenues recognized under the application of IFRIC 12;

d) US$ 37 million in readjustments of the financial asset associated with IFRIC 12 as a result of a higher CPI registered in 2021 (10%) compared to 2020 (5%); and

e) US$ 27 million of higher toll revenues.

These increases in revenues and other operating income were partially offset by lower revenues of:

f) US$ 63 million due to the devaluation of the Brazilian real against the U.S. dollar.

(iv) US$ 328 million, or 26.2%, from Enel Distribution Rio mainly explained by higher revenues of:

a) US$ 141 million as a result of a higher average sales price resulting from inflation and tariff readjustments;

b) US$ 131 million from 261 GWh of higher volumes of physical energy sales;

c) US$ 53 million in readjustments of the financial assets associated with IFRIC 12 as a result of a higher CPI registered in 2021 (10%) compared to 2020 (5%);

d) US$ 53 million of higher construction revenues recognized under the application of IFRIC 12; and

e) US$ 16 million of higher toll revenues.

These increases in revenues and other operating income were offset by lower revenues of:

f) US$ 66 million due to the devaluation of the Brazilian real against the U.S. dollar.

In Colombia, revenues and other operating income from Codensa increased by US$ 160 million, or 10.3%, in 2021 compared to 2020, mainly due to higher revenues of:

(i) US$ 113 million from 764 GWh of higher physical energy sales as a result of a higher average sales price resulting from an increase in the Producer Price Index (PPI), to which sales prices are indexed);

(ii) US$ 54 million from increased investment recognition that was remunerated at a higher rate due to a greater regulatory base of assets; and

(iii) US$ 7 million from operations contracts related to leasing support infrastructure to the public transportation system Transmilenio.

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These increases in revenues and other operating income were offset by lower revenues of:

(iv) US$ 20 million due to the devaluation of the Colombian peso against the U.S. dollar.

In Peru, revenues and other operating income from Enel Distribution Peru increased by US$ 8 million, or 0.9%, in 2021 compared to 2020, principally due to higher revenues of:

(i) US$ 89 million from 552 GWh of higher physical energy sales as a result of a higher average sales price; and

(ii) US$ 18 million of higher costs for other services such as connections, maintenance, and reconnections.

These increases in revenues and other operating income were offset by lower revenues of:

(iii) US$ 99 million due to the devaluation of the new Peruvian sol against the U.S. dollar.

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Total Raw materials and consumables used

The following table sets forth our total raw materials and consumables used by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2021, and 2020:

	Year ended December 31,
	2021	2020	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	17	19	(2)	(10.5)
Costanera	5	5	(0)	-
El Chocón	4	5	(1)	(20.0)
Dock Sud	9	10	(1)	(10.0)
Other	(1)	(1)	-	n.a.
Generation and Transmission Business in Brazil	1,907	781	1,126	144.2
EGP Cachoeira Dourada	1,351	666	685	102.9
Fortaleza	210	119	91	76.5
Cien	-	-	-	n.a.
EGP Volta Grande	14	11	3	27.3
Brazil NCRE Subsidiaries(1)	294	-	294	n.a.
Enel Trading Brasil	746	-	746	n.a.
Other	(708)	(15)	(693)	(4,620.0)
Generation and Transmission Business in Colombia	408	413	(5)	(1.2)
Emgesa	408	413	(5)	(1.2)
EGP Colombia	25	-	25	n.a.
Other	(25)	-	(25)	n.a.
Generation and Transmission Business in Peru	175	162	13	8.0
Enel Generation Peru	151	140	11	7.9
Enel Generation Piura	24	23	1	4.3
Chinango	5	5	-	-
EGP Peru	3	-	3	n.a.
Other	(8)	(6)	(2)	(33.3)
Generation and Transmission Business in Central America	43	-	43	n.a.
EGP Costa Rica	-	-	-	n.a.
EGP Guatemala	50	-	50	n.a.
EGP Panama	21	-	21	n.a.
Other	(28)	-	(28)	n.a.
Total Generation and Transmission Business reportable segment	2,550	1,375	1,175	85.5
Distribution Business in Argentina	528	530	(2)	(0.4)
Edesur	528	530	(2)	(0.4)
Distribution Business in Brazil	6,574	4,937	1,637	33.2
Enel Distribution Rio	1,148	869	278	32.0
Enel Distribution Ceara	1,099	835	264	31.6
Enel Distribution Goias	1,469	1,027	442	43.0
Enel Distribution Sao Paulo	2,858	2,206	652	29.6
Distribution Business in Colombia	1,012	886	126	14.2
Codensa	1,012	886	126	14.2
Distribution Business in Peru	605	599	6	1.0
Enel Distribution Peru	605	599	6	1.0
Total Distribution Business reportable segment	8,719	6,953	1,766	25.4
Less: consolidation adjustments and non-core activities	(818)	(772)	(46)	(6.0)
Total Raw materials and consumables used	10,451	7,556	2,895	38.3

(1) Prior to the merger of EGP Brasil with and into Enel Brasil in November 2021, the Brazil NCRE Subsidiaries were held by EGP Brasil.

Generation and Transmission Business: Raw materials and consumables used

In Brazil, raw materials and consumables used increased by US$ 1,126 million, or 144.2%, in 2021 compared to 2020, mainly due to increases of:

(i) US$ 746 million from Enel Trading Brasil as a result of the costs of energy sales determined by prices established in short- and long-term contracts with customers and that were much lower than spot prices in the last quarter of 2021.

(ii) US$ 685 million from EGP Cachoeira Dourada primarily as a result of:

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a) US$ 831 million from imported energy purchases, and

b) US$ 60 million from additional GSF (Generation Scaling Factor) compensatory benefits for hydrological risk granted in 2020 that did not recur in 2021.

These increases in raw materials and consumables used were primarily offset by decreases of:

c) US$ 146 million from lower volumes of energy in local purchases; and

d) US$ 60 million due to the devaluation of the Brazilian real against the U.S. dollar.

(iii) US$ 294 million from the Brazil NCRE Subsidiaries, primarily due to the merger of EGP Américas with Enel Américas in April 2021, as follows:

a) US$267 million from energy purchases;

b) US$26 million in transportation expenses; and

c) US$1 million in other variable supplies and services. EGP Brasil was included in the merger with Enel Américas in April 2021.

(iv) US$ 91 million, or 76.5%, from Fortaleza mainly due to:

a) US$ 108 million from higher volumes of energy purchases due to higher energy demand.

This increase in raw materials and consumables used was primarily offset by decreases of:

b) US$9 million due to the devaluation of the Brazilian real against the U.S. dollar; and

c) US$ 8 million of lower fuel cost from a better mix of fixed supply contracts compared to those in effect in 2020.

(v) US$ 3 million, or 27.3%, from EGP Volta Grande due to higher prices of purchased energy.

These increases in raw materials and consumables used were offset by a decrease of:

(vi) US$ 693 million mainly due to the elimination of related party transactions between these companies.

In Colombia, raw materials and consumables used decreased by US$ 5 million, or 1.2%, in 2021 compared to 2020, mainly due to decreases of:

(i) US$ 25 million mainly due to the elimination of related party transactions between these companies;]

(ii) US$ 24 million related to lower energy purchases as a result of a lower average purchase price for US$ 60 million, partially offset by US$ 36 million from 887 GWh of higher volumes of physical energy purchases;

(iii) US$ 14 million from lower fuel consumption mainly due to lower generation of the Termozipa power plant as a result of a decrease in energy spot prices; and

(iv) US$ 6 million due to the devaluation of the Colombian peso against the U.S. dollar.

These decreases in raw materials and consumables used were partially offset by increases of:

(v) US$ 29 million of higher transportation expenses due to an increase in marginal costs;

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(vi) US$ 25 million from EGP Colombia due to energy purchases to meet demand. EGP Colombia was included in the merger with Enel Américas in April 2021; and

(vii) US$ 10 million of higher other variable supplies and services.

In Peru, raw materials and consumables used increased by US$ 13 million, or 8.0%, in 2021 compared to 2020, primarily due to an increase of:

(i) US$ 11 million, or 7.9%, from Enel Generation Peru as a result of:

a) US$ 15 million of higher transportation expenses; and

b) US$ 12 million of higher fuel consumption due to higher production in thermal power plants as a result of increased demand.

These increases in raw materials and consumables used were partially offset by a decrease of:

c) US$ 16 million as a result of the devaluation of the new Peruvian sol against the U.S. dollar.

(ii) Enel Generation Piura was in line with the same period of the previous year.

In Central America, raw materials and consumables used increased by US$ 43 million primarily due to the merger of EGP Américas with Enel Américas in April 2021, as follows:

(i) US$ 50 million from EGP Guatemala as a result of:

a) US$ 37 million of energy purchases; and

b) US$ 13 million of transportation expenses and other services costs.

(ii) US$ 21 million from EGP Panama as a result of:

a) US$ 12 million of energy purchases

b) US$ 6 million of transportation expenses; and

c) US$ 3 million of other variable supplies and services.

These increases in raw materials and consumables used were partially offset by a decrease of:

(iii) US$ 28 million mainly due to the elimination of related party transactions between these companies.

Distribution Business: Raw materials and consumables used

In Argentina, raw materials and consumables used from Edesur decreased by US$ 2 million, or 0.4%, in 2021 compared to 2020, mainly due to a decrease of:

(i) US$ 116 million as a result of the devaluation of the Argentine peso against the U.S. dollar.

This decrease in raw materials and consumables used was partially offset by increases of:

(ii) US$ 90 million of higher energy purchases;

(iii) US$ 19 million of higher volumes of energy purchased; and

(iv) US$ 6 million of higher costs for other supplies and variable services due to the increase in sales volume.

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��

In Brazil, raw materials and consumables used increased by US$ 1,637 million, or 33.2%, in 2021 compared to 2020, due to increases of:

(i)US$ 652 million, or 29.6%, from Enel Distribution Sao Paulo mainly due to:

a) US$ 620 million of higher energy purchases from thermal power plants at higher prices as a result of lower hydrology;

b) US$ 128 million of higher other operating costs mainly due to higher construction costs recognized under the application of IFRIC 12; and

c) US$ 50 million of higher interruptions and reconnections costs.

These increases in raw materials and consumables used were partially offset by decreases of:

d) US$ 127 million due to the devaluation of the Brazilian real against the U.S. dollar; and

e) US$ 19 million of lower transportation costs due to a decrease in the volume of energy distributed.

(ii)US$ 442 million, or 43.0%, from Enel Distribution Goias mainly due to:

a) US$ 332 million of higher energy purchases at a higher average price and higher volumes

b) US$ 163 million of higher costs of other variable supplies and services due to higher construction costs recognized under the application of IFRIC 12; and

c) US$ 13 million of higher costs for interruptions and reconnections.

These increases in raw materials and consumables used were partially offset by a decrease of:

d) US$ 66 million as a result of the devaluation of the Brazilian real against the U.S. dollar.

(iii)US$ 278 million, or 32.0%, from Enel Distribution Rio mainly due to:

a) US$ 261 million of higher energy purchases due to US$ 176 million of higher volumes of physical energy purchases and US$ 85 million from a higher average purchase price as a result of readjustments related to inflation and worsening hydrology;

b) US$ 53 million of higher construction costs recognized under the application of IFRIC 12;

c) US$ 13 million of higher costs for disconnections and reconnection services; and

d) US$ 2 million of higher energy transportation cost due to higher fees for network use.

These increases in raw materials and consumables used were partially offset by a decrease of:

e) US$ 51 million due to the devaluation of the Brazilian real against the U.S. dollar.

(iv)US$ 264 million, or 31.6%, from Enel Distribution Ceara mainly explained by:

a) US$ 263 million of higher energy purchases due to US$ 174 million from a higher average purchase price due to an inflation readjustment and US$ 89 million of higher volumes of physical energy purchases;

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b) US$ 37 million of higher construction costs recognized under the application of IFRIC 12; and

c) US$ 13 million of higher energy transportation costs due to higher fees for network use.

These increases in raw materials and consumable uses were partially offset by a decrease of:

d) US$ 49 million due to the devaluation of the Brazilian real against the U.S. dollar.

In Colombia, raw materials and consumables used from Codensa increased by US$ 126 million, or 14.2%, in 2021 compared to 2020, mainly due to increases of:

(i)US$ 115 million of higher energy purchases at a higher average purchase price;

(ii)US$ 15 million of higher energy transportation costs as a result of increased payments for the incorporation of new construction units (assets used directly in the transmission system and that must be prorated proportionally among the system operators); and

(iii)US$ 13 million of higher costs for other supplies and services.

These increases in raw materials and consumables used were partially offset by a decrease of:

(iv)US$ 17 million as a result of the devaluation of the Colombian peso against the U.S. dollar.

In Peru, Raw materials and consumables used from Enel Distribution Peru increased by US$ 6 million, or 1.0%, mainly due to increases of:

(i)US$ 62 million of higher energy purchases at a higher average purchase price and higher volumes of physical energy purchases;

(ii)US$ 10 million of higher costs of other services such as connections, reconnections, and maintenance.

These increases in raw materials and consumables used were partially offset by a decrease of:

(iii)US$ 66 million as a result of the devaluation of the new Peruvian sol against the U.S. dollar.

Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense

Our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense are comprised of salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.

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The following table sets forth the employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2021, and 2020:

	Year ended December 31,
	2021	2020	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	268	158	110	69.6
Costanera	186	89	97	109.0
El Chocón	28	22	6	27.3
Dock Sud	48	42	6	14.3
Other	6	5	1	20.0
Generation and Transmission Business in Brazil	180	51	129	252.9
EGP Cachoeira Dourada	26	16	10	62.5
Fortaleza	20	17	3	17.6
Cien	13	14	(1)	(7.1)
EGP Volta Grande	4	3	1	33.3
Brazil NCRE Subsidiaries(1)	110	—	110	n.a.
Enel Trading Brasil	5	—	5	n.a.
Other	2	1	1	100.0
Generation and Transmission Business in Colombia	139	140	(1)	(0.7)
Emgesa	132	140	(8)	(5.7)
EGP Colombia	7	—	7	n.a.
Other	—	—	—	n.a.
Generation and Transmission Business in Peru	143	135	8	5.9
Enel Generation Peru	95	106	(11)	(10.4)
Enel Generation Piura	19	22	(3)	(13.6)
Chinango	8	9	(1)	(11.1)
EGP Peru	25	—	25	n.a.
Other	(4)	(2)	(2)	(100.0)
Generation and Transmission Business in Central America	58	—	58	n.a.
EGP Costa Rica	12	—	12	n.a.
EGP Guatemala	29	—	29	n.a.
EGP Panama	31	—	31	n.a.
Other	(14)	—	(14)	n.a.
Total Generation and Transmission Business reportable segment	788	484	304	62.8
Distribution Business in Argentina	334	339	(5)	(1.5)
Edesur	334	339	(5)	(1.5)
Distribution Business in Brazil	1,435	1,244	191	15.4
Enel Distribution Rio	336	289	47	16.3
Enel Distribution Ceara	244	232	12	5.2
Enel Distribution Goias	296	282	14	5.0
Enel Distribution Sao Paulo	559	441	118	26.8
Distribution Business in Colombia	276	286	(10)	(3.5)
Codensa	276	286	(10)	(3.5)
Distribution Business in Peru	136	146	(10)	(6.8)
Enel Distribution Peru	136	146	(10)	(6.8)
Total Distribution Business reportable segment	2,181	2,015	166	8.2
Less: consolidation adjustments and non-core activities	108	85	23	27.1
Total employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expenses	3,077	2,584	493	19.1

(1) Prior to the Merger of EGP Brasil with and into Enel Brasil in November 2021, the Brazil NCRE Subsidiaries were held by EGP Brasil.

Consolidated depreciation, amortization, and impairment reached US$ 1,438 million for the period ended December 31, 2021, an increase of US$ 337 million compared to 2020.

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Depreciation and amortization reached US$ 993 million for the period ended December 31, 2021, an increase of US$ 135 million compared to 2020 mainly due to the addition of US$ 99 million of depreciation and amortization from EGP Américas companies that were acquired in the merger of EGP Américas with and into Enel Américas on April 1, 2021.

Generation and Transmission Business

Consolidated employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased US$ 304 million, or 62.8%, in 2021 compared to 2020, mainly due to increases of:

In Argentina, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased by US$ 97 million from Costanera mainly due to increases of:

(i) US$ 82 million from the recognition of an impairment loss mainly explained by the inflationary restatement of non-monetary assets, as a result of the application of IAS 29 "Financial Reporting in Hyperinflationary Economies" in Argentina. These assets were restated as of February 2003, while the company’s revenues have not increased in the same proportion;

(ii) US$ 13 million in depreciation due to higher activations; and

(iii) US$ 7 million in staff costs as a result of by US$ 13 million in wage increases, partially offset by a US$ 6 million decrease from the devaluation of the Argentine peso against the U.S. dollar.

These increases were partially offset by;

(iv) US$5 million of lower other expenses by nature due to the devaluation of the Argentine peso against the U.S. dollar.

In Brazil, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased by US$ 129 million primarily due to increases of:

(i) US$ 110 million from the Brazil NCRE Subsidiaries due to increases from the merger of EGP Américas with Enel Américas in April 2021, as follows:

a) US$ 63 million in depreciation;

b) US$ 25 million in salaries and social security of workers; and

c) US$ 22 million mainly for US$ 15 million in independent outsourced services and US$ 7 million in maintenance and repair costs.

(ii) US$ 10 million from EGP Cachoeira Dourada mainly due to increases of:

a) US$7 million in depreciation due to higher activations, partially offset by US$ 1 million as a result of the devaluation of the Brazilian real against the U.S. dollar; and

b) US$ 2 million in other expenses by nature from higher costs of legal services and other services.

(iii) US$ 5 million from Enel Trading Brasil mainly due to an increase of:

a) US$ 3 million in impairment losses resulting from the application of IFRS 9; and

b) US$ 2 million in salaries and social security payments for workers.

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In Central America, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased by US$ 58 million, mainly due to the merger of EGP Americas into Enel Americas in April 2021, as follows:

(i) US$ 31 million from EGP Panama consisting of:

a) US$ 13 million in depreciation;

b) US$ 11 million in outsourced independent services; and

c) US$ 7 million in salaries and social security of workers.

(ii) US$ 29 million from EGP Guatemala consisting of:

a) US$ 16 million in outsourced independent services;

b) US$ 9 million in depreciation; and

c) US$ 4 million in salaries and social security payments for workers.

(iii) US$ 12 million from EGP Costa Rica consisting of:

a) US$ 5 million in outsourced independent services;

b) US$ 5 million in depreciation; and

c) US$ 2 million in salaries and social security payments for workers.

These increases were partially offset by a decrease of:

(iv) US$ 14 million due to the elimination of related party transactions between these companies.

Distribution Business

Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased US$ 166 million, or 8.2%, in 2021 compared to 2020, mainly due to the following:

In Brazil, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense increased by US$ 191 million, or 15.4%, in 2021 compared to 2020, primarily due to increases of:

(i) US$ 118 million from Enel Distribution Sao Paulo due to increases of:

a) US$ 63 million in employee benefits expenses and other work capitalized mainly due to (i) US$18 million in provisions for the restructuring plan associated with the digitalization strategy and (ii) US$ 89 million as a result of voluntary migration by employees to a defined contribution plan in 2020, that did not recur in 2021, partially offset by (i) US$11 million due to higher efficiency from digitalization process; (ii) US$ 8 million from the devaluation of the Brazilian real against the U.S. dollar; and (iii) US$25 million in capitalization of personnel expenses allocated to investment projects.

b) US$ 65 million in impairment charges on financial assets due to the increase in the expected credit loss resulting from the current business scenario in Brazil.

These increases were partially offset by a decrease of:

c) US$ 10 million due to the devaluation of the Brazilian real against the U.S. dollar.

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(ii) US$ 47 million from Enel Distribution Rio principally due to an increase of:

a) US$ 44 million in impairment charges resulting from the periodic evaluation of financial assets.

(iii) US$ 14 million from Enel Distribution Goias mainly due to increases of:

a) US$11 million in depreciation as a result of higher asset activations, partially offset by US$ 3 million due to the devaluation of the Brazilian real against the U.S. dollar.

b) US$ 15 million in impairment charges resulting from the periodic evaluation of financial assets.

These increases were partially offset by decreases of:

c) US$ 5 million due to the devaluation of the Brazilian real against the U.S. dollar; and

d) US$ 5 million in fines and maintenance costs.

(iv) US$ 12 million from Enel Distribution Ceara mainly due to increases of:

a) US$ 16 million in impairment charges resulting from the periodic evaluation of financial assets; and

b) US$ 5 million in depreciation as a result of higher asset activations, partially offset by US$ 3 million due to the devaluation of the Brazilian real against the U.S. dollar.

These increases were partially offset by decreases of:

c) US$ 3 million due to the devaluation of the Brazilian real against the U.S. dollar; and

d) US$ 3 million due to a reversal in 2021 of provisions for regulatory contingency established in 2020.

In Colombia, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense decreased by US$ 10 million, or 3.6%, in 2021 compared to 2020 mainly due to a decrease of:

(i) US$ 11 million from Codensa in staffing costs mainly due to restructuring costs recorded in 2020 that did not recur in 2021.

In Peru, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense decreased by US$ 10 million, or 6.8%, in 2021 compared to 2020 mainly due to a decrease of:

(i) US$ 8 million in Enel Distribution Peru due to a reversal in 2021 of provisions for impairment of financial assets established in 2020.

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Operating Income

The following table sets forth our operating income by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2021, and 2020:

	Year ended December 31,
	2021	2020	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	(57)	53	(110)	n.a.
Costanera	(86)	19	(105)	n.a.
El Chocón	10	22	(12)	(54.5)
Dock Sud	23	14	9	64.3
Other	(4)	(2)	(2)	(100.0)
Generation and Transmission Business in Brazil	464	273	191	70.0
EGP Cachoeira Dourada	52	130	(78)	(60.0)
Fortaleza	97	51	46	90.2
Cien	42	39	3	7.7
EGP Volta Grande	63	48	15	31.3
Brazil NCRE Subsidiaries(1)	136	—	136	n.a.
Enel Trading Brasil	76	—	76	n.a.
Other	(2)	5	(7)	n.a.
Generation and Transmission Business in Colombia	718	607	111	18.1
Emgesa	723	607	116	19.1
EGP Colombia	(3)	—	(3)	n.a.
Other	(2)	—	(2)	n.a.
Generation and Transmission Business in Peru	255	208	47	22.6
Enel Generation Peru	185	162	23	14.2
Enel Generation Piura	31	19	12	63.2
Chinango	34	27	7	25.9
EGP Peru	5	—	5	n.a.
Other	-	—	-	n.a.
Generation and Transmission Business in Central America	132	—	132	n.a.
EGP Costa Rica	5	—	5	n.a.
EGP Guatemala	29	—	29	n.a.
EGP Panama	97	—	97	n.a.
Other	1	—	1	n.a.
Total Generation and Transmission Business reportable segment	1,512	1,141	371	32.5
	-
Distribution Business in Argentina	(68)	(68)	-	-
Edesur	(68)	(68)	-	-
Distribution Business in Brazil	753	652	101	15.5
Enel Distribution Rio	98	94	4	4.3
Enel Distribution Ceara	169	99	70	70.7
Enel Distribution Goias	55	85	(30)	(35.3)
Enel Distribution Sao Paulo	431	374	57	15.2
Distribution Business in Colombia	419	375	44	11.7
Codensa	419	375	44	11.7
Distribution Business in Peru	154	141	13	9.2
Enel Distribution Peru	154	141	13	9.2
Total Distribution Business reportable segment	1,258	1,100	158	14.4
Less: consolidation adjustments and non-core activities	(106)	(89)	(17)	(19.1)
Total operating income	2,664	2,151	513	23.8

(1) Prior to the Merger of EGP Brasil with and into Enel Brasil in November 2021, the Brazil NCRE Subsidiaries were held by EGP Brasil.

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Generation and Transmission Business

Operating income from the generation and transmission business increased US$ 371 million, or 32.5%, in 2021 compared to 2020, mainly due to the following:

In Argentina, operating income decreased by US$ 110 million mainly attributable to:

(i) lower revenues as a result of the devaluation of the Argentine peso against the U.S. dollar;

(ii) higher maintenance costs and lower revenues from Costanera mainly due to 823 GWh of lower physical energy sales as a result of lower generation because of a lower dispatch requirement from CAMMESA, mainly for combined-cycle generation facilities; and

(iii) an US$ 82 million loss due to the application of recoverability tests recognized in Costanera due to recognition of impairment in long-term assets.

In Brazil, operating income increased by US$ 191 million, or 70.0%, mainly due to:

(i) US$ 136 million from the addition of the Brazil NCRE Subsidiaries as a result of EGP Américas merging with and into Enel Américas on April 1, 2021; and

(ii) US$ 76 million from Enel Trading Brasil for the sale of electricity at higher spot prices offered by the market in the second half of 2021 as a result of the water crisis in Brazil.

These increases in operating income were partially offset by a decrease of:

(iii) US$ 77 million from EGP Cachoeira Dourada as a result of higher volumes of energy purchases at higher prices compared to 2020.

In Colombia, operating income increased by US$ 111 million, or 18.1%, in 2021 compared to 2020, mainly as a result of a higher average sales price and lower purchase prices to meet our supply obligations.

In Peru, operating income increased by US$ 47 million, or 22.6%, in 2021 compared to 2020, as a result of a higher average sales price and higher volumes of physical energy sales.

In Central America, operating income increased by US$ 132 million in 2021 compared to 2020, mainly attributable to revenues at EGP Panama, EGP Guatemala, and EGP Costa Rica, which were added in 2021 as a result of the merger of EGP Américas with and into Enel Américas on April 1, 2021.

Distribution Business

Operating income increased US$ 158 million, or 14.4%, in 2021 compared to 2020, mainly due to the following:

In Brazil, operating income increased US$ 101 million, or 15.5%, in 2021 compared to 2020, mainly due to:

(i) an increase of US$ 57 million from Enel Distribution Sao Paulo mainly due to the effects of the economic recovery, which resulted in a higher volume of physical sales for 736 GWh and higher average sales prices, due to a tariff adjustment of 9.44%. This was partially offset by higher energy purchases due to lower hydrology and higher prices, higher personnel expenses associated with the digitalization strategy and the voluntary migration of employees under a defined contribution plan, the impairment caused by the valuation of financial assets, and the effects of the devaluation of the Brazilian real against the U.S. dollar.

(ii) an increase of US$ 70 million from Enel Distribution Ceara mainly due to the effects of the economic recovery, which resulted in higher physical sales volumes for 865 GWh and higher average sales prices as a result of inflation and tariff readjustments. This was partially offset by higher energy purchases,

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mainly physical and higher average purchase prices, the impairment caused by the valuation of financial assets and higher depreciations due to higher activations, and the effects of the devaluation of the Brazilian real against the dollar. 

These increases in operating income were partially offset by;

(iii) a decrease of US$ 30 million from Enel Distribution Goias, which resulted in higher energy purchase expenditure, higher average prices, the impairment caused by the valuation of financial assets and higher depreciations due to higher activations, and the effects of the devaluation of the Brazilian real against the dollar. This was partially offset by higher physical sales for 607 GWh and improved average sales prices as a result of the effects of the devaluation of the Brazilian real against the U.S. dollar.

In Colombia, operating income from Codensa increased US$ 44 million, or 11.7%, in 2021 compared to 2020, mainly due to higher physical energy sales, a higher average sale price, and higher remuneration for assets, which were partially offset by higher energy purchases at a higher average purchase price.

Other Results

The following table sets forth our financial and other results for the years ended December 31, 2021, and 2020:

	Year ended December 31,
	2021	2020	Change	Change
	(in millions of US$)			(in %)
Financial results
Financial income(1)	295	222	73	32.9
Financial costs	(1,052)	(768)	(284)	(37.0)
Results for Hyperinflation	31	77	(46)	(59.7)
Net foreign currency exchange gains (losses)	(2)	57	(59)	n.a.
Total	(728)	(412)	(316)	(76.7)
Other
Other gains (losses)	3	5	(2)	(40.0)
Share of the profit of associates and joint ventures accounted for using the equity method	1	3	(2)	(66.7)
Total	4	8	(4)	(50.0)
Total other results	(723)	(404)	(319)	(79.0)

(1) During 2021, we reclassified from financial income to operating income the value to be recovered of certain financial assets related to the concession contracts of the electricity distribution subsidiaries in Brazil. As a consequence of such reclassification, we retrospectively reclassified in the consolidated statements of comprehensive income the amount of ThUS$ 99,071 from financial income to operating income for the year ended December 31, 2020. Please refer to Note 2.2.c of the Notes to our consolidated financial statements for further detail.

Financial Results

Our net total financial results decreased by US$ 316 million, or 76.5%, in 2021 compared to 2020, mainly due to:

(i) US$ 284 million of higher financial costs mainly attributable to increases of:

a) US$ 99 million from Edesur mainly explained by the financial update related of the debt with the energy supplier (CAMMESA);

b) US$ 97 million of higher financial expenses for hedging transactions mainly by Brazilian companies;

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c) US$ 56 million of higher financial expense due to (i) higher financial debt mainly in Enel Distribution Sao Paulo of US$ 37 million and (ii) US$ 19 million as a result of the merger of the EGP Américas with Enel Américas on April 1, 2021;

d) US$ 16 million of higher net financial expense on unguaranteed obligations mainly from Enel Distribution Ceara of US$ 12 million, Enel Distribution Goias of US$ 12 million, and Codensa of US$ 6 million, offset by lower expenses associated with net payments of unguaranteed obligations made by Emgesa of US$14 million; and

e) US$ 16 million of higher financial expense mainly due to debt owed to EFI by Enel Distribution Goias of US$ 12 million and from the incorporation of the EGP Américas companies as a result of the merger of the EGP Américas with Enel Américas on April 1, 2021, of US$ 4 million.

(ii) US$ 46 million in results for hyperinflation for an inflation adjustment attributed to non-monetary assets and liabilities and income statements due to the implementation of IAS 29 in Argentina. The decrease in 2021 compared to 2020 is a result of a decrease in the position of net liabilities exposed to inflation in Argentina.

(iii) a US$ 59 million decrease in exchange rate differences mainly due to:

a) US$ 34 million from EGP Cachoeira Dourada due to the update of accounts payable in foreign currency for the importation of energy from Argentina and Uruguay as a result of the devaluation of the Brazilian real against the U.S. dollar;

b) US$ 14 million in debt from our subsidiaries in Brazil with non-consolidated related companies; and

c) US$ 11 million in VOSA credits due to the devaluation of the Argentine peso against the U.S. dollar, as well as lower capital in U.S. dollars due to amortization;

These decreases in net total financial results were partially offset by an increase of:

(iv) US$ 73 million in financial income, primarily explained by increases of:

a) US$ 28 million for the monetary update of the regulatory assets of distribution companies in Brazil due to a CPI that reached 10% in 2021 compared to 5% in 2020;

b) US$ 25 million from interest obtained from financial investments in Argentine subsidiaries;

c) US$ 25 million for derivatives transactions in Enel Distribution Sao Paulo

d) US$ 10 million in interest receivable associated with clients for energy sales mainly by distribution subsidiaries in Brazil; and

e) US$ 10 million in financial income from the incorporation of the EGP Américas companies as a result of the merger of EGP Américas with and into Enel Américas on April 1, 2021.

These increases in net total financial results were partially offset by a decrease of:

(v) US$ 25 million in extraordinary income recognized in 2020 due to a change in the valuation of investments in Termoeléctrica Belgrano and Termoeléctrica San Martin that did not recur in 2021.

Other Non-Operating Results

Other non-operating results decreased by US$ 4 million, or 50.0%, in 2021 compared to 2020, mainly due to the sale of assets for US$ 2 million by Enel Generation Piura in 2020 that did not recur in 2021, and lower results of

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US$ 2 million for investments in Central Térmica Manuel Belgrano and Central Térmica San Martin, investments that at year-end 2020 were reclassified as financial assets at fair value through profit or loss.

Income Taxes

Total income tax expense increased US$ 239 million, or 42.2%, in 2021 compared to 2020, due to increased expenses of:

(i) US$ 109 million in income taxes and deferred taxes from subsidiaries in Argentina due to the adaptation of deferred taxes as a result of the tax reform approved by the Argentine Government that increased the nominal tax rate from 30% to 35%: US$ 101 million from Edesur, US$ 11 million from Costanera, US$ 4 million Central Dock Sud, partially offset by a US$ 7 million reduction from El Chocón;

(ii) US$ 119 million in tax expense due to better financial results: US$ 26 million from Enel Trading Brasil; US$ 17 million from Emgesa; US$ 15 million from Edesur; US$ 14 million from Enel Generation Peru; US$ 13 million from Fortaleza; US$ 9 million from Codensa; US$ 9 million from Enel Distribution Ceara; US$ 9 million from Enel Distribution Peru; and US$ 7 million from the Brazil NCRE Subsidiaries;

(iii) US$ 13 million in income taxes and deferred taxes from subsidiaries in Colombia due to an increase in the income tax rate from 30% to 35% for 2021 and the recognition of deferred taxes in 2021: US$ 12 million from Emgesa and US$ 1 million from Codensa; and

(iv) US$ 59 million in income tax expenses due to the merger of EGP Américas into Enel Américas on April 1, 2021.

These increases in tax expense were partially offset by a decrease of:

(v) US$ 61 million in income tax from EGP Cachoeira Dourada of US$ 38 million and from Enel Distribution Goias of US$ 23 million, due to lower income.

The effective tax rate was 41.5% in 2021 and 32.4% in 2020. The increases in income tax rates in 2021 mainly explain this increase.

The following table sets forth the tax effect of rates applied in other countries that result in a difference between domestic or nominal tax rates in Chile (4.2% for 2021 and 4.7% for 2020) and tax rates enacted in each foreign jurisdiction:

	Nominal Tax Rates		Tax effect of rates applied in other countries
	2021	2020	2021	2020
	(%)		(in millions of US$)
Argentina	35.0	30.0	20.2	(2.8)
Brazil	34.0	34.0	(48.3)	(27.9)
Colombia	31.0	32.0	(41.8)	(43.1)
Costa Rica	30.0	—	(0.1)	—
Guatemala	25.0	—	0.6	—
Panama	25.0	—	(2.1)	—
Peru	29.5	29.5	(8.9)	(7.9)
Total			(80.4)	(81.7)

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Net Income

The following table sets forth our consolidated income before income taxes, income taxes, and net income for the years ended December 31, 2021, and 2020:

	Year ended December 31,
	2021	2020	Change	Change
	(in millions of US$)			(in %)
Operating income	2,664	2,152	512	23.8
Other results	(723)	(404)	(319)	(79.0)
Income before income taxes	1,941	1,748	193	11.0
Income taxes	(806)	(567)	(239)	(42.2)
Net Income	1,135	1,181	(46)	(3.9)
Net income attributable to:
Net income attributable to the parent company	741	825	(84)	(10.2)
Net income attributable to non-controlling interests	394	356	38	10.7

Net income attributable to the parent company on a consolidated basis reached US$ 741 million, a decrease of 10.2% compared to 2020. This is mainly explained by higher asset impairment losses in Argentina, Brazil, and Peru, higher financial expenses in Brazil and Argentina, and higher taxes due to better performance of operations and tax rate changes in Argentina and Colombia.

3. Analysis of Results of Operations for the Years Ended December 31, 2020, and 2019.

Consolidated Revenues and other operating income

Generation and Transmission Business

The following table sets forth the electricity sales of our subsidiaries and the corresponding changes for the years ended December 31, 2020, and 2019:

	Electricity sales during the year ended December 31,
	2020	2019	Change	Change
	(in GWh)			(in %)
Costanera (Argentina)	6,518	6,210	308	5.0
El Chocón (Argentina)	2,924	2,528	396	15.7
Dock Sud (Argentina)	4,461	4,238	223	5.3
EGP Cachoeira Dourada (Brazil)(1)	11,896	13,400	(1,504)	(11.2)
Fortaleza (Brazil)	3,636	4,742	(1,106)	(23.3)
EGP Volta Grande (Brazil)	2,000	2,370	(370)	(15.6)
Emgesa (Colombia)	17,539	18,376	(837)	(4.6)
Enel Generation Peru (Peru)	9,642	10,541	(899)	(8.5)
Enel Generation Piura (Peru)	616	658	(42)	(6.4)
Total	59,232	63,063	(3,831)	(6.1)

(1) As of December 31, 2020, the figure reported was 19,660 GWh. (22,890 GWh. in 2019 ) in cumulative terms, which included 7,764 GWh. and 9,490 GWh. respectively corresponding to the energy that EGP Cachoeira Dourada S.A. brokered in the Brazilian electricity market. As of 2021, this intermediation business is carried out by Enel Trading Brasil, so for comparative purposes, the aforementioned physical sales figures for 2020 and 2019 have been excluded.

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Distribution Business

The following table sets forth the electricity sales of our subsidiaries, by country, and their corresponding variations for the years ended December 31, 2020, and 2019:

	Electricity sales during the year ended December 31,
	2020	2019	Change	Change
	(in GWh)			(in %)
Edesur (Argentina)	15,888	16,798	(910)	(5.4)
Enel Distribution Rio (Brazil)	11,228	11,568	(339)	(2.9)
Enel Distribution Ceara (Brazil)	11,866	12,197	(332)	(2.7)
Enel Distribution Goias (Brazil)	14,469	14,365	104	0.7
Enel Distribution Sao Paulo (Brazil)	40,350	43,148	(2,798)	(6.5)
Codensa (Colombia)	13,834	14,307	(473)	(3.3)
Enel Distribution Peru (Peru)	7,578	8,211	(633)	(7.7)
Total	115,213	120,594	(5,381)	(4.5)

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The following table sets forth the revenues and other operating income by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2020, and 2019:

	Year ended December 31,
	2020	2019	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	231	436	(205)	(47.1)
Costanera	113	214	(101)	(47.2)
El Chocón	49	72	(23)	(32.6)
Dock Sud	66	147	(81)	(54.9)
Other	3	3	—	—
Generation and Transmission Business in Brazil	1,106	778	328	42.2
EGP Cachoeira Dourada	812	494	318	64.4
Fortaleza	187	310	(123)	(39.6)
Cien	53	70	(17)	(24.7)
EGP Volta Grande	62	107	(45)	(41.7)
Other	(8)	(203)	195	96.1
Generation and Transmission Business in Colombia	1,159	1,247	(88)	(7.0)
Emgesa	1,159	1,247	(88)	(7.0)
Generation and Transmission Business in Peru	505	596	(91)	(15.3)
Enel Generation Peru	408	474	(66)	(13.9)
Enel Generation Piura	64	82	(18)	(22.1)
Chinango	41	45	(4)	(8.9)
Other	(7)	(5)	(2)	(40.0)
Total Generation and Transmission Business reportable segment	3,001	3,057	(56)	(1.8)
	—	—
Distribution Business in Argentina	801	1,347	(546)	(40.5)
Edesur	801	1,347	(546)	(40.5)
Distribution Business in Brazil(1)	6,834	8,227	(1,393)	(16.9)
Enel Distribution Rio	1,253	1,526	(273)	(17.9)
Enel Distribution Ceara	1,166	1,398	(232)	(16.6)
Enel Distribution Goias	1,394	1,546	(152)	(9.8)
Enel Distribution Sao Paulo	3,021	3,757	(736)	(19.6)
Distribution Business in Colombia	1,547	1,665	(118)	(7.1)
Codensa	1,547	1,665	(118)	(7.1)
Distribution Business in Peru	887	950	(63)	(6.7)
Enel Distribution Peru	887	950	(63)	(6.7)
Total Distribution Business reportable segment	10,069	12,189	(2,120)	(17.4)
Less: consolidation adjustments and non-core activities	(778)	(861)	83	9.6
Total Revenues and other operating income	12,292	14,385	(2,093)	(14.5)

(1) During 2021, we reclassified from financial income to operating income the value to be recovered of certain financial assets related to the concession contracts of the electricity distribution subsidiaries in Brazil. As a consequence of such reclassification, we retrospectively reclassified in the consolidated statements of comprehensive income the amounts of ThUS$ 99,071 and ThUS$ 73,345 from financial income to operating income, for the years ended December 31, 2020, and 2019, respectively. Please refer to Note 2.2.c of the Notes to our consolidated financial statements for further detail.

Generation and Transmission Business: Revenues

In Argentina, revenues and other operating income decreased by US$ 205 million, or 47.1% in 2020 compared to 2019, primarily explained by:

(i) a decrease of US$ 101 million from Costanera, or 47.2%, in 2020 compared to 2019, mainly explained by lower revenues of:

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a) US$ 61 million because of Resolution No. 12/2019, which became applicable in 2020, due to the fact that prior to the resolution taking effect, generation companies could buy fuel in the market and sell it to third parties. As a result of the resolution, generation companies must rely on CAMMESA to supply them with fuel.;

b) US$ 46 million as a result of the devaluation of the Argentine peso against the U.S. dollar; and

c) US$ 9 million from lower availability contracts, as a result of a regulatory agreement that ended the previous year.

This decrease in revenues and other operating income was partially offset by higher revenues of:

d) US$ 12 million as a result of increased physical sales of 308 GWh, which includes increased rates of US$ 11 million; and

e) US$ 3 million from the implementation of new Resolution No. 31/2020, applicable as of February 2020, which established that energy and power values should be charged in Argentine pesos, using the exchange rate against the U.S. dollar valid at the billing date.

(ii) a decrease of US$ 81 million from Dock Sud, or 54.9%, in 2020 compared to 2019, which is mainly explained by lower revenues of:

a) US$ 55 million mainly because of Resolution No. 12/2019, which became applicable in 2020, due to the fact that prior to the resolution taking effect, generation companies could buy fuel in the market and sell it to third parties. As a result of the resolution, generation companies must rely on CAMMESA to supply them with fuel;

b) US$ 27 million as a result of the depreciation of the Argentine peso against the U.S. dollar; and

c) US$ 6 million due to an insurance claim recorded during the first half of 2019.

This decrease in energy revenues was partially offset by:

d) an increase of US$ 7 million in energy sales of 223 GWh.

(iii) a decrease of US$ 23 million from Enel Generation El Chocón in 2020 compared to 2019, primarily because of lower revenues of US$ 25 million as a result of the devaluation of the Argentine peso against the U.S. dollar, offset by US$ 2 million higher energy sales of 396 GWh.

In Brazil, revenues and other operating income increased by US$ 328 million, or 42.2%, in 2020 compared to 2019, primarily explained by the following:

(i) physical energy sales from EGP Cachoeira Dourada increased by US$ 318 million, or 64.3%. The increase is mainly explained by:

a) US$ 568 million increase in energy sales explained by:

● US$ 649 million higher energy imports from Argentina and Uruguay for commercialization; partially offset by

● US$ 81 million of lower physical sales to the regulated market for 1,504 GWh, at least partly attributable to the Covid-19 pandemic.

This increase in physical energy sales was partially offset by:

b) US$ 250 million less in revenue as a result of the devaluation of the Brazilian real against the U.S. dollar.

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(ii) an increase of US$ 195 million in other operating revenues mainly due to sales transactions and energy purchases between our generation companies in Brazil.

These increases in revenues and other operating income were partially offset by:

(iii) a decrease of US$ 123 million from Fortaleza, or 39.6%, mainly as a result of:

a) US$ 65 million less in energy sales explained by a contraction in demand, for 1,106 GWh at least partly attributable to the Covid-19 pandemic, and

b) US$ 57 million less in revenue as a result of the devaluation of the Brazilian real against the U.S. dollar.

(iv) a decrease of US$ 45 million from EGP Volta Grande, or 41.7%, mainly explained by:

a) lower energy sales of US$ 25 million, due to a reduction in demand for 370 GWh, at least partly attributable to the Covid-19 pandemic; and

b) US$ 19 million less in revenue due to the devaluation of the Brazilian real against the U.S. dollar.

(iv) a decrease of US$ 17 million from Cien, or 24.7%, mainly explained by the devaluation of the Brazilian real against the U.S. dollar.

In Colombia, revenues and other operating income from Emgesa decreased by US$ 88 million, or 7.0%, in 2020 compared to 2019, mainly explained by lower revenues of:

(i) US$ 142 million as a result of the devaluation of the Colombian peso against the U.S. dollar;

(ii) US$ 5 million due to an insurance compensation received in June 2019 from a claim at the El Quimbo hydroelectric plant; and

(iii) US$ 2 million in gas sales due to lower consumption partly explained by the Covid-19 pandemic.

These decreases in revenues and other operating income were partially offset by higher revenues of:

(iv) US$ 56 million due to higher average sales prices (caused by low hydrology in 2020), which contributed to US$ 111 million in revenues, offset by US$ 55 million for lower physical sales (-837 GWh) due to lower unregulated market demand partly caused by the Covid-19 pandemic; and

(v) US$ 5 million related to the sales of carbon credits.

In Peru, revenues and other operating income from Enel Generation Peru decreased by US$ 91 million, or 15.3%, in 2020 compared to 2019, primarily explained by:

(i) a decrease of US$ 66 million from Enel Generation Peru, or 13.9%. This decrease is mainly explained by lower revenues of:

a) US$ 40 million, or 899 GWh, due at least partly to the Covid-19 pandemic;

b) US$ 19 million as a result of the devaluation of the new Peruvian sol against the U.S. dollar; and

c) US$ 10 million from the modifications to outsourcing agreements.

(ii) a decrease of US$ 18 million from Enel Generation Piura, or 22.1%, mainly explained by:

a) US$ 15 million in lower revenues from lower gas sales; and

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b) US$ 3 million from the devaluation of the new Peruvian sol against the U.S. dollar.

Distribution Business: Revenues

In Argentina, revenues and other operating income from Edesur decreased by US$ 546 million, or 40.5%, in 2020 compared to 2019, which is mainly explained by:

(i) US$ 324 million in lower revenues due to the devaluation of the Argentine peso against the U.S. dollar;

(ii) US$ 203 million in lower revenues as a result of the regulatory agreement signed between Edesur and the Argentine government in 2019, which ended outstanding reciprocal claims arising in the 2006-2016 transition period; and

(iii) US$ 51 million due to inflation adjustments from the application of IAS 29.

These decreases in revenues and operating income were partially offset by higher revenues of:

(iv) US$ 18 million from the new 2020 framework agreement between the ENRE and Edesur, to allocate funds to improve electricity service and distribution networks; and

(v) US$ 14 million as a result of better prices due to inflation adjustments.

In Brazil, revenues and other operating income decreased by US$ 1,393 million in 2020, or 16.9%, in 2020 compared to 2019, explained by:

(i) a decrease of US$ 736 million from Enel Distribution Sao Paulo, or 19.6%, explained by:

a) a decrease of US$ 954 million in revenues due to the devaluation of the Brazilian real against the U.S. dollar.

This decrease in revenues and other operating income was partially offset by:

b) an increase of US$ 90 million in energy sales revenues, as a result of US$ 368 million average sales price increase despite lower physical sales of 2.798 GWh, totaling US$ 278 million, due at least partly to the impacts of the Covid-19 pandemic;

c) US$ 67 million increase in other services due to increased average sale prices for toll services; and

d) US$ 61 million due to higher income from the application of IFRIC 12, of which US$ 56 million corresponds to income from construction and US$ 5 million from the update of recoverable financial assets at the end of the concession.

(ii) a decrease of US$ 273 million from Enel Distribution Rio, or 17.9%, mainly explained by:

a) US$ 378 million less in revenues as a result of the devaluation of the Brazilian real against the U.S. dollar.

This decrease in revenues and other operating income was partially offset by an increase of:

b) US$ 55 million in revenues from energy sales, mainly from higher average sale prices, due to US$ 98 million inflation adjustments, partially offset by US$ 43 million lower physical energy sales of 340 GWh partly as a result of the Covid-19 pandemic; and

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c) US$ 50 million due to higher income from the application of IFRIC 12, of which US$ 29 million corresponds to income from construction and US$ 21 million from the update of recoverable financial assets at the end of the concession.

(iii) a decrease of US$ 232 million from Enel Distribution Ceara, or 16.6%, primarily due to:

a) a decrease of US$ 355 million in revenues as a result of the devaluation of the Brazilian real against the U.S. dollar.

This decrease in revenues and other operating income was partially offset by an increase of:

b) US$ 61 million due to the application of IFRIC 12;

c) US$ 58 million in energy sales mainly due to (i) higher tariff prices, US$ 92 million, offset by (ii) lower physical sales of 331 GWh, or US$ 34 million, as a result at least in part of the Covid-19 pandemic; and

d) US$ 5 million in other services due to energy tolls for unregulated customers in the local market.

(iv) a decrease of US$ 152 million from Enel Distribution Goias, or 9.8%, which is mainly explained by:

a) US$ 431 million as a result of the devaluation of the Brazilian real against the U.S. dollar.

This decrease in revenues and other operating income was partially offset by an increase of:

b) US$ 134 million in other revenues due to the application of IFRIC 12;

c) US$ 123 million in energy sales explained by higher sectoral commissions payable; and

d) US$ 22 million in toll revenues due to a rate adjustment on unregulated customers.

In Colombia, revenues and other operating income from Codensa decreased by US$ 118 million or 7.1% in 2020, compared to 2019, mainly explained by:

(i) US$ 194 million due to the devaluation of the Colombian peso against the U.S. dollar.

This decrease in revenues and other operating income was partially offset by higher revenues of:

(ii) US$ 44 million in investment recognition income in 2019, paid at higher rates due to a higher regulatory asset base;

(iii) US$ 11 million mainly due to improved profitability in Codensa’s credit card business;

(iv) US$ 6 million for a higher average sales prices, despite lower physical sales of 473 GWh due partly to the Covid-19 pandemic;

(v) US$ 6 million related to the CREG Resolution 189 in December 2019, which approved the variables necessary to calculate income and charges associated with Codensa’s energy distribution;

(vi) US$ 6 million in electrical projects and other businesses; and

(vii) US$ 3 million in fee increase from the collection of municipal cleaning charges on customer invoices.

In Peru, operating income from Enel Distribution Peru decreased by US$ 63 million, or 6.7%, principally explained by:

(i) US$ 42 million due to the devaluation of the new Peruvian sol against the U.S. dollar;

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(ii) US$ 19 million in lower energy sales explained by (i) a decrease in physical sales of 633 GWh, equivalent to US$ 88 million, for lower energy consumption due partly to the Covid-19 pandemic and (ii) an increase of US$ 69 million in average energy prices due to energy power billing; and

(iii) US$ 3 million less in revenues from traditional businesses such as connections, ancillary services, as well as from retail activities and lower contributions to regulating bodies.

Total Raw materials and consumables used

The following table sets forth our total raw materials and consumables used by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2020, and 2019:

	Year ended December 31,
	2020	2019	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	19	130	(111)	(85.7)
Costanera	5	69	(64)	(92.8)
El Chocón	5	6	(1)	(24.3)
Dock Sud	10	54	(44)	(81.4)
Other	(1)	1	(2)	(200.0)
Generation and Transmission Business in Brazil	781	419	362	86.3
EGP Cachoeira Dourada	666	395	272	68.7
Fortaleza	119	183	(65)	(35.2)
Cien	—	1	(1)	(100.0)
EGP Volta Grande	11	43	(32)	(75.5)
Other	(15)	(203)	188	92.6
Generation and Transmission Business in Colombia	413	466	(53)	(11.4)
Emgesa	413	466	(53)	(11.4)
Generation and Transmission Business in Peru	162	204	(42)	(20.7)
Enel Generation Peru	140	178	(38)	(21.2)
Enel Generation Piura	23	28	(5)	(16.3)
Chinango	5	5	—	—
Other	(6)	(7)	1	14.3
Total Generation and Transmission Business reportable segment	1,375	1,219	156	12.8
Distribution Business in Argentina	530	774	(244)	(31.5)
Edesur	530	774	(244)	(31.5)
Distribution Business in Brazil	4,937	5,820	(883)	(15.2)
Enel Distribution Rio	869	1,029	(160)	(15.5)
Enel Distribution Ceara	835	992	(157)	(15.8)
Enel Distribution Goias	1,027	1,100	(73)	(6.6)
Enel Distribution Sao Paulo	2,206	2,699	(493)	(18.3)
Distribution Business in Colombia	886	962	(76)	(7.9)
Codensa	886	962	(76)	(7.9)
Distribution Business in Peru	599	619	(20)	(3.2)
Enel Distribution Peru	599	619	(20)	(3.2)
Total Distribution Business reportable segment	6,953	8,175	(1,222)	(14.9)
Less: consolidation adjustments and non-core activities	(772)	(853)	81	9.5
Total Raw materials and consumables used	7,556	8,541	(985)	(11.5)

Generation and Transmission Business: Raw materials and consumables used

In Argentina, raw materials and consumables used decreased US$ 111 million, or 85.7%, in 2020 compared to 2019, mainly due to a decreases of:

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(i) US$ 64 million, or 92.8%, from Costanera, explained mainly by:

a) US$ 59 million in lower gas consumption as a result of the application of Resolution No. 12/2019;

b) US$ 3 million due to lower variable costs in CAMMESA as a result of lower market activity; and

c) US$ 2 million because of the devaluation of the Argentine peso against the U.S. dollar.

(ii) US$ 44 million, or 81.4%, from Dock Sud, mainly explained by:

a) lower gas consumption costs of US$ 41 million, as a result of the implementation of Resolution No. 12/2019; and

b) US$ 3 million lower costs as a result of the devaluation of the Argentine peso against the U.S. dollar.

(iii) US$ 1 million, or 24.3%, from El Chocón as a result of the devaluation of the Argentine peso against the U.S. dollar.

In Brazil, raw materials and consumables used increased by US$ 362 million, or 86.3%, in 2020 compared to 2019, which is mainly explained by:

(i) an increase of US$ 272 million, or 68.7%, from EGP Cachoeira Dourada, mainly explained by:

a) US$ 618 million in energy purchases in the market to cover its obligations.

This increase in raw materials and consumables used was primarily offset by:

b) US$ 222 million as a result of the devaluation of the Brazilian real against the U.S. dollar;

c) US$ 63 million of lower energy purchases of 3,520 GWh, due to lower customer demand on the regulated market at least partly attributable to the Covid-19 pandemic; and

d) US$ 61 million favorable impact due to the registration of the Generation Scaling Factor agreement, which allowed renegotiation and the distribution of hydrological risk costs among system operators.

(ii) US$ 188 million, or 92.6%, in other operating costs mainly due to energy purchases and sales transactions between our generation companies in Brazil.

These increases in raw materials and consumables used were partially offset by a decrease of:

(iii) US$ 65 million, or 35.2%, from Fortaleza mainly due to:

a) US$ 37 million lower costs as a result of the devaluation of the Brazilian real against the U.S. dollar;

b) US$ 24 million reduction in energy purchases of 190 GWh, explained by lower average purchase prices; and

c) US$ 4 million in lower gas consumption due to lower generation in 2020.

(iv) US$ 32 million, or 75.5%, from EGP Volta Grande due to lower energy purchases of 527 GWh explained by lower energy sales at least partly attributable to the Covid-19 pandemic.

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In Colombia, raw materials and consumables used from Emgesa decreased by US$ 53 million, or 11.4%, in 2020 compared to 2019, mainly due to:

(i) US$ 51 million as a result of the devaluation of the Colombian peso against the U.S. dollar;

(ii) US$ 7 million decrease in energy purchases; and

(iii) US$ 4 million in lower gas purchases mainly due to the decrease in customer demand due partly to the Covid-19 pandemic.

These decreases in raw materials and consumables used were partially offset by:

(iv) US$ 5 million in other variable provisions and services mainly due to the new contribution of the National Development Plan to regulatory bodies; and

(v) US$ 4 million increase in transportation expenses.

In Peru, raw materials and consumables used decreased by US$ 41 million, or 20.2%, in 2020 compared to 2019, which is primarily explained by a decrease of:

(i) US$ 38 million, or 21.2%, from Enel Generation Peru as a result of:

a) US$ 12 million in lower gas transportation and distribution costs;

b) US$ 11 million in lower energy purchases of 419 GWh, explained by a lower marginal cost and the Covid-19 pandemic;

c) US$ 8 million in lower gas consumption due to lower production in thermal power plants; and

d) US$ 7 million lower costs due to the devaluation of the new Peruvian sol against the U.S. dollar.

(ii) US$ 5 million from Enel Generation Piura, or 16.3%, mainly as a result of:

a) lower gas consumption of US$ 3 million, due to lower demand, which resulted in lower production of thermal power plants; and

b) US$ 1 million due to the devaluation of the new Peruvian sol against the U.S. dollar.

Distribution Business: Raw materials and consumables used

In Argentina, raw materials and consumables used of Edesur decreased by US$ 244 million, or 31.5%, in 2020 compared to 2019, mainly explained by a decrease of:

(i) US$ 214 million as a result of the devaluation of the Argentine peso against the U.S. dollar;

(ii) US$ 27 million in energy purchases due to lower market purchase prices of US$ 26 million and US$ 1 million due to increased energy losses from 15.5% as of December 2019 to 18.9% as of December 2020; and

(iii) US$ 10 million in other supply costs, explained by lower rental expenses of equipment.

These decreases in raw materials and consumables used were partially offset by:

(iv) US$ 8 million in higher transportation costs due to increased service prices in line with the inflation adjustment associated with the application of IAS 29.

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In Brazil, raw materials and consumables used decreased by US$ 882 million, or 15.2%, in 2020 compared to 2019, explained by:

(i) a decrease of US$ 493 million, or 18.3%, from Enel Distribution Sao Paulo, mainly explained by:

a) US$ 682 million as a result of the devaluation of the Brazilian real against the U.S. dollar;

This decrease in raw materials and consumables used was partially offset by:

b) US$ 86 million in energy purchases from thermal power plants due to higher prices in the last quarter of 2020 as a result of lower hydrology;

c) a US$ 56 million increase in variable supply and services due to the application of IFRIC 12; and

d) US$ 47 million in transportation costs.

(ii)a decrease of US$ 160 million, or 15.5%, from Enel Distribution Rio, explained mainly by:

a) US$ 269 million in lower costs as a result of the devaluation of the Brazilian real against the U.S. dollar;

This decrease in operating costs was mainly offset by:

b) US$ 38 million in higher energy transportation costs due to higher fees for network use;

c) a US$ 37 million increase in other variable supplies and services due to US$ 29 million related to the application of IFRIC 12 and a US$ 8 million contingency effect related to taxes registered in 2019; and

d) US$ 34 million in higher energy consumption explained by US$ 98 million in higher prices related to inflation adjustment associated with the application of IAS 29, which was offset by 506 GWh in higher energy purchases for a US$ 64 million increase.

(iii)a decrease of US$ 157 million, or 15.8%, from Enel Distribution Ceara, which is mainly explained by:

a) US$ 259 million, as a result of the devaluation of the Brazilian real against the U.S. dollar;

This decrease in raw materials and consumables used was partially offset by:

b) US$ 61 million increase from the application of IFRS 12;

c) US$ 23 million increase in energy purchases as a result of higher average purchase prices of US$ 58 million, due to inflation adjustment associated with the application of IAS 29, offset by a US$ 35 million decrease in physical energy purchases of 83 GWh, at least partly attributable to the Covid-19 pandemic; and

d) US$ 18 million increase in transportation costs.

(iv)a decrease of US$ 73 million, or 6.6%, from Enel Distribution Goias mainly explained by:

a) US$ 318 million as a result of the devaluation of the Brazilian real against the U.S. dollar;

This decrease in raw materials and consumables used was partially offset by higher costs of:

b) US$ 141 million in other variable supplies and services that correspond mainly to the application of IFRIC 12;

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c) US$ 66 million in energy purchases due to higher average prices; and

d) US$ 38 million in transportation costs.

In Colombia, raw materials and consumables used of Codensa decreased by US$ 76 million, or 7.9%, in 2020 compared to 2019, mainly explained by:

(i)a decrease of US$ 111 million due to the devaluation of the Colombian peso against the U.S. dollar.

This decrease in raw materials and consumables used was partially offset by an increase in costs of:

(ii)US$ 17 million in energy transportation costs caused by the entry of new construction units into the national transmission system;

(iii)US$ 10 million in energy purchases, mainly due to higher average energy prices caused by lower hydrological conditions in 2020; and

(iv)US$ 8 million in other provisions and services mainly due to contributions to regulatory bodies, higher taxes, connections lines, and maintenance charges.

In Peru, raw materials and consumables used of Enel Distribution Peru decreased by US$ 20 million, or 3.2%, in 2020 compared to 2019, mainly explained by:

(i)US$ 27 million for lower conversion effects from the devaluation of the new Peruvian sol against the U.S. dollar.

This decrease in operating costs was partially offset by:

(ii)US$ 7 million in higher energy purchases, mainly explained by higher energy purchases related to the increase in the average purchase price for US$ 52 million, partially offset by lower physical energy purchases of US$ 45 million, or 609 GWh, due partly to the Covid-19 pandemic.

Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense

Our employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense are comprised of salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.

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The following table sets forth the employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2020, and 2019:

	Year ended December 31,
	2020	2019	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	158	151	7	4.6
Costanera	89	85	4	4.9
El Chocón	22	23	(1)	(3.6)
Dock Sud	42	42	(0)	(0.3)
Other	5	1	4	400.0
Generation and Transmission Business in Brazil	51	71	(20)	(28.9)
EGP Cachoeira Dourada	16	20	(4)	(18.1)
Fortaleza	17	26	(9)	(33.2)
Cien	14	20	(6)	(29.7)
EGP Volta Grande	3	4	(1)	(15.8)
Other	1	1	—	—
Generation and Transmission Business in Colombia	140	144	(4)	(2.5)
Emgesa	140	144	(4)	(2.5)
Generation and Transmission Business in Peru	135	137	(2)	(2)
Enel Generation Peru	106	108	(2)	(1.7)
Enel Generation Piura	22	21	1	4.4
Chinango	9	10	(1)	(10.0)
Other	(2)	(2)	—	n.a.
Total Generation and Transmission Business reportable segment	484	503	(19)	(3.8)
Distribution Business in Argentina	339	362	(23)	(6.3)
Edesur	339	362	(23)	(6.3)
Distribution Business in Brazil	1,244	1,628	(384)	(23.6)
Enel Distribution Rio	289	322	(33)	(10.2)
Enel Distribution Ceara	232	241	(9)	(3.7)
Enel Distribution Goias	282	422	(140)	(33.2)
Enel Distribution Sao Paulo	441	643	(202)	(31.5)
Distribution Business in Colombia	286	272	14	5.0
Codensa	286	272	14	5.0
Distribution Business in Peru	146	135	11	8.2
Enel Distribution Peru	146	135	11	8.2
Total Distribution Business reportable segment	2,015	2,397	(382)	(15.9)
Less: consolidation adjustments and non-core activities	85	104	(20)	(18.8)
Total Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense	2,584	3,004	(420)	(14.0)

Consolidated depreciation, amortization, and impairment reached US$ 1,100 million for the period ended December 31, 2020, a decrease of US$ 127 million compared to 2019.

Depreciation and amortization reached US$858 million as of December 2020, representing a decrease of US$90 million compared to the same period of the previous year, explained by US$112 million as a result of the devaluation of the Brazilian real against the U.S. dollar, offset by higher amortization of US$27 million due to higher investments in 2020, mainly in the distribution subsidiaries in Brazil.

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Generation and Transmission Business

Consolidated Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense decreased US$ 15 million, or 3.8%, in 2020 compared to 2019, mainly due to a US$ 19 million decrease from the businesses in Brazil, as a result of the devaluation of the Brazilian real against the U.S. dollar.

Distribution Business

Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense decreased US$ 382 million, or 15.9%, in 2020 compared to 2019, mainly due to the following:

In Argentina, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense decreased by US$ 23 million, or 6.3%, in 2020 compared to 2019, primarily due to the following:

(i) US$ 26 in lower personnel expenses from Edesur mainly explained by (i) US$ 38 million less in expenses due to the devaluation of the Argentine peso against the U.S. dollar and (ii) US$ 15 million in lower spending on retirement and pension plans, partially offset by US$ 27 million in salary increases, mainly explained by the recognition of inflation in salary and social security expenses; and

(ii) US$ 19 million in lower other expenses from Edesur mainly explained by US$ 51 million as a result of the devaluation of the Argentina pesos against the U.S. dollar, offset by (i) US$ 30 million in higher costs for maintenance and network renovations, among others, and (ii) US$ 2 million for the purchase of safety and hygiene elements linked to the Covid-19 pandemic.

These decreases in selling and administrative expenses were partially offset by:

(iii) US$ 20 million in higher depreciation, mainly due to the application of IAS 29 (inflation) to the company’s fixed assets; and

(iv) US$ 2 million in higher provisions for bad debt due to the application of IFRS 9.

In Brazil, Employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense decreased by US$ 384 million, or 23.6%, in 2020 compared to 2019, primarily due to the following:

(i) a decrease of US$ 33 million, 10.2%, from Enel Distribution Rio, mainly explained by:

a) US$ 28 million in lower other expenses mainly due to US$ 39 million as a result of the devaluation of the Brazilian real against the U.S. dollar, partially offset by US$ 11 million from higher operation and commercial costs;

b) US$ 21 million in lower amortization and depreciations mainly due to US$ 25 million from the devaluation of the Brazilian real against the U.S. dollar, partially offset by higher amortization of US$ 4 million; and

c) US$ 6 million lower in staffing costs, due to US$ 7 million from the devaluation of the Brazilian real against the U.S. dollar, partially offset by higher staffing costs of US$ 1 million.

These decreases were partially offset by:

d) US$ 22 million in higher provisions for bad debts due to US$ 39 million as a result of the application of IFRS 9 as a consequence of Covid-19 pandemic, partially offset by US$ 17 million as a result of the devaluation of the Brazilian real against the U.S. dollar.

(ii) a decrease of US$ 140 million, or 33.2%, from Enel Distribution Goias, mainly explained by:

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a) US$ 98 million less in impairment losses, mainly explained by an impairment of US$ 92 million recognized in 2019 associated with accounts receivable linked to the Goiás Distribution Contribution Fund (FUNAC), created by the state of Goiás;

b) US$ 16 million less in personnel expenses explained by (i) a US$ 9 million decrease due to fewer staff members and lower overtime expenses resulting from the Covid-19 pandemic; and (ii) US$ 7 million as a result of the devaluation of the Brazilian real against the U.S. dollar;

c) US$ 14 million in lower amortization and depreciation expenses mainly due to US$ 20 million from the devaluation of the Brazilian real against the U.S. dollar, offset by higher amortization of US$ 6 million, due to greater investments during the period;

d) US$ 11 million less in other expenses due to US$ 54 million as a result of the devaluation of the Brazilian real, partially offset by an increase of:

● US$ 32 million in maintenance and conservation costs for electrical installations, meter reading services, customer service, and other services;

● US$ 8 million in costs for fines and quality-of-service contingencies; and

● US$ 3 million in expenses explained by other marketing activities and customer-related virtual channels.

(iii) a decrease of US$ 202 million, or 31.5%, from Enel Distribution Sao Paulo mainly due to:

a) US$ 89 million attributable to the effects of voluntary migration by employees to a defined contribution plan;

b) US$ 43 million as a result of the devaluation of the Brazilian real against the U.S. dollar;

c) US$ 42 million in lower amortization expenses explained by US$ 49 million as a result of the devaluation of the Brazilian real against the U.S. dollar, offset by higher amortization of US$ 7 million due to greater investments during the period;

d) US$ 13 million less in expenses due to increased efficiency and digitization of processes;

e) US$ 13 million less in other expenses, explained by US$ 52 million due to the devaluation of the Brazilian real against the U.S. dollar, partially offset by a US$ 40 million increase mainly in third-party service costs for lines, network maintenance, and other technical services; and

f) US$ 4 million in higher personnel expenses due to investments in projects to improve service quality.

In Colombia, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense from Codensa increased US$ 14 million, or 5.0%, in 2020 compared to 2019, mainly due to an increase of US$ 11 million in provisions for bad debts as a result of the application of IFRS 9 in response to the Covid-19 pandemic.

In Peru, employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense from Enel Distribution Peru increased US$ 11 million, or 8.2%, in 2020 compared to 2019, mainly due to an increase of US$ 10 million in provisions for bad debts as a result of the application of IFRS 9 in response to the Covid-19 pandemic.

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Operating Income

The following table sets forth our operating income by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2020, and 2019:

	Year ended December 31,
	2020	2019	Change	Change
	(in millions of US$)			(in %)
Generation and Transmission Business in Argentina	53	155	(102)	(65.8)
Costanera	19	60	(41)	(68.6)
El Chocón	22	43	(21)	(49.3)
Dock Sud	14	51	(37)	(71.7)
Other	(2)	1	(3)	(300.0)
Generation and Transmission Business in Brazil	273	288	(15)	(5.1)
EGP Cachoeira Dourada	130	79	51	64.1
Fortaleza	51	100	(49)	(48.8)
Cien	39	50	(11)	(22.0)
EGP Volta Grande	48	60	(12)	(19.2)
Other	5	(1)	6	600
Generation and Transmission Business in Colombia	607	637	(30)	(4.8)
Emgesa	607	637	(30)	(4.8)
Generation and Transmission Business in Peru	208	255	(47)	(18.6)
Enel Generation Peru	162	192	(30)	(15.6)
Enel Generation Piura	19	33	(14)	(43.9)
Chinango	27	30	(3)	(10.0)
Total Generation and Transmission Business reportable segment	1,141	1,335	(194)	(14.6)
Distribution Business in Argentina	(68)	211	(279)	(132.4)
Edesur	(68)	211	(279)	(132.4)
Distribution Business in Brazil	652	779	(127)	(16.4)
Enel Distribution Rio	94	175	(81)	(46.2)
Enel Distribution Ceara	99	165	(66)	(40.3)
Enel Distribution Goias	85	24	61	256.1
Enel Distribution Sao Paulo	374	415	(41)	(9.8)
Distribution Business in Colombia	375	431	(56)	(13.0)
Codensa	375	431	(56)	(13.0)
Distribution Business in Peru	141	196	(55)	(27.8)
Enel Distribution Peru	141	196	(55)	(27.8)
Total Distribution Business reportable segment	1,100	1,617	(517)	(32.0)
Less: consolidation adjustments and non-core activities	(89)	(111)	22	19.7
Total operating income	2,151	2,842	(691)	(24.3)

Generation and Transmission Business

Operating income from the generation and transmission business decreased US$ 194 million, or 14.6%, in 2020 compared to 2019, mainly explained by the following events:

In Argentina, operating income decreased by US$ 102 million, or 65.8%, mainly attributable to Costanera’s higher maintenance costs and lower revenues from El Chocón and Dock Sud, explained by the devaluation of the Argentine peso against the U.S. dollar associated with the IAS 29 inflation adjustment.

In Brazil, operating income decreased by US$ 15 million, or 5.1%, mainly due to (i) higher energy purchases from EGP Cachoeira Dourada, increasing operating costs, and (ii) a decrease in operating income from Fortaleza and EGP Volta Grande due to lower energy sales and the devaluation of the Brazilian real against the U.S. dollar.

In Colombia, operating income decreased by US$ 30 million, or 4.8%, mainly due to lower physical sales and the devaluation of the Colombian peso against the U.S. dollar, partially offset by better sales prices due to a tariff increase.

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In Peru, operating income decreased by US$ 47 million, or 18.6%, due to the devaluation of the new Peruvian Sol against the U.S. dollar, lower physical sales in Enel Generation Peru, and lower gas sales in Enel Generation Piura.

Distribution Business

Operating income decreased US$ 516 million, or 31.9%, in 2020 compared to 2019, mainly explained by the following events:

In Argentina, operating income from Edesur decreased US$ 279 million, or 132.4%, as a result of the regulatory agreement signed between Edesur and the Argentine government, which settled the outstanding reciprocal claims arising in the transition period 2006-2016 for US$ 203 million, and the effects of the devaluation of the Argentine peso against the U.S. dollar.

In Brazil, operating income decreased US$ 126 million, or 16.2%, mainly due to:

(i) a decrease of US$ 81 million, or 46.2%, from Enel Distribution Rio, mostly attributable to the effects of the devaluation of the Brazilian real against the U.S. dollar and lower physical sales;

(ii) a decrease of US$ 66 million, or 40.3%, from Enel Distribution Ceara, mainly due to the effects of the devaluation of the Brazilian real against the U.S. dollar;

(iii) a decrease of US$ 41 million, or 9.8%, from Enel Distribution Sao Paulo, primarily as a result of the devaluation of the Brazilian real against the U.S. dollar, and the positive effect of voluntary migration by employees to a defined contribution pension plan; and

These decreases in operating income were partially offset by;

(iv) an increase of US$ 61 million, or 262.9%, in Enel Distribution Goias mainly due to the reduction of employee benefits expenses and other work capitalized, depreciation, amortization and impairment losses and other expense, primarily explained by lower impairment losses.

In Colombia, operating income from Codensa decreased US$ 56 million, or 13.0%, in 2020 compared to 2019, mainly due to lower physical sales and the devaluation of the Colombian peso against the U.S. dollar.

In Peru, operating income from Enel Distribution Peru decreased US$ 55 million, or 27.8%, in 2020 compared to 2019, mainly explained by lower physical sales and devaluation of the new Peruvian sol against the U.S. dollar.

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Other Results

The following table sets forth our other results for the years ended December 31, 2020, and 2019:

	Year ended December 31,
	2020	2019	Change	Change
	(in millions of US$)			(in %)
Financial results
Financial income(1)	222	376	(154)	(40.9)
Financial costs	(768)	(1,088)	320	29.4
Results for Hyperinflation	77	124	(47)	(38.1)
Net foreign currency exchange gains (losses)	57	137	(80)	(58.3)
Total	(412)	(451)	39	8.6
Other
Other gains (losses)	5	14	(9)	(64.3)
Share of the profit of associates and joint ventures accounted for using the equity method	3	1	2	200.0
Total	8	15	(7)	(47.2)
Total other results	(404)	(436)	32	7.3

(1) During 2021, we reclassified from financial income to operating income the value to be recovered of certain financial assets related to the concession contracts of the electricity distribution subsidiaries in Brazil. As a consequence of such reclassification, we retrospectively reclassified in the consolidated statements of comprehensive income the amounts of ThUS$ 99,071 and ThUS$ 73,345 from financial income to operating income, for the years ended December 31, 2020, and 2019, respectively. Please refer to Note 2.2.c of the Notes to our consolidated financial statements for further detail.

Financial Results 

Our net total financial results in 2020 decreased by US$ 39 million, or 8.6%, compared to 2019. The variation is mainly explained by:

(i) a decrease of US$ 154 million in financial income, primarily explained by lower revenues of:

a) US$ 37 million attributable to (i) US$ 27 million from Enel Distribution Sao Paulo, mainly due to the devaluation of the Brazilian real against the U.S. dollar and (ii) US$ 10 million in revenues for lower returns on financial investments;

b) US$ 26 million from our generation subsidies in Argentina, primarily as a result of (i) US$ 30 million in lower interest revenue related to the accounts receivable and (ii) US$ 21 million due to the devaluation of the Argentine peso against the U.S. dollar, partially offset by US$ 25 million in financial income for investment revaluation due to a change in ownership of Central Térmica Manuel Belgrano and Central Térmica San Martín;

c) US$ 17 million from Enel Generation Fortaleza, mainly explained by US$ 13 million in financial updates to PIS/COFINS taxes recorded in 2019;

d) US$ 37 million from Enel Distribution Rio, due to the devaluation of the Brazilian real against the U.S. dollar for US$ 16 million and from lower returns on financial investments for US$ 21 million;

e) US$ 12 million from Edesur, mainly due to US$ 4 million as a result of the devaluation of the Argentine peso against the U.S. dollar and US$ 7 million in lower interest charged on customer defaults;

f) US$ 12 million from Enel Américas, mainly from lower financial issuances; and

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g) US$ 6 million from Enel Cien, mainly due to lower revenues as a result of financial updates to PIS/COFINS taxes.

(ii) a decrease of US$ 80 million due to (i) US$ 74 million negative exchange rate differences from our generation subsidiaries in Argentina, (ii) US$ 42 million from Enel Brasil related to updates to service provider agreements. This was partially offset by US$ 34 million less in negative exchange rate differences in Enel Américas, mainly due to lower domestic currency placements made in 2019 during the capital increase process.

(iii) a decrease of US$ 47 million in results for hyperinflation, explained by an inflation adjustment attributed to non-monetary assets and liabilities and income statements due to the implementation of IAS 29 in Argentina.

These decreases were partially offset by:

(iv) a decrease of US$ 320 million in financial costs, mainly attributable to:

a) US$ 160 million from Enel Brasil, mainly related to US$ 151 million in debt with Enel Finance International N.V., which was paid off on July 7, 2019, and US$ 9 million as a result of the devaluation of the Brazilian real against the U.S. dollar;

b) US$ 49 million from Enel Distribution Sao Paulo, explained by US$ 53 million due to the devaluation of the Brazilian real against the U.S. dollar, offset by US$ 4 million in higher expenses for updates to civil and labor contingencies;

c) US$ 27 million from Enel Distribution Rio, mainly due to the devaluation of the Brazilian real against the U.S. dollar;

d) US$ 27 million from Enel Distribution Goias, mainly due to US$ 20 million as a result of the devaluation of the Brazilian real against the U.S. dollar and US$ 7 million less in bank debt;

e) US$ 20 million from Edesur, explained by US$ 60 million due to the devaluation of the Argentine peso against the U.S. dollar, primarily offset by (i) US$ 40 million in higher expenses for updates to fines and debt to CAMMESA;

f) US$ 16 million less in expenses from Enel Generation Costanera, mainly US$ 11 million less in expenses on its debt to CAMMESA and US$ 5 million due to the devaluation of the Argentine peso against the U.S. dollar;

g) US$ 16 million from Enel Generation El Chocón, mainly due to lower expenses on its debt with CAMMESA;

h) US$ 14 million from Enel Distribution Ceara, mainly US$ 12 million as a result of the devaluation of the Brazilian real against the U.S. dollar;

i) US$ 12 million from Emgesa, explained by US$ 10 million due to the devaluation of the Colombian peso against the U.S. dollar and US$ 2 million less in bank debt expenses; and

j) US$ 8 million from Codensa, mainly US$ 7 million due to the devaluation of the Colombian peso against the U.S. dollar and US$ 2 million less in financial debt.

These decreases in financial costs were partially offset by increased financial costs of:

k) US$ 14 million from EGP Cachoeira Dourada; and

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l) US$ 12 million from Enel Américas, mainly explained by withholding tax on dividends from subsidiaries in Argentina and Peru.

Other Non-Operating Results

Other non-operating results decreased in 2020, explained by Enel Distribution Peru’s sale of assets in 2019.

Income Taxes

Total income tax expense increased US$ 330 million in 2020 compared to 2019, explained by increased expenses of:

(i) US$ 538 million from Enel Distribution Sao Paulo, of which US$ 553 million originated from deferred tax profit recorded in 2019, arising from the merger with Enel Investimento Sudeste S.A., and offset by US$ 15 million from the devaluation of the Brazilian real against the U.S. dollar;

(ii) US$ 13 million from Central Dock Sud, explained by a US$ 25 million tax benefit from the revaluation of its non-monetary tax assets and liabilities recorded in 2019, offset by US$ 12 million due to the devaluation of the Argentine peso against the U.S. dollar;

These increases in income tax expenses were partially offset by:

(iii) US$ 54 million from Edesur, mainly US$ 44 million in lower financial results in regulatory assets and liabilities recorded as a profit in 2019 and US$ 10 million due to the devaluation of the Argentine peso against the U.S. dollar;

(iv) US$ 47 million from Enel Cien, mainly explained by US$ 30 million lower financial results and US$ 17 million higher expenses in 2019 due to impairment losses on receivables;

(v) US$ 33 million from Enel Generation Costanera, primarily as a result of US$ 36 million less in financial results, offset by US$ 3 million due to the devaluation of the Argentine peso against the U.S. dollar;

(vi) US$ 31 million from Enel Distribution Rio, mainly explained by lower financial results;

(vii) US$ 24 million from Codensa, primarily due to US$ 12 million in financial results and US$ 12 million as a result of the devaluation of the Colombian peso against the U.S. dollar;

(viii) US$ 17 million from Enel Distribution Peru, due to lower financial results; and

(ix) US$ 14 million from Enel Generation Peru, mainly explained by the provision of legal contingencies with Empresa de Electricidad del Perú S.A.

The effective tax rate was 32.4% in 2020 and 9.8% in 2019. The recognition of deferred tax assets from the merger of Enel Investimento Sudeste S.A. with Enel Distribution Sao Paulo, registered in 2019, mainly explains this increase.

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The following table sets forth the tax effect of rates applied in other countries that result in a difference between domestic or nominal tax rates in Chile (4.7% for 2020 and 5.2% for 2019) and tax rates enacted in each foreign jurisdiction:

	Nominal Tax Rates (%)		Tax effect of rates applied in other countries (in millions of US$)
	2020	2019	2020	2019
Argentina	30.0	30.0	(2.8)	(18.1)
Brazil	34.0	34.0	(27.9)	(41.8)
Colombia	32.0	33.0	(43.1)	(55.7)
Peru	29.5	29.5	(7.9)	(10.3)
Total			(81.7)	(125.9)

Net Income

The following table sets forth our consolidated income before income taxes, income taxes and net income for the years ended December 31, 2020, and 2019:

	Year ended December 31,
	2020	2019	Change	Change
	(in millions of US$)			(in %)
Operating income(1)	2,152	2,842	(690)	(24.3)
Other results(1)	(404)	(436)	32	7.3
Income before income taxes	1,748	2,406	(658)	(27.4)
Income taxes	(567)	(236)	(330)	(139.7)
Net Income	1,181	2,170	(989)	(45.6)
Net income attributable to:
Net income attributable to the parent company	825	1,614	(789)	(48.9)
Net income attributable to non-controlling interests	356	556	(200)	(35.9)

(1) 2020 and 2019 restated: Please refer to Note 2.2.c of the Notes to our consolidated financial statements.

Net income attributable to the parent company on a consolidated basis reached US$ 825 million, a decrease of 48.9% compared to 2019, explained by: (i) lower demand primarily as a result of the Covid-19 pandemic, which affected our revenues mainly in the distribution segment; (ii) the regulatory agreement signed between Edesur and the Argentine government, which settled the outstanding reciprocal claims arising in the transition period 2006-2016; and (iii) the negative effect from the devaluation of the countries’ currencies where we operate.

B.Liquidity and Capital Resources.

Our primary assets are the stocks of our subsidiaries. The following discussion of cash sources and uses reflects the key drivers of our cash flow.

As a holding company, we receive cash from our subsidiaries and related companies. Our subsidiaries and associates’ cash flows may not always be available to satisfy our liquidity needs, mainly because they are not wholly-owned, but also because there is typically a time lag before we have access to those funds through dividends or capital reductions. However, we believe that cash flow generated from our business operations, cash balances, borrowings from commercial banks, short- and long-term intercompany loans, and ample access to the capital markets will continue to

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satisfy all our present requirements for cash to fund our working capital, debt service, dividends, and routine capital expenditures as discussed in further detail below.

Set forth below is a summary of our consolidated cash flow information for the years ended December 31, 2021, 2020 and 2019.

	Year ended December 31,
	2021	2020	2019
	(in millions of US$)
Net cash flows provided by operating activities	2,616	2,426	2,528
Net cash flows used in investing activities	(1,934)	(1,536)	(1,600)
Net cash flows from (used in) financing activities	(595)	(1,187)	(823)
Net increase (decrease) in cash and cash equivalents before effect of exchange rates changes	87	(297)	105
Effects of exchange rate changes on cash and cash equivalents	(198)	(135)	(70)
Cash and cash equivalents at the beginning of the period	1,507	1,939	1,904
Cash and cash equivalents at the end of the period	1,396	1,507	1,939

For the year ended December 31, 2021, net cash flows provided by operating activities totaled US$ 2,616 million, an increase of US$ 190 million, or 7.8%, compared to 2020. This increase is mainly explained by:

(i) an increase in cash flow due to an increase of US$ 4,967 million in cash collections from the sale of goods and services consisting principally of:

a) US$ 3,302 million from the generation segment mainly as a result of (i) US$ 2,008 million from EGP Américas companies that were acquired in the merger of EGP Américas with and into Enel Américas on April 1, 2021, and (ii) US$ 1,329 from Brazil due to higher energy sales in the Brazilian NIS as a result of the importation of energy from Argentina and Uruguay and higher spot prices offered by the market in the second half of 2021 due to the water crisis in Brazil; and

b) US$ 1,663 from the distribution segment mainly due to the recovery of customer collections, which decreased in 2020 as a result of the Covid-19 pandemic, including US$ 1,399 million from Brazil, US$ 185 million from Codensa, and US$ 106 million from Enel Distribución Perú.

This increase in operating activities was partially offset by:

(ii) a decrease in cash flow due to an increase of US$3,488 million higher payments to suppliers for the supply of goods and services explained by:

a) US$ 2,295 million from the generation segment mainly due to (i) US$ 1,646 million from EGP Américas companies that were acquired in the merger of EGP Américas with and into Enel Américas on April 1, 2021, and US$ 747 from Brazil due to higher imports of energy from Argentina and Uruguay; and

b) US$ 1,228 million from the distribution segment mainly due to an increase in economic production, which led to an increase in distributed energy, that had decreased in 2020 as a result of the Covid-19 pandemic, including US$ 1,192 million from Brazil and US$ 123 million from Codensa, partially offset by US$ 83 million from Edesur due to the devaluation of the Argentine peso against the U.S. dollar.

(iii) a decrease in cash flow due to a decrease of US$ 569 million in other cash collections from operating activities mainly due to US$ 617 million from the distribution segment in Brazil due to collections in 2020 related to the “Covid Account” (see Note 10 of the Notes to our consolidated financial statements);

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(iv) a decrease in cash flow due to an increase of US$ 466 million in other payments for operating activities mainly due to (i) an increase of US$ 331 million in payments by Enel Brasil primarily related to VAT payments and the Energy Development Account (see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Brazilian Electricity Regulatory Framework — 4. Tariffs — Energy Development Account) and (ii) an increase of US$ 139 million in payments by Codensa attributed to greater payments in “Codensa Hogar,” a program oriented to our residential customers to purchase products and services marketed by various business partners;

(v) a decrease in cash flow due to an increase of US$ 193 million in income tax payments related to greater payments of (i) US$ 86 million from Enel Brasil, on a consolidated basis, mainly due to our distribution subsidiaries, (ii) US$ 53 million from the EGP Américas companies that were acquired in the merger of EGP Américas with and into Enel Américas on April 1, 2021, and (iii) US$ 43 million from Enel Generation Peru.

(vi) a decrease in cash flow due to an increase of US$ 80 million in other outflows mainly explained by US$ 60 million from EGP Américas companies that were acquired in the merger of EGP Américas with and into Enel Américas on April 1, 2021, and US$ 38 from Enel Distribution Peru due to litigation settlements.

For the year ended December 31, 2020, net cash flows provided by operating activities totaled US$ 2,426 million, a decrease of US$ 102 million, or 4%, compared to 2019. This decrease is mainly explained by:

(i) a reduction of US$ 3,639 million in cash collections from the sale of goods and services mainly related to the impact of the Covid-19 pandemic on the devaluation of the local currency, lockdown periods that led to lower energy consumption and lower collection rates, all of which is mainly explained by decreases of:

a) US$ 3,211 million from Enel Brasil mainly explained by lower collections of:

◾ US$ 1,614 million by Enel Distribution Sao Paulo;

◾ US$ 703 million by Enel Distribution Goias;

◾ US$ 551 million by Enel Distribution Rio, and

◾ US$ 410 million by Enel Distribution Ceara;

b) US$ 228 million from Edesur in Argentina;

c) US$ 142 million from Codensa in Colombia; and

d) US$ 106 million from Enel Distribution Peru.

These reductions in operating activities were partially offset by:

(ii) an increase in cash flow due to a decrease of US$ 1,710 million in other payments for operating activities, mainly explained by (i) a decline of US$ 1,476 million in payments by Enel Brasil, caused by the effects of the devaluation of the Brazilian real against the U.S. dollar in our energy distribution subsidiaries and (ii) a decrease of US$ 228 million in payments by Codensa, attributed to the devaluation of the Colombian peso against the U.S. dollar and lower payments in “Codensa Hogar,” a program oriented to our residential customers to purchase products and services marketed by various business partners;

(iii) an increase in cash flows due to a decrease of US$ 1,158 million in payments to suppliers for goods and services, mainly explained by the devaluation of the local currencies against the U.S. dollar of:

a) US$ 789 million in payments from Enel Brasil, driven by decreases of

◾ US$ 518 million in payments from Enel Distribution Sao Paulo,

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◾ US$ 186 million in payments from Enel Distribution Rio,

◾ US$ 123 million in payments from Enel Distribution Goias,

partially offset by US$ 30 million in higher Enel Brasil payments of technical services;

b) US$ 253 million in payments from Edesur; and

c) US$ 126 million in payments from Codensa.

(iv) an increase of US$ 441 million in other cash collections from operating activities, mainly explained by an increase of US$ 617 million from Enel Brasil, on a consolidated basis, explained by collections related to the “Covid Account” (see Note 10 of the Notes to our consolidated financial statements):

a) US$ 255 million from Enel Distribution Sao Paulo,

b) US$ 115 million from Enel Distribution Ceara,

c) US$ 133 million from Enel Distribution Rio, and

d) US$ 114 million from Enel Distribution Goias.

(v) an increase in cash flows due to a US$ 136 million decrease in payments to employees, mainly from decreases associated with the devaluation of the local currencies:

a) US$ 115 million from Enel Brasil; and

b) US$ 20 million from our Argentine subsidiaries.

(vi) an increase in cash flow due to a decrease of US$ 57 million in other outflows, mainly from Enel Brasil, explained by the devaluation of the Brazilian real against the U.S. dollar.

(vii) an increase in cash flow due to a decrease of US$ 34 million in income tax payments, related to a reduction of US$ 66 million from Enel Brasil, on a consolidated basis, mainly due to the devaluation of the Brazilian real against the U.S. dollar and lower payments by Enel Distribution Rio and Enel Distribution Goias, partially offset by higher payments from Emgesa and Codensa of US$ 22 million and US$ 11 million, respectively.

For the year ended on December 31, 2021, net cash flows used in investment activities were outflows amounting to US$ 1,934 million, representing an increase of US$ 398 million, or 25.9%, compared to 2020. This increase is mainly explained by:

(i) an increase of US$1,027 million in disbursements due to (i) US$ 964 million as a result of the incorporation of property, plant and equipment mainly from EGP Américas companies that were acquired in the merger of EGP Américas with and into Enel Américas on April 1, 2021, and (ii) US$ 86 million from Edesur mainly due to greater investments in distribution networks; and

(ii) an increase of US$ 431 million due to the incorporation of intangible assets under IFRIC 12 from our Brazilian distribution subsidiaries and payments of licenses in some subsidiaries of EGP Brasil.

These increases in investment activities were partially offset by:

(iii) an increase of US$1,031 million in other cash inflows mainly due to US$ 1,022 million from the initial balances of cash and cash equivalents incorporated by the EGP Américas companies; and

(iv) an increase of US$ 56 million of net financial investments made with EFI and other financial institutions.

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For the year ended on December 31, 2020, net cash flows used in investment activities were outflows amounting to US$ 1,536 million, representing a decrease of US$ 64 million, or 4.0%, compared to 2019, mainly from:

(i) a decrease of US$ 78 million in investments on fixed assets realized by our subsidiaries, mainly from Argentina of US$ 88 million, associated with the devaluation of the Argentine peso against the U.S. dollar;

(ii) a decrease of US$ 28 million for the incorporation of intangible assets (under IFRIC 12) of our Brazilian distribution subsidiaries, mainly associated with the devaluation of the Brazilian real against the U.S. dollar of US$ 181 million, offset by an increase in investment of US$ 154 million; and

(iii) a decrease of US$ 98 million in cash flows used in the purchase of non-controlling interests, as a result of Enel Brasil increasing its ownership interest in Enel Distribution Sao Paulo by 4.1% in November and December 2019, which did not recur in 2020.

These increases in investment activities were partially offset by:

(iv) a decrease of US$ 79 million in investment in time deposits with a maturity greater than 90 days; and

(v) a decrease of US$ 68 million in interest income received.

For further information regarding the acquisition of fixed assets in 2021 and 2020, please see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures, and Divestitures.”

For the year ended December 31, 2021, net cash flows used in financing activities amounted to US$ 595 million, reflecting a decrease of US$ 592 million, or 49.9% compared to 2020. This decrease is mainly explained by:

(i) an increase of US$1,081 million of bank loans and bonds granted to (i) our distribution subsidiaries in Brazil for US$ 738 million; (ii) Emgesa for US$ 267 million; and (iii) EGP Américas companies for US$ 131 million;

(ii) an increase of US$980 million in loans from EFI, a related company, of which US$ 879 million were granted to our distribution subsidiaries in Brazil and US$ 83 million to Enel Américas; and

(iii) a decrease of US$ 95 million of dividend payments to third parties mainly due to lower payments by us of US$ 395 million, offset by an increase of (i) US$ 258 million in dividend payments by Codensa and Emgesa and (ii) US$ 28 million by Enel Fortuna.

These decreases in financing activities were partially offset by:

(iv) an increase of US$ 1,083 million in payments of loans and bonds mainly explained by: (i) US$ 449 million paid by our distribution subsidiaries in Brazil; (ii) US$ 302 million paid by Emgesa; (iii) US$ 108 million paid by Codensa; (iv) US$ 54 million paid by our generation subsidiaries in Brazil; (v) US$ 97 million paid by our generation subsidiaries in Peru; and (vi) US$ 33 million paid by us; and

(v) an increase of US$ 445 million in loan payments to EFI.

For the year ended December 31, 2020, net cash flows used in financing activities amounted to US$ 1,187 million, reflecting an increase of US$ 364 million, or 44.2% compared to 2019, this increase is mainly due to:

(i) an increase of US$ 3,253 million in bank loan and bond financings obtained, including US$ 2,461 million in loans granted to Enel Brasil to pay its debt with EFI, a related company, which refinanced our acquisition of Enel Distribution Sao Paulo; US$ 1,540 million by our distribution subsidiaries in Brazil, offset by new loans of US$ 480 million granted to Enel Américas, US$ 275 million to Enel Peru and US$ 24 million to Enel Generation Piura; and

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(ii) an increase of US$ 334 million in dividend payments to third parties, excluding dividends paid to us, due to higher dividend payments of US$ 319 million from Enel Américas and US$ 16 million from Codensa and Emgesa.

These increases in financing activities were partially offset by:

(iii) a decrease of US$ 3,000 million in proceeds from the share issuance in Enel Américas' capital increase in 2019, net of issuance costs, which did not recur in 2020;

(iv) a decrease of US$ 3,006 million in payments of bank loans and bond financings, including US$ 2,470 million in lower payments by Enel Brasil, US$ 667 million by our distribution subsidiaries in Brazil, US$ 247 million by Volta Grande, US$ 144 million by Emgesa and US$ 155 million by Codensa, partially offset of US$ 505 million of increased payments by Enel Américas and US$ 121 million by Enel Peru;

(v) a decrease of US$ 2,662 million of debt payments to EFI, a related company, to finance the purchase of Enel Distribution Sao Paulo, which payment was made with the cash proceeds of the Enel Américas capital increase;

(vi) a decrease of US$ 288 million in interest expense, mainly from Enel Brasil on a consolidated basis, including US$ 172 million paid by Enel Brasil to EFI and US$ 87 million by our distribution subsidiaries in Brazil, and US$ 22 million by Emgesa; and

(vii) US$ 295 million in loans from EFI, of which US$ 150 million were granted to Enel Américas and US$ 145 million to Enel Distribution Rio.

For a description of liquidity risks resulting from the inability of our subsidiaries to transfer funds, please see “Item 3. Key Information — C. Risk Factors — We depend on payments from our subsidiaries and associates to meet our payment obligations.” Please see Notes 20 and 23 of the Notes to our consolidated financial statements for further details regarding the features and conditions of financial obligations and financial derivatives. These notes also refer to the material cash requirements of contractual and other known contractual and other obligations.

The table below sets forth our cash payment of contractual obligations as of December 31, 2021:

	Payments due by Period
Contractual Obligation	Total	2022	2023-2024	2025-2026	After 2026
	(in millions of US$)
Purchase obligations(1)	71,800	21,501	16,202	14,241	19,856
Bank debt	3,979	848	1,770	736	625
Pension and post-retirement obligations(2)	2,800	312	597	573	1,318
Local bonds(3)	2,486	459	837	510	680
Interest expense	1,925	472	645	333	475
Yankee bonds	601	0	0	601	0
Lease Obligations	438	77	72	53	236
Other debt(4)	86	31	20	11	24
Total contractual obligations(5)	84,115	23,700	20,143	17,058	23,214

(1) Includes generation, transmission, and distribution business purchase obligations, comprised mainly of energy purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of US$ 71,800 million, 95% corresponds to energy purchased for distribution, and 4% primarily to fuel supply, maintenance of medium- and low-voltage lines, supplies of cable and utility poles, and energy purchased for generation. The remaining 1% corresponds to miscellaneous services, such as LNG regasification, fuel transport, and coal handling.

(2) We have funded and unfunded pension and post-retirement benefit plans. Our funded plans have annual contractual commitments for contributions, which do not change based on funding status. Cash flow estimates in the table are based on such obligations, including certain estimated variable factors such as interest. Cash flow estimates in the

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table relating to our unfunded plans are based on future discounted payments necessary to meet all our pension and post-retirement obligations.

(3) Local bond debt includes the value of derivatives.

(4) Other debt includes governmental loan facilities, supplier credits, and short-term commercial paper, among others.

(5) Represents only obligations with third parties.

We coordinate the overall financing strategy of our controlled subsidiaries. However, our operating subsidiaries independently develop their capital expenditure plans and finance their capital expansion programs through internally generated funds or direct financings. We have no legal obligations or other commitments to support our subsidiaries financially. In some cases, our subsidiaries may be financed by us through intercompany loans. For information regarding our commitments for capital expenditures, see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures, and Divestitures” and “— C. Liquidity, capital resources.” Notwithstanding our corporate policy in connection with the expectation of financial autonomy for our subsidiaries, we have provided financial support to some of our subsidiaries to a minimal extent in the past.

As of December 31, 2021, our consolidated interest-bearing debt, mainly consisting of accounts payable to related parties and financial liabilities, totaled US$ 7,604 million and had the following maturity profile:

Company	2022	2023-2024	2025-2026	After 2026
	(in millions of US$)
Enel Américas	1,463	2,682	1,895	1,564

Set forth below is a breakdown by country for debt maturing in 2022:

Country	2022
	(in millions of US$)
Argentina	6
Brazil	725
Colombia	380
Costa Rica	14
Panama	6
Peru	323
Chile	9

We have accessed the international equity capital markets (including several SEC-registered ADS issuances by our predecessor) in 1993, 1996, 2000, 2003, 2013, and 2019. Since 1996, we have also issued a total of US$ 1,750 million in bonds in the United States (“Yankee Bonds”).

The following table lists the Yankee Bonds issued by us that are outstanding as of December 31, 2021. The weighted -average annual coupon interest rate for such bonds is 4.00%, without giving effect to each bond’s duration or put options.

				Aggregate Principal Amount
Issuer	Term	Maturity	Coupon	Issued	Outstanding
			(%)	(in millions of US$)
Enel Américas	10 years	October 2026	4.00	600	600
Enel Américas(1)	30 years	December 2026	6.60	150	1
Total			4.00(2)	750	601

(1) Holders of our 6.6% Yankee Bonds due 2026 exercised a put option on December 1, 2003, for an aggregate principal amount of US$ 149 million, leaving less than US$ 1 million outstanding.

(2) Weighted-average coupon by outstanding amount.

We, and our subsidiaries in the countries in which we operate, have access to the domestic capital markets where we have issued debt instruments, including commercial paper and medium and long-term bonds that are primarily sold to pension funds, life insurance companies, and other institutional investors.

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The following table lists UF-denominated Chilean bonds issued by us outstanding as of December 31, 2021. 

				Aggregate Principal Amount
Issuer	Term	Maturity	Coupon (inflation adjusted rate)	Issued	Outstanding
			(%)	(in millions of UF)	(in millions of UF)	(in millions of US$)
Enel Américas Series B2	21 years	June 2022	5.75	2.5	0.1	3.3

For a complete description of local bonds issued by us, see “Secured and unsecured liabilities by company” in Note 20 of the Notes to our consolidated financial statements.

The following table lists our foreign subsidiaries’ local bonds, outstanding as of December 31, 2021. We present aggregate information for each company. The maturity column for each company reflects the issuance with the longest maturity, and the coupon rate corresponds to the weighted-average coupon of all issuances for each company.

Issuer	Maturity	Coupon(1)	Aggregate Principal Amount Outstanding
		(%)	(in millions of US$)
Enel Distribution Sao Paulo	April 2031	9.59%	778
Codensa	April 2030	7.12%	552
Emgesa	May 2030	9.43%	467
Enel Distribution Peru	November 2038	5.89%	309
Enel Distribution Ceara	June 2025	12.23%	258
EGP Volta Grande	October 2029	14.91%	134
Enel Generation Peru	January 2028	6.33%	16
Enel Brasil	June 2029	18.62%	4
Total			2,518

(1) Many of the coupon rates are variable rates based on local indices, such as inflation. The table reflects the coupon rate taking into account each local index as of December 31, 2021.

We frequently participate in the international commercial bank markets and have access to fully committed credit lines. As of December 31, 2021, the outstanding balance of the committed credit lines was as follows:

Borrower	Type	Last Maturity	Facility Amount	Amount Drawn
			(in millions of US$)	(in millions of US$)
Enel Américas	Syndicated revolving loan	February 2024	500	—
Enel Américas	Bilateral revolving loan	February 2024	500	—
Total			1,000	—

As detailed below, our subsidiaries also had access to fully committed credit lines in the local markets as of December 31, 2021.

Borrower	Type	Last Maturity	Facility Amount	Amount Drawn
			(in millions of US$)	(in millions of US$)
Enel Brasil	Bilateral revolving loan	July 2022	272	—
Enel Generation Peru	Bilateral revolving loan	October 2023	63	—
Codensa	Bilateral revolving loan	April 2022	61	—
Enel Distribution Peru	Bilateral revolving loan	September 2023	56	—
Emgesa	Bilateral revolving loan	April 2022	42	—
EGP Peru	Bilateral revolving loan	December 2022	30	6
Enel Trading Brasil	Bilateral revolving loan	March 2022	18	—
Total			542	6

We have access to fully committed undrawn revolving loans, both international and domestic. The disbursements are not subject to compliance with a condition precedent regarding the non-occurrence of a “Material Adverse Effect”

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(or MAE, as defined contractually), thus allowing us total flexibility to draw down, under any circumstances including situations involving an MAE, up to US$ 1.5 billion in the aggregate as of December 31, 2021.

We also have access to an uncommitted Chilean bank facility with an approved line of credit for US$ 1.2 million which was undrawn as of December 31, 2021. Unlike the committed lines described above, which are not subject to any MAE condition precedent before disbursements, this facility is subject to a greater risk of not being disbursed in the event of an MAE. It could limit our liquidity under such circumstances. Our subsidiaries also have access to uncommitted local bank facilities for a total amount of US$ 301 million, which were undrawn as of December 31, 2021.

We and our subsidiaries have debt instruments that include financial covenants. For Enel Américas, only our Series B2 Chilean bonds due in June 2022 include financial covenants. As of December 31, 2021, the most restrictive financial covenant affecting us was the Ratio of Assets subject to Guarantees. Under such covenant, the maximum additional assets that could be subject to guarantees without a breach is US$ 6.4 billion. As of December 31, 2021, our subsidiaries and we comply with the covenants contained in our debt instruments.

As is customary in the credit and capital market debt facilities, a significant portion of our financial indebtedness is subject to cross-default provisions. Each of the revolving credit facilities described above and our Yankee Bonds have cross-default provisions with different definitions, criteria, materiality thresholds, and applicability as to the subsidiaries that could give rise to a cross-default.

The cross-default provision of our syndicated revolving loans may be triggered by one of our other debts, on an individual basis, with an outstanding principal exceeding US$ 150 million.

Cross-default provisions of our Yankee Bonds, issued in 2016, maturing in October 2026, may be triggered by another debt of ours or by Significant Subsidiaries, as defined in the indenture. A matured default on an individual basis could result in a cross-default to our Yankee Bonds if such matured default, on an individual basis, has a principal exceeding US$ 150 million or its equivalent in other currencies. Additionally, in the Yankee Bonds issued in 1996, maturing in December 2026, the cross-default could be triggered only by other debt of Enel Américas, on an individual basis, exceeding US$ 30 million or its equivalent in other currencies.

In the case of a matured default above the materiality threshold, Yankee Bondholders would have the option to accelerate the debt if either the trustee or bondholders representing no less than 25% of the aggregate debt of a particular series then outstanding choose to do so. All of our Yankee Bonds are unsecured and not subject to any guarantees by any of our subsidiaries or parent company or contain any financial covenants. Our local bonds do not have subsidiary cross-default provisions. They can be triggered only by default of Enel Américas if the amount in default, on an individual or aggregate basis, exceeds 3% of the Total Consolidated Assets, as defined in its respective contract.

Payment of dividends and distributions by our subsidiaries and affiliates represent an essential source of funds for us. The payment of dividends and distributions by certain subsidiaries and affiliates are potentially subject to legal restrictions, such as legal reserve requirements, capital and retained earnings criteria, and other contractual conditions. Legal counsel in the countries where our subsidiaries and affiliates operate has informed us of the current legal restrictions regarding the payment of dividends or distributions in the jurisdictions where such subsidiaries or affiliates are incorporated. We are currently in compliance with legal restrictions that could otherwise affect the payment of dividends or distributions to us. Certain credit facilities and investment agreements of our subsidiaries or affiliates restrict dividends or distributions in exceptional circumstances. For a description of liquidity risks resulting from our company status, please see “Item 3. Key Information — C. Risk Factors —We depend on payments from our subsidiaries and associates to meet our payment obligations.”

We expect to be able to refinance our indebtedness as it becomes due, fund our purchase obligations with internally generated cash, and fund capital expenditures with a mixture of internally generated cash and borrowings.

LIBOR Transition

The U.K. Financial Conduct Authority found that the London Interbank Offered Rate (“LIBOR”) had inconsistencies in its calculations and recommended that it be based on actual transactions. As a result, the authority agreed to stop requiring banks to comply with the submission of interbank rates to calculate LIBOR as of December 31, 2021. On March 5, 2021, LIBOR succession dates (December 31, 2021, for EUR, CHF, JPY, and GBP LIBOR for all

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tenors and one week and two-month USD LIBOR and June 30, 2023, for all other USD LIBOR tenors) were announced. LIBOR will be discontinued, and alternative benchmark rates are expected to replace it. Currently, there is no consensus as to a replacement benchmark rate. Still, market participants expect a risk-free rate, such as the Secured Overnight Financing Rate (“SOFR”), a broad measure of the cost of overnight borrowing, collateralized by U.S. Treasury securities, to replace LIBOR in operations involving U.S. banks.

This reform may affect us in the following ways:

● Interest payments on loans and derivatives: Financial risks arising from using a new benchmark rate, where interest payments previously based on LIBOR may increase or decrease. There is also a risk concerning data availability relating to the timely disclosure of market information, which may also affect the effectiveness of hedges.

● Financial systems: Operational risk arising from the necessity to modify and adapt our financial systems to report, evaluate, or calculate payments under the new required benchmark rates.

● Fair value measurement: Financial risks arising from how changes to benchmark rates in our debt obligations could adversely affect fair value measurements.

● Contracts: Legal and financial risk relating to the renegotiation of ISDA and local derivative contracts.

As of December 31, 2021, our total outstanding debt exposure to LIBOR was US$ 532 million, all of which includes provisions to transition from LIBOR to an alternative benchmark rate. However, at this time, we cannot determine the extent that these changes will affect us. For more information, see “Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4, and IFRS 16: Interest Rate Benchmark Reform (Phase 2)” in Note 2.2.a) of the Notes to our consolidated financial statements.

C. Research and Development, Patents and Licenses, etc.

None.

D. Trend Information.

Through our subsidiaries and affiliates, we engage in the generation, distribution, and transmission of electricity in Argentina, Brazil, Colombia, and Peru. With the merger with EGP Américas effective on April 1, 2021, we added exposure to other countries in Central America, including Costa Rica, Guatemala, and Panama.

The electricity sector continues to experience more restrictive government regulations, new technologies and business models, and greater competition. Our businesses depend on a wide range of conditions that may result in significant variability in our earnings and cash flows from year to year. We seek to establish a conservative and well-balanced commercial policy on a country-by-country basis to control relevant variables, reduce risks, and stabilize the results of our operations.

Generation

Through the merger with EGP Américas, we added 4.7 GW of installed capacity, and in the advanced development stage that runs until 2024, there are another 2.7 GW. We expect that renewable energy will boost the growth of our generation business in the long term. We have a potential pipeline of an additional 22 GW, which will be the base for our expected renewable energy growth after 2024.

Distribution

We anticipate that our distribution companies will maintain their profitability during the periods between periodic tariff-setting processes, according to the price cap tariff model, due to growth and economies of scale. After tariffs have been set, the companies can increase their efficiency and obtain extra profits associated with such efficiencies.

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Adverse Effects of Covid-19 Pandemic

Increases in infection rates and extraordinary governmental measures such as quarantines and lockdown periods may adversely affect our business and results. For more information see “Item 3. Key Information — D. Risk Factors— We are subject to the adverse effects of worldwide pandemics.”

Armed Conflict between Russia and Ukraine

The effects of the armed conflict between Russia and Ukraine, which began in February 2022, on our company are unknown. Although we do not have direct business transactions with suppliers, clients, or lenders from Russia or Ukraine, our business, results of operations, and financial condition may be impacted by (i) limited access to financial markets; (ii) possible interruptions in the global supply chain; and (iii) an increase in inflationary pressures in the countries in which we operate, which could increase the rates charged to our customers.

E. Critical Accounting Estimates

Our significant accounting policies are more fully described in Notes 2 and 3 to the Notes of our consolidated financial statements included elsewhere in this Report. Certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations. In applying these critical accounting policies, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates, as described in Note 2.3 of the Notes to our consolidated financial statements.

Item 6.  Directors, Senior Management and Employees

A. Directors and Senior Management.

Directors

Our board of directors consists of seven members elected for a three-year term at the Ordinary Shareholders’ Meeting (“OSM”). Following the end of their term, they may be re-elected or replaced. If a vacancy occurs in the interim, the board of directors would elect a temporary director to fill the vacancy until the next OSM, at which time the entire board of directors will be elected for new three-year terms. Our executive officers are appointed and hold office at the discretion of the board of directors.

Our current board of directors was elected at the OSM held on April 29, 2021, for a three-year term that ends in April 2024. The members of our board of directors as of December 31, 2021, were as follows:

Directors	Position	Age(1)	Current Position Held Since
Borja Acha B.	Chairman	57	2015
José Antonio Vargas L.	Director	58	2016
Giulia Genuardi	Director	43	2021
Francesca Gostinelli	Director	48	2021
Hernán Somerville S.	Director	81	1999
Patricio Gómez S.	Director	58	2016
Domingo Cruzat A.	Director	66	2016

(1) As of the date of this Report.

Set forth below are brief biographical descriptions of the members of our board of directors as of December 31, 2021:

Borja Acha B.: Mr. Acha is also the Secretary of the board of directors and Director of Legal Affairs and Corporate Matters of Endesa, S.A., a Spanish subsidiary of Enel. Previously, he was the Secretary and General Counsel of Enel (2012-2015) and General Counsel of Endesa, S.A. (1998-2013). Mr. Acha holds a law degree from Universidad Complutense de Madrid.

José Antonio Vargas L.: Mr. Vargas has also been the chairman of Codensa and Emgesa since 2006. He has more than 20 years of experience in the Colombian energy sector, especially in the gas, coal, and electricity industries. From

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1999-2006, he was CEO of Empresa de Energía de Bogotá S.A. (now Grupo Energía Bogotá S.A.). Mr. Vargas holds a law degree from Colegio Mayor de Nuestra Señora del Rosario, focusing on private and public administration.

Giulia Genuardi: Ms. Genuardi has served as the Head of Planning, and Sustainability and Human Rights Performance Management of Enel since 2021. From 2019-2021, she worked for the European Lab at the European Financial Reporting Advisory Group (EFRAG). From 2008-2013, Ms. Genuardi was Secretary to the Enel Supervisory Council. Ms. Genuardi joined Enel in May 2003 as part of the internal auditing team and holds a degree in economic and business sciences from the Università di Palermo and a graduate degree in financial management from Luiss Business School.

Francesca Gostinelli: Ms. Gostinelli has served as Global Head of Strategy for Enel since 2019. From 2007-2019, Ms. Gostinelli held managerial positions in international regulations, business development, strategy, and served as an advisor on several Enel management councils. Ms. Gostinelli joined Enel in 2007 and holds a degree in environmental engineering from the Università degli Studi di Firenze and a graduate degree in economics and energy and environmental management from the Escuela Superior Enrico Mattei.

Hernán Somerville S.: Mr. Somerville has been managing director and partner of Fintec since 1989. In 1992-2010, Mr. Somerville was the chairman of the Asociación de Bancos e Instituciones Financieras. From 2000-2010, he was a member of the Asia-Pacific Economic Cooperation Forum (APEC) and the chairman of the Fundación Chilena del Pacífico, a foundation that strengthens Pacific Ocean countries’ integration. Mr. Somerville holds a law degree from the Universidad de Chile.

Patricio Gómez-Sabaini C.: Mr. Gómez-Sabaini has been an executive director and partner of Sur Capital Partners since 2005. He has been a board member of BO Packaging since 2013, El Tejar Ltda. since 2007, and Nortel since 2016. Mr. Gómez-Sabaini holds a degree in business administration from George Mason University and an MBA from George Washington University.

Domingo Cruzat A.: Mr. Cruzat is director of Conpax, Stars, Empresa de Servicios Sanitarios de Los Lagos, and Corporación Esperanza. He has also been a board member of Tech Pack S.A., Viña San Pedro Tarapacá, Compañia Sud Americana de Vapores, Solfrut, Alto Inmobiliaria Plaza Santo Domingo, and Principal Financial Group, and was CEO of Watt’s Alimentos and Bellsouth Comunicaciones S.A. Mr. Cruzat holds a civil engineering degree from Universidad de Chile and an MBA from The Wharton School of the University of Pennsylvania.

Executive Officers

Set forth below are our executive officers as of December 31, 2021.

Executive Officers	Position	Age(1)	Joined Enel or Affiliate in	Current Position Held Since
Maurizio Bezzeccheri	Chief Executive Officer	63	1999	2018
Aurelio Ricardo Bustilho de Oliveira(2)	Chief Financial Officer / Planning & Control Officer	53	1999	2018
Simone Tripepi	Enel X South America Officer	51	2003	2019
Raffaele Cutrignelli(3)(4)	Internal Audit Officer	40	2005	2016
Domingo Valdés P.(3)	General Counsel	58	1993	1999

(1) As of the date of this Report.

(2) Mr. Bustilho de Oliveira temporarily assumed the role of Planning & Control Officer as of October 27, 2021.

(3) Mr. Cutrignelli and Mr. Valdés are executive officers of Enel Américas but are paid exclusively by Enel Chile S.A. They provide services to the Company under an intercompany agreement.

(4) Eugenio Belinchón Gueto assumed the role of Internal Audit Officer as of February 1, 2022.

Set forth below are brief biographical descriptions of our executive officers as of December 31, 2021:

Maurizio Bezzeccheri: Mr. Bezzeccheri was the country manager of Enel Argentina (2015-2018). He joined Enel as vice president of EGP Europe and director of Iberia and Latam and held managerial positions in multinational

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companies located in Europe, the Middle East, and the Americas. Mr. Bezzeccheri holds a degree in chemical engineering from Università degli Studi di Napoli.

Aurelio Ricardo Bustilho de Oliveira: Mr. Bustilho was CFO of Enel Brasil and served as finance director of Enel Green Power Cachoeira Dourada S.A. Mr. Bustilho holds a degree in business administration and an MBA from Coppead / UFRJ.

Simone Tripepi: Since joining Enel in 2003, Mr. Tripepi has worked in generation, energy management, and the CO₂ trading desk. In 2017, Mr. Tripepi created Enel X Latam’s regional structure and became head of Enel X South America. Mr. Tripepi holds a degree in engineering management from Università degli Studi di Roma “Tor Vergata.”

Raffaele Cutrignelli: Mr. Cutrignelli was the audit officer for Enel affiliates in Colombia (2015-2016) and the head of Latin American audit for EGP in Brazil (2013-2015). Mr. Cutrignelli holds a degree in international business from Nottingham Trent University and a graduate degree in audit and internal controls from Universitá di Pisa.

Domingo Valdés P.: Mr. Valdés is the general counsel of Legal and Corporate Affairs for both Enel Américas and Enel Chile and serves as secretary of both their boards of directors. He is a tenured professor of economic and antitrust law at Universidad de Chile, and graduated summa cum laude from this law school. Mr. Valdés also holds a Master of Law degree from the University of Chicago.

B. Compensation.

At the OSM held on April 29, 2021, our shareholders approved our board of directors’ compensation policy for 2021. Director compensation consists of a monthly fixed compensation of UF 216 per month and an additional fee of UF 79.2 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings, within the corresponding fiscal year. The Chairman of the Board is entitled to double the compensation compared to other directors under this policy.

Our Directors Committee members are paid a monthly fixed compensation of UF 72 per month and an additional fee of UF 26.4 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings, within the corresponding fiscal year.

If a director serves on one or more boards of directors of the subsidiaries or associate companies or serves as director of other companies or corporations where the economic group holds an interest directly or indirectly, the director can only receive compensation in one of these boards.

Our Company’s executive officers and our subsidiaries or affiliates will not receive compensation if they serve as directors of any subsidiary, associate company, or are affiliated in any way to our Company. However, the officer may receive compensation to the extent that it is expressly and previously authorized as an advance payment of the variable portion of the wage to be paid by the respective subsidiaries or associate companies, where the executive officer signed a work contract.

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In 2021, the total compensation paid to each of our directors, including fees for attending Directors Committee meetings, was as follows:

	Year ended December 31, 2021 (1)
Director	Fixed Compensation	Ordinary and Extraordinary Session	Directors Committee (Fixed Compensation)	Ordinary and Extraordinary Session (Directors Committee)	Total
	(in ThUS$)
Borja Acha B.(2)	—	—	—	—	—
José Antonio Vargas L.(2)	—	—	—	—	—
Giulia Genuardi	—	—	—	—	—
Francesca Gostinelli	—	—	—	—	—
Hernán Somerville S.	102	47	34	13	196
Patricio Gómez S.	102	47	34	13	196
Domingo Cruzat A.	102	47	34	13	196
Total	306	141	102	40	589

(1) The U.S. dollar equivalent of compensation paid in Chilean pesos was translated for these purposes using the average exchange rate for the year ended on December 31, 2021, of Ch$ 759.06 per US$ 1.00.

(2) Directors Acha, Vargas, Genuardi, and Gostinelli waived their compensation for their current positions as directors of the Company since they are employees of other companies in Enel.

We do not disclose any information about an individual executive officer’s compensation. Executive officers are eligible for variable compensation under a bonus plan. The annual bonus plan is paid to our executive officers for achieving company-wide objectives and for their contribution to our results and objectives. The yearly bonus plan provides a range of bonus amounts according to seniority level and consists of a certain multiple of gross monthly salaries. For the year ended December 31, 2021, the aggregate gross compensation, paid or accrued, for all our executive officers, attributable to the fiscal year 2021, was US$ 3.9 million in fixed compensation and US$ 0.1 million in benefits. For expatriate executive officers, no variable compensation was paid by us since they received their variable bonus from their home country in 2021. The other executive officers have been paid exclusively by Enel Chile and provide services to the Company under an intercompany agreement. Therefore, their variable bonus was paid by Enel Chile in 2021.

We entered into severance indemnity agreements with all our executive officers. We will pay a severance indemnity for voluntary resignation or termination by mutual understanding among the parties. The severance indemnity does not apply if the termination is due to willful misconduct, prohibited negotiations, unjustified absences, or abandonment of duties, among other causes, as defined in Article 160 of the Chilean Labor Code. All of our employees are entitled to severance indemnity pay if terminated due to our needs, as described in Article 161 of the Chilean Labor Code. We did not pay severance indemnity to our executive officers in 2021.

C. Board Practices.

Members of the board of directors do not have service contracts with us or with any of our subsidiaries that provide them benefits upon the termination of their service. Our current board of directors was elected at the OSM held on April 29, 2021, for a three-year term. For information about the directors in office as of December 31, 2021, and the year they began their service on the board of directors, see “Item 6. Directors, Senior Management and Employees — A. Directors and Senior Management” above.

Directors Committee (Audit Committee)

Set forth below are our members of the Directors Committee as of December 31, 2021:

Committee Member	Position on Committee
Hernán Somerville S.	President
Patricio Gómez S.	Member
Domingo Cruzat A.	Member

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Our Directors Committee performs the following functions:

• reviews financial statements and the reports of the external auditors before their submission for shareholders’ approval;

• presents proposals to the board of directors, who then undertake their recommendations to shareholders’ meetings for the selection of external auditors and private rating agencies;

• reviews information related to our transactions with related parties and reports the opinion of the Directors Committee to the board of directors;

• proposes to the board of directors a general policy on conflicts of interest, as well as reviews the related-party policy;

• examines the compensation framework and plans for managers, executive officers, and employees;

• prepares an Annual Management Report, including recommendations to shareholders;

• provides information to the board of directors about the convenience of recruiting external auditors to provide non-auditing services, when such services are not prohibited by law, depending on whether such services might affect the external auditors’ independence;

• oversees the work of external auditors;

• reviews and approves the annual auditing plan by the external auditors;

• evaluates the qualifications, independence, and quality of the auditing services;

• elaborates policies regarding the employment of former members of the external auditing firm;

• reviews and discusses problems or disagreements between management and external auditors regarding the auditing process;

• establishes procedures for receiving and dealing with complaints regarding accounting, internal controls, and auditing matters; and

• carries out other functions mandated to the Committee by the bylaws, our board of directors, or our shareholders.

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D. Employees.

The following table sets forth the total number of our personnel (both permanent and temporary employees) and the number of personnel (both permanent and temporary employees) of each of our consolidated subsidiaries as of December 31, 2021, 2020, and 2019:

Company	2021	2020	2019
Argentina
Edesur	3,507	3,500	3,519
Costanera	392	395	398
Dock Sud	90	86	86
El Chocón	47	49	48
Enel Trading Argentina	21	26	31
CTM and TESA	3	4	4
Enel Argentina	4	4	—
Total personnel in Argentina	4,064	4,064	4,086
Brazil
Enel Distribution Sao Paulo(1)	4,441	5,845	6,484
Enel Distribution Goias	1,321	1,123	1,119
Enel Distribution Ceara	1,111	1,122	1,118
Enel Distribution Rio	962	997	966
Enel Brasil(2)(3)	715	74	75
Enel X Brasil	128	126	146
Cachoeira Dourada	86	124	106
Fortaleza	54	61	63
Cien	37	38	33
EGP Volta Grande	15	13	14
Total personnel in Brazil	8,870	9,523	10,124
Chile
Enel Américas	57	51	53
Total personnel in Chile	57	51	53
Colombia
Codensa(4)	1,583	1,535	1,500
Emgesa	590	615	606
EGP Colombia(3)	86	—	—
Total personnel in Colombia	2,259	2,150	2,106
Peru
Enel Distribution Peru	621	597	598
Enel Generation Peru	311	306	286
Enel Generation Piura	31	31	36
EGP Peru(3)	14	—	—
Enel X Peru	12	9	6
Total personnel in Peru	989	943	926
Central America(3)
EGP Guatemala	94	—	—
EGP Panama	94	—	—
EGP Costa Rica	34	—	—
Total personnel in Central America	222	—	—
Total personnel(5)	16,461	16,731	17,295

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(1) The total personnel was reduced in 2021 and 2020 as compared to 2019 as a result of an organizational restructuring process that Enel Distribution Sao Paulo is currently undergoing in accordance with a plan implemented by the investment committee to increase efficiency.

(2) In November 2021, EGP Brasil was merged into Enel Brasil. Includes EGP Cumaru I, EGP Morro do Chapeu I, EGP Sao Goncalo I, and EGP Ventos Santa Angela I.

(3) On April 1, 2021, we completed the acquisition of EGP Américas S.p.A. by means of a merger. Prior to the merger, EGP Américas S.p.A. held the renewable energy generation businesses in Central and South America (outside Chile) previously held by Enel Green Power S.p.A.

(4) Includes Fontibon ZE and Usme ZE as of 2021.

(5) The total number of temporary employees is not significant.

The Chilean Labor Code entitles all employees in Chile who are fired for reasons other than misconduct to a severance indemnity payment. In most cases, contracted employees are entitled to a legal minimum severance indemnity payment of one month’s salary for each year (and every fraction thereof beyond six months) worked, subject to a maximum of 11 months’ salary.

Our employment contracts typically provide severance indemnity payments higher than those required by the Chilean Labor Code. In most cases, we respect seniority in accordance with the time that the employee first joined us or an affiliate. Therefore, employees hired by one of our Chilean affiliates or predecessor companies maintain their seniority in the company and are treated contractually as if we had hired them. Under such contracts, severance indemnity payments for most of our employees consist of one month’s salary for each full year worked (and every fraction thereof beyond six months), subject to a maximum of 25 months. Under our collective bargaining agreements and other employment contracts not covered by such agreements, we are typically obligated to make severance indemnity payments to all covered employees in cases of voluntary resignation or death in specified amounts that increase according to seniority and often exceed the amounts required under Chilean law.

Chile

We have the following collective bargaining agreements:

Company	Signed in	In Force until
Enel Américas - Collective Bargaining Agreement 1	July 2019	July 2022
Enel Américas - Collective Bargaining Agreement 2	January 2020	December 2022

Argentina

We have the following collective bargaining agreements:

Company(1)	Signed in	In Force until
Edesur - Collective Bargaining Agreement 1	2004	2007
Edesur - Collective Bargaining Agreement 2	2004	2007
El Chocón - Collective Bargaining Agreement 1	2012	2017
Costanera - Collective Bargaining Agreement 1	2011	2014
Costanera - Collective Bargaining Agreement 2	2012	2015

(1) Under Argentine law, the working conditions under the expired agreements continue until the signing of a new agreement, under the principle of ultra-activity established by Law No. 14,250/1953 (Art. 12).

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Brazil

We have the following collective bargaining agreements:

Company(1)	Signed in	In Force until
Enel Distribution Sao Paulo - Collective Bargaining Agreement	December 2021	May 2023
Enel Distribution Rio - Collective Bargaining Agreement	December 2021	September 2023
Enel Distribution Ceara - Collective Bargaining Agreement	February 2021	November 2022
Cien - Collective Bargaining Agreement	Oct 2021	April 2023
Cachoeira Dourada - Collective Bargaining Agreement	May 2021	April 2022
Fortaleza - Collective Bargaining Agreement	Sep 2021	April 2023
Enel Distribution Goias - Collective Bargaining Agreement	November 2020	April 2022
Enel Brasil - Collective Bargaining Agreement	December 2021	September 2023

(1) Under Brazilian law, collective bargaining agreements cannot last for more than two years.

Colombia

We have the following collective bargaining agreements:

Company	Signed in	In Force until
Codensa - Collective Bargaining Agreement 1	November 2019	December 2022
Codensa - Collective Bargaining Agreement 2(1)	May 2016	December 2019
Emgesa - Collective Bargaining Agreement 1	January 2022	December 2022
Emgesa - Collective Bargaining Agreement 2(1)	May 2016	December 2019

(1) This collective bargaining agreement is under negotiation as of the date of this Report.

Peru

We have the following collective bargaining agreements:

Company	Signed in	In Force until
Enel Distribution Peru - Collective Bargaining Agreement 1	2020	2023
Enel Distribution Peru - Collective Bargaining Agreement 2	2021	2023
Enel Generation Peru - Collective Bargaining Agreement 1(1)	2019	2021
Enel Generation Piura - Collective Bargaining Agreement 1	2022	2026

(1) This collective bargaining agreement is still under negotiation as of the date of this Report.

Panama

We have the following collective bargaining agreements:

Company	Signed in	In Force until
EGP Panama - Collective Bargaining Agreement 1	December 2020	December 2024

E. Share Ownership.

To the best of our knowledge, none of our directors or officers owns more than 0.1% of our shares or holds any stock options. It is not possible to confirm whether any of our directors or officers has a beneficial, rather than direct, interest in our shares. Any share ownership by all our directors and officers, in the aggregate, amounts to significantly less than 10% of our outstanding shares.

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Item 7.Major Shareholders and Related Party Transactions

A.Major Shareholders.

We have only one class of capital stock, and Enel, our ultimate controlling shareholder, has the same voting rights as our other shareholders. As of March 31, 2022, 22,598 shareholders of record held our 107,281,698,561 shares of common stock outstanding. Enel owned 88,260,048,702 shares of our common stock, representing an 82.3% direct ownership interest in us. There were four record holders of our ADS, as of such date.

It is not practicable for us to determine the number of ADSs or common shares beneficially owned in the United States. The depositary for our ADSs only knows the record holders, including the Depositary Trust Company and its nominees. As such, we are not able to ascertain the domicile of the ultimate beneficial holders represented by the four ADS record holders in the United States, nor are we able to determine the domicile of any of our foreign stockholders who hold our common stock, either directly or indirectly.

As of March 31, 2022, Chilean private pension funds (“AFPs”) owned 7.7% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 7.4% of our shares. ADS holders owned 1.8% of our shares, and 22,422 minority shareholders held the remaining 0.9% of our shares.

The following table sets forth information concerning ownership of the common stock as of March 31, 2022, concerning each stockholder known by us to own more than 5% of the outstanding shares of common stock:

	Number of Shares Owned(1)	Percentage of Shares Outstanding
Enel S.p.A. (Italy)	88,260,048,702	82.3%

(1) Includes 31,195,387,525 shares issued in the 2021 merger with EGP Américas on April 1, 2021, and 7,608,559,104 shares (including shares represented by ADSs) acquired in the 2021 partial tender offer concluded on April 13, 2021.

Enel, an Italian company and our controlling shareholder that beneficially owned 82.3% of our shares as of December 31, 2021, is a multinational power company and a leading integrated player in the global power and renewables markets. It is one of the largest European utility companies with operations in over 30 countries worldwide, and a consolidated installed capacity of approximately 90 GW. Enel distributes electricity through a network of over 2.2 million kilometers to 75 million end users. It is one of the world’s largest network operators and has one of the most extensive customer bases. Enel’s shares are listed on Euronext Milan organized and managed by Borsa Italiana S.p.A.

B.Related Party Transactions.

Article 146 of the Chilean Corporations Law defines related-party transactions as all transactions involving a company and any entity belonging to the corporate group, its parent companies, controlling companies, subsidiaries or related companies, board members, managers, administrators, senior officers or company liquidators, including their spouses, some of their relatives, and all entities controlled by them, in addition to individuals who may appoint at least one member of the company’s board of directors or who hold 10% or more of voting capital, or companies in which a board member, manager, administrator, senior officer, or company liquidator has been serving in the same position within the last 18 months.

Article 147 of the Chilean Corporations Law (“Article 147”) requires that related-party transactions must consider the corporate interest, as well as the prices, terms, and conditions prevailing in the market at the time of their approval. Article 147 provides that board members, managers, administrators, senior officers, or company liquidators having a personal interest or acting in negotiations of a related-party transaction must immediately inform the board of directors. Such a transaction shall only be approved if an absolute majority of the directors (excluding interested directors) consider the transaction beneficial for the corporate interest. Chilean law requires an interested director to abstain from voting on such a transaction. If an absolute majority of the directors are obliged to abstain from voting on any particular transaction, it shall only be approved if authorized unanimously by the independent directors or during an ESM. Board

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resolutions approving related-party transactions must be reported to the company’s shareholders at the next shareholders’ meeting.

The law described above, which also applies to our affiliates, provides for some exceptions. In some instances, the board’s approval would suffice for related-party transactions, under certain transaction thresholds when the transactions are conducted with another entity in which we hold 95% or more of their capital, or when such transactions are conducted in compliance with the related-party policies defined by the company’s board. At its meeting held on June 28, 2017, our board of directors updated our related-party transaction policy. This policy is available on our website at www.enelamericas.com.

If a transaction is not in compliance with Article 147, this will not affect its validity. However, our shareholders or we may demand compensation for damages from the individual associated with the infringement as provided by law.

In the countries where we operate, we do not manage our subsidiaries’ cash flows even when intercompany transactions are permitted; however, these may have adverse tax consequences.

The following are related-party transactions entered into between January 1, 2021, and March 31, 2022.

Lender	Borrower	Issuance Date	Maturity Date	Notional Amount (millions)	Interest Rate (%)	Outstanding Principal (millions of USD)(1)	Contract Type
EFI	Enel Américas	Feb-21	Feb-24	US$ 500	LIBOR + 1.08%	388	RCA(2)
EFI	Enel Distribution Ceara	Feb-21	Mar-25	R$ 500	IDC + 1.0% (3)	106	Term loan
EFI	Enel Distribution Goias	Apr-21	Mar-23	R$ 600	IDC + 1.29% (3)	127	Term loan
EFI	Enel Distribution Goias	Apr-21	Apr-23	R$ 160	IDC + 1.18% (3)	34	Term loan
EFI	Enel Distribution Rio	Apr-21	Apr-23	R$ 230	IDC + 0.9% (3)	49	Term loan
EFI	Enel Distribution Goias	Apr-21	Apr-23	R$ 290	IDC + 1.18% (3)	61	Term loan
EFI	Enel Distribution Rio	Jul-21	Jul-23	EUR 50	1.29%	56	Term loan
EFI	Enel Distribution Goias	Jul-21	Jul-23	EUR 36	1.29%	40	Term loan
EFI	Enel Distribution Rio	Jul-21	Jul-24	EUR 50	1.29%	56	Term loan
EFI	Enel Distribution Goias	Aug-21	Aug-24	EUR 20	1.53%	22	Term loan
EFI	Enel Brasil	Aug-21	Jul-22	R$ 800	IDC + 0.85% (3)	169	RCA(2)
EFI	Enel Distribution Goias	Sep-21	Sep-24	EUR 22	1.53%	24	Term loan
EFI	Enel Distribution Rio	Sep-21	Sep-24	EUR 50	1.53%	56	Term loan
EFI	Enel Distribution Goias	Sep-21	Sep-24	EUR 45	1.59%	50	Term loan
EFI	Enel Distribution Goias	Oct-21	Oct-24	EUR 73	1.59%	82	Term loan
EFI	Enel Distribution Rio	Oct-21	Oct-24	EUR 40	1.59%	45	Term loan
EFI	Enel Distribution Rio	Dec-21	Dec-24	EUR 55	1.65%	61	Term loan
EFI	Enel Distribution Rio	Dec-21	Dec-22	EUR 160	1.06%	179	Term loan
EFI	EGP Peru	Dec-21	Dec-22	US$ 30	LIBOR + 0.90%	16	RCA(2)
Enel Américas	Enel Brasil	Dec-21	Dec-23	US$ 150	3.17%	150	Term loan
EFI	Enel Distribution Goias	Feb-22	Feb-25	EUR 63	1.76%	71	Term loan
Enel Américas	Enel Brasil	Feb-22	Feb-24	US$ 225	3.50%	225	Term loan

(1) As of March 31, 2022.

(2) Revolving credit agreement.

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(3) Interbank deposit certificate.

On April 1, 2021, Enel Américas completed the merger of EGP Américas S.p.A. with and into Enel Américas and on April 16, Enel S.p.A. completed the partial tender offer for Enel Américas shares and ADSs . Please see “Item 4. Information on the Company — A. History and Development of the Company.”

There are various contractual relationships between Enel Chile and us to provide intercompany services. Enel Chile entered into intercompany agreements under which it provides services directly and indirectly to us. The services rendered by Enel Chile include specific legal, finance, treasury, insurance, capital markets, financial and documentary compliance, accounting, human resources, communications, security, relations with contractors, IT, tax, and other corporate support and administrative services. These services are provided and charged at market prices if there is a comparable reference service. If there are no similar services in the market, they will be provided at cost plus a specified percentage. The intercompany services contracts are valid for one year as of July 1, 2021, and subject every year to automatic renewal for one year.

As of the date of this Report, the abovementioned transactions have not experienced material changes. As of December 31, 2021, there were also some commercial transactions with related parties. Please see Note 10 of the Notes to our consolidated financial statements for more information regarding transactions with related parties.

C. Interests of Experts and Counsel.

Not applicable.

Item 8.Financial Information

A. Consolidated Statements and Other Financial Information.

See “Item 18. Financial Statements.”

Legal Proceedings

Our subsidiaries and we are parties to legal proceedings arising in the ordinary course of business. We believe it is unlikely that any loss associated with pending lawsuits will significantly affect the normal development of our business.

For detailed information as of December 31, 2021, on the status of the material pending lawsuits filed against us and our subsidiaries, please refer to Note 34.3 of the Notes to our consolidated financial statements.

Concerning the legal proceedings reported in the Notes to our consolidated financial statements, we use the criterion of disclosing lawsuits above a minimum threshold of US$ 25 million of potential impact to us, and, in some cases, qualitative criteria according to the materiality of the plausible effect on the conduct of our business. The lawsuit status includes a general description, the process status, and the estimate of the amount involved in each lawsuit.

Dividend Policy

Our board of directors presents an annual proposal for approval to the OSM for a final dividend payable each year. The dividend is accrued in the prior year and cannot be less than the legal minimum of 30% of annual net income. The proposal also states the dividend policy for the current fiscal year. Additionally, our board of directors generally establishes an interim dividend for the current fiscal year, payable in January of the following year and deducted from the final dividend payable in May of the following year. The board of directors establishes the interim dividend, which is not subject to restrictions under Chilean law.

For dividends accrued in the fiscal year 2021, on November 25, 2021, the board of directors agreed to distribute an interim dividend of US$ 0.00096 per share of common stock on January 28, 2022, equal to 15% of consolidated net income as of September 30, 2021. The interim dividend was paid in Chilean pesos, considering the U.S. dollar Observed Exchange Rate as of January 24, 2022. At the OSM held on April 26, 2022, our shareholders approved a final dividend of US$ 0.00207 per share for the fiscal year 2021, equivalent to a payout of 30% of annual net income for 2021. The final dividend for the fiscal year 2021 will be distributed in May 2022, after deducting the interim dividend paid in January 2022.

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For dividends corresponding to the fiscal year 2022, our board of directors presented the following dividend policy at the OSM held on April 26, 2022:

● An interim dividend, accrued in the fiscal year 2022 and amounting to 15% of consolidated net income as of September 30, 2022, to be paid in January 2023.

● A final dividend payout equal to 30% of the annual net income for the fiscal year 2022, to be paid in May 2023, from which the interim dividend paid in January 2023 will be deducted.

This dividend policy is conditioned on generating net profits in each period and expectations of future profit levels and other conditions that may exist at the time of such dividend declaration. The proposed dividend policy is subject to our board of directors’ right to change the amount and timing of the dividends under prevailing circumstances at the time of the payment.

Dividend payments are potentially subject to legal restrictions, such as legal reserve requirements, capital and retained earnings criteria, and other contractual restrictions such as the non-default on credit agreements. For example, Enel Generation Piura may not pay dividends unless it complies with certain financial covenants. However, these potential legal and contractual restrictions do not currently affect our ability or any of our subsidiaries’ ability to pay dividends. For additional information, see “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources.”

Shareholders of each subsidiary and affiliate agree on the final dividend payments. There are currently no material currency controls that prohibit us from repatriating the dividend payments from our non-Chilean principal subsidiaries and affiliates.

Dividends are paid to shareholders of record as of midnight of the fifth business day before the payment date. Holders of ADSs on the applicable record dates will be entitled to receive dividend payments.

Dividends

For each of the years indicated, the table below sets forth the dividends distributed by us in U.S. dollars per common share and ADS. For additional information, see “Item 10. Additional Information — D. Exchange Controls.”

	Dividends Distributed(1)
	US$	US$
Year	per Share	per ADS(2)
2021	0.00385	0.19
2020	0.01061	0.53
2019	0.00836	0.42

(1) This table reports dividends paid rather than dividends accrued within any given year. These amounts do not reflect a reduction for Chilean withholding taxes, if applicable. Figures have been rounded.

(2) One ADS = 50 shares of common stock.

For a discussion of Chilean withholding taxes and access to the formal currency market in Chile in connection with the payment of dividends and sales of ADSs and the underlying common stock, see “Item 10. Additional Information — E. Taxation” and “Item 10. Additional Information — D. Exchange Controls.”

B. Significant Changes.

None.

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Item 9.The Offer and Listing

A. Offer and Listing Details.

Our shares of common stock are listed and traded on the Chilean Stock Exchanges under the trading symbol “ENELAM,” and our ADSs are listed and traded on the NYSE under the trading symbol “ENIA.”

B. Plan of Distribution.

Not applicable.

C. Markets.

In Chile, our common stock is traded on the following stock exchanges: the Santiago Stock Exchange (Bolsa Comercio de Santiago) (“SSE”) and the Chilean Electronic Stock Exchange (Bolsa Electrónica de Chile) (“ESE”). These stock exchanges operate on business days from 9:30 a.m. to 4:00 p.m., which may differ from New York City time by up to two hours, depending on the season. As of December 31, 2021, the SSE and ESE accounted for 97% and 3%, respectively, of our total equity traded in Chile.

In the United States, our common stock trades on the NYSE, our primary market, in the form of ADSs. Each ADS represents 50 shares of common stock, with the ADS in turn evidenced by American Depositary Receipts (“ADRs”). The ADRs were issued under the Third Amended and Restated Deposit Agreement dated as of March 28, 2013, among us, Citibank, N.A. as Depositary (the “Depositary”), and the holders and beneficial owners from time to time of ADRs issued thereunder (the “Deposit Agreement”). The Depositary treats only persons in whose names ADRs are registered in the books of the Depositary as owners of ADRs. The NYSE operates on business days from 9:30 a.m. to 4:00 p.m.

The following table contains information regarding the amount of total traded shares of common stock and the

corresponding percentage traded per market during 2021:

Market	Number of shares of common stock traded	Percentage
Chile(1)	27,049,187,862	58.5%
United States (One ADS = 50 shares of common stock)(2)	19,204,683,400	41.5%
Total	46,253,871,262	100.0%

(1) Includes the SSE and ESE.

(2) Includes the NYSE and over-the-counter trading.

D.  Selling Shareholders.

Not applicable.

E.  Dilution.

Not applicable.

F.  Expenses of the Issue.

Not applicable.

Item 10.Additional Information

A. Share Capital.

Not applicable.

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B. Memorandum and Articles of Association.

Description of Share Capital

Set forth below is certain information concerning our share capital and a summary of certain significant Chilean law provisions and our bylaws.

General

Shareholders’ rights in Chilean companies are governed by the company’s bylaws (estatutos), which have the same purpose as the articles or the certificate of incorporation and the bylaws of a company incorporated in the United States, and the Chilean Corporations Law. Under the Chilean Corporations Law, shareholders’ legal actions to enforce their rights as shareholders of the company must be brought in Chile in arbitration proceedings or, at the plaintiff’s option, before Chilean courts. Members of the board of directors, managers, officers, and principal executives of the company, or shareholders that individually own shares with a book value or stock value higher than UF5,000 (US$ 183,450 as of December 31, 2021) do not have the option to bring the procedure to the courts.

The CMF regulates the Chilean securities markets under the Securities Market Law (Law No. 18,045) and the Chilean Corporations Law. These two laws state the disclosure requirements, restrictions on insider trading and price manipulation, and protect minority shareholders. The Securities Market Law sets forth requirements for public offerings, stock exchanges, and brokers and outlines disclosure requirements for companies that issue publicly offered securities. The Chilean Corporations Law and the Securities Market Law, both as amended, state rules regarding takeovers, tender offers, transactions with related parties, qualified majorities, share repurchases, directors’ committees, independent directors, stock options, and derivative actions.

Public Register

We are a publicly held limited liability stock corporation incorporated under the laws of Chile. We were incorporated by public deed issued on June 19, 1981, by the Santiago Notary Public, Mr. Patricio Zaldívar M. Our existence was approved by CMF Resolution 409-S of July 17, 1981, and we were registered on July 21, 1981, in the Commercial Register (Registro de Comercio del Conservador de Bienes Raíces y Comercio de Santiago), on pages 13099 No. 7269. We are registered with the CMF under entry number 0175. We also registered with the United States Securities and Exchange Commission under the commission file number 001-12440 on October 19, 1993.

Reporting Requirements Regarding Acquisition or Sale of Shares

Under Article 12 of the Securities Market Law and General Rule No. 269 of the CMF, certain information regarding transactions in shares of a publicly held limited liability stock corporation or in contracts or securities whose price or financial results depend on, or are conditioned in whole or in a significant part on the price of such shares, must be reported to the CMF and the Chilean Stock Exchanges. Since ADSs are deemed to represent the shares of common stock underlying the ADRs, transactions in ADRs will be subject to these reporting requirements and those established in Circular 1375 of the CMF. Shareholders of publicly held limited liability stock corporations are required to report to the CMF and the Chilean Stock Exchanges:

● any direct or indirect acquisition or sale of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held limited liability stock corporation’s subscribed capital;

● any direct or indirect acquisition or sale of contracts or securities whose price or financial results depend on or are conditioned in whole or in a significant part on the price of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held limited liability stock corporation’s subscribed capital;

● any direct or indirect acquisition of shares made by a holder who, due to a purchase of shares of such publicly held stock company, results in the holder acquiring, directly or indirectly, at least 10% of a publicly held stock company’s subscribed capital;

● any direct or indirect acquisition or sale of shares in any amount, made by a director, receiver, principal executive, general manager, or manager of a publicly held limited liability stock corporation; and

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● any direct or indirect acquisition or sale of contracts or securities whose price or financial results depend on or are conditioned in whole or in a significant part on the price of shares made by a director, receiver, principal executive, general manager, or manager of a publicly held limited liability stock corporation.

The majority shareholders of a publicly held limited liability stock corporation must inform the CMF and the Chilean Stock Exchanges if such acquisitions are entered into to acquire control of the company or make a passive financial investment instead.

Under Article 54 of the Securities Market Law and General Rule No. 104 of the CMF, unless the tender offer regulation applies, any person who directly or indirectly intends to take control of a publicly held limited liability stock corporation must disclose this intent to the market at least ten business days in advance of the proposed change of control and, in any event, as soon as the negotiations for the change of control have taken place or reserved information of the publicly held limited liability stock corporation has been provided.

Corporate Objectives and Purposes

Article 4 of our bylaws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transmission, transformation, or sale of energy in any form, directly or through other companies, as well as to provide engineering consulting services related to these objectives, and to participate in the telecommunications business.

Board of Directors

Our board of directors consists of seven members elected by shareholders at an OSM for a three-year term, at the end of which they will be re-elected or replaced.

The seven directors elected at the OSM are the seven individual nominees who receive the highest majority of the votes, provided one of those individuals must be an independent director. Shareholders may vote their shares in favor of one nominee or may apportion their shares among any number of nominees.

The effect of these voting provisions is to ensure that a shareholder owning more than 12.5% of our shares can elect a board member. However, depending on the distribution of the rest of the votes at the OSM, a director may in some cases be elected with the votes of less than 12.5% of our shares. This number is derived from the reciprocal of the number of directors plus one. In our case, there are seven directors, and the reciprocal of eight is equal to 12.5%.

The compensation of the directors is established annually at the OSM. See “Item 6. Directors, Senior Management and Employees — B. Compensation.”

Agreements entered into by us with related parties can only be executed when such agreements serve our interest, and their price, terms, and conditions are consistent with prevailing market conditions at the time of their approval and comply with all the requirements and procedures indicated in Article 147 of the Chilean Corporations Law.

Certain Powers of the Board of Directors

As of the date of this Report, every agreement or contract that we enter into with our controlling shareholder, our directors or executives, or their related parties, must be previously approved by the board of directors and be included in the board meetings, as set forth by the Chilean Corporations Law.

Our bylaws do not contain provisions related to:

● the directors’ power, in the absence of an independent quorum, to vote on compensation for themselves or any members of their body;

● borrowing powers exercisable by the directors and how such borrowing powers can be changed;

● retirement or non-retirement of directors under an age limit requirement; or

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● the number of shares, if any, required for directors’ qualification.

Certain Provisions Regarding Shareholder Rights

As of the date of this Report, our capital comprises only one class of shares, all of which are common shares and have the same rights.

Our bylaws do not contain any provisions relating to:

● redemption provisions;

● sinking funds; or

● liability for capital reductions by us.

Under Chilean law, the rights of our shareholders may only be modified by an amendment to the bylaws that complies with the requirements explained below under “Item 10. Additional Information — B. Memorandum and Articles of Association. — Shareholders’ Meetings and Voting Rights.”

Capitalization

Under Chilean law, only the shareholders of a company acting at an ESM have the power to authorize a capital increase. When an investor subscribes shares, these are officially issued and registered under the subscriber’s name. The subscriber is treated as a shareholder for all purposes, except the receipt of dividends and return of capital if the shares have been subscribed but not paid. The subscriber becomes eligible to receive dividends only for the shares that the subscriber has paid for or, if the subscriber has paid for only a portion of such shares, the pro-rata portion of the dividends declared with respect to such shares unless the company’s bylaws provide otherwise. If a subscriber does not fully pay for shares for which the subscriber has subscribed on or before the date agreed upon for payment, notwithstanding the actions intended by the company to collect payment, the company is entitled to auction on the stock exchange where such shares are traded, for the account and risk of the debtor, the number of shares held by the debtor necessary for the company to pay the outstanding balances and disposal expenses. However, until such shares are sold at auction, the subscriber continues to hold all the shareholder rights, except the right to receive dividends and return of capital. The Chief Executive Officer, or the person replacing the Chief Executive Officer, will reduce in the shareholders’ register the number of shares in the name of the debtor shareholder to the number of shares that remain, deducting the shares sold by the company and settling the debt in the amount necessary to cover the result of such disposal after the related expenses.

When there are authorized and issued shares for which full payment has not been made within the period fixed by shareholders at the same ESM at which the subscription was authorized (which may not exceed three years from the date of such meeting, unless a stock option plan is approved, in which case the period to pay for the shares under such program may be up to five years), these shall be reduced in the non-subscribed amount until that date. Concerning the shares subscribed and not paid following the term mentioned above, the board must proceed to collect payment, unless the shareholders’ meeting authorizes the board not to do so (by two-thirds of the voting shares), in which case the capital shall be reduced by force of law to the amount effectively paid. Once collection actions have been exhausted, the board should propose to the shareholders’ meeting the approval by a simple majority of the write-off of the outstanding balance and the reduction of capital to the amount effectively collected.

As of December 31, 2021, the Company’s subscribed and fully paid capital totaled US$ 15,799,498,544 consisting of 107,281,698,561 shares, (including 1,809,031 treasury shares).

Preemptive Rights and Increases of Share Capital

Except for capital increases needed to carry out a merger, Chilean regulation requires Chilean publicly held limited liability stock corporations to grant shareholders preemptive rights to purchase a sufficient number of shares, or any other securities convertible into shares or that confer future rights over shares, to maintain their existing ownership

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percentage of such company whenever such company issues new shares, or any other securities convertible into shares or that confer future rights over shares.

Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders for 30 days. The options to subscribe for shares in capital increases of the company or of any other securities convertible into shares or that confer future rights over these shares should be offered, at least once, to the shareholders pro-rata to the shares held registered in their name at midnight on the fifth business day before the date of the start of the preemptive rights period. The preemptive rights offering and the beginning of the 30 days for exercising them shall be communicated through the publication of a prominent notice, at least once, in the newspaper that should be used for notifications of shareholders’ meetings. During such 30 days, and for an additional period of at least 30 days immediately following the initial 30-day period, publicly held limited liability stock corporations are not permitted to offer any unsubscribed shares to third parties under more favorable terms than those provided to their shareholders. At the end of the second 30-day period, a Chilean publicly held limited liability stock corporation is authorized to sell non-subscribed shares to third parties on any terms, provided they are sold on one of the Chilean Stock Exchanges.

Shareholders’ Meetings and Voting Rights

An OSM must be held within the first four months following the end of our fiscal year. Our last OSM was held on April 26, 2022. An ESM may be called by the board of directors when deemed appropriate. An ESM and OSM, as the case may be, must be called when requested by shareholders representing at least 10% of the issued shares with voting rights or by the CMF. To convene an OSM or ESM, notice must be given three times in a newspaper located in our corporate domicile, at least ten days in advance of the scheduled meeting. The newspaper designated by our shareholders is El Mercurio de Santiago. Notice must also be mailed to the CMF and the Chilean Stock Exchanges.

The OSM or ESM shall be held on the day stated in the notice and should remain in session until all the matters stated in the notice have been addressed. However, once constituted, upon the proposal of the Chairman or shareholders representing at least 10% of the shares with voting rights, the majority of the shareholders present may agree to suspend it and to continue it within the same day and place, with no new constitution of the meeting or qualification of powers being necessary, recorded in one set of minutes. Only those shareholders who were present or represented may attend the recommencement of the meeting with voting rights.

Under Chilean law, a quorum for a shareholders’ meeting is established by the presence, in person or by proxy, of shareholders representing at least a majority of the issued shares with voting rights of a company. If a quorum is not present at the first meeting, a reconvened meeting can occur at which the shareholders present are deemed to constitute a quorum regardless of the percentage of the shares represented. This second meeting must take place within 45 days following the scheduled date for the first meeting. Shareholders’ meetings adopt resolutions by the affirmative vote of a majority of those shares present or represented at the meeting unless a qualified majority is required.

Regardless of the quorum present, a vote of at least a two-thirds majority of the outstanding shares with voting rights is required to adopt any of the following actions:

● a transformation of the company into a form other than a publicly held limited liability stock corporation under the Chilean Corporations Law, a merger or split-up of the company;

● an amendment to the term of duration or early dissolution of the company;

● a change in the company’s domicile;

● a decrease of corporate capital;

● an approval of capital contributions in kind and non-monetary assessments;

● a modification of the authority reserved to shareholders or limitations on the board of directors;

● a reduction in the number of members of the board of directors;

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● the disposition of 50% or more of the assets of the company, whether it includes the disposition of liabilities or not, as well as the approval or the amendment of the business plan that contemplates the disposition of assets in an amount greater than such percentage;

● the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the corporation, as well as any disposition of its shares that results in the parent company losing its position as controlling shareholder;

● the form of distributing corporate benefits;

● issue of guarantees for third-party liabilities which exceed 50% of the assets, except when the third party is a subsidiary of the company, in which case approval of the board of directors is deemed sufficient;

● the purchase of the company’s own shares;

● other actions established by the bylaws or the laws;

● certain remedies for the nullification of the company’s bylaws;

● inclusion in the bylaws of the right to purchase shares from minority shareholders, when the controlling shareholders reach 95% of the company’s shares through a tender offer for all of the company’s shares, where at least 15% of the shares have been acquired from unrelated shareholders; and

● approval or ratification of acts or contracts with related parties.

Bylaw amendments for creating a new class of shares, or an amendment to or an elimination of those classes of shares that already exist, must be approved by at least two-thirds of the outstanding shares of the affected series.

Chilean law does not require a publicly held limited liability stock corporation to provide its shareholders the same level and type of information required by the U.S. securities laws regarding proxies’ solicitation. However, shareholders are entitled to examine the financial statements and corporate books of a publicly held limited liability stock corporation and its subsidiaries within 15 days before its scheduled shareholders’ meeting. Under Chilean law, publicly held limited liability stock corporations must also inform, at least ten days in advance of the scheduled meeting and in the manner to be established by the CMF, the fact that an ESM or OSM has been summoned, indicating the date, a reference to the matters to be discussed, and how complete copies of the documents that support the issues submitted for voting can be obtained, which must also be made available to the shareholders on the company’s website. In the case of an OSM, our annual report of activities, which includes audited financial statements, must also be made available to shareholders and published on our website at www.enelamericas.com.

The Chilean Corporations Law provides that, upon the request by the Directors Committee or by shareholders representing at least 10% of the issued shares with voting rights, a Chilean company’s annual report must include, in addition to the materials provided by the board of directors to shareholders, such shareholders’ comments and proposals concerning the company’s affairs. Under Article 136 of the Chilean Corporations Regulation (Reglamento de Sociedades Anónimas), the shareholder(s) holding or representing at least 10% of the shares issued with voting rights may:

● make comments and proposals relating to the progress of the corporate businesses in the corresponding year, no shareholder can make individually or jointly more than one presentation. These observations should be presented in writing to the company concisely, responsibly, and respectfully. The respective shareholder(s) should state their willingness to be included as an appendix to the annual report. The Board shall include in an appendix to the annual report of the year a faithful summary of the pertinent comments and proposals the interested parties had made, provided they are presented during the year or within 30 days after its ending; or

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● make comments and proposals on matters that the Board submits for the shareholders’ knowledge or voting. The Board shall include a faithful summary of those comments and proposals in all information it sends to shareholders, provided the shareholders’ proposal is received at the offices of the company at least ten days before the date of dispatch of the information by the company.

The shareholders should present their comments and proposals to the company, expressing their willingness to be included in the appendix to the respective annual report or in information sent to shareholders, as the case may be. The observations referred to in Article 136 may be made separately by each shareholder holding at least 10% of the shares issued with voting rights or shareholders who together hold that percentage, who should act as one.

Similarly, the Chilean Corporations Law provides that whenever the board of directors of a publicly held limited liability stock corporation convenes an OSM or ESM and solicits proxies for the meeting, or circulates information supporting its decisions or other similar material, it is obligated to include the pertinent comments and proposals that may have been made by the Directors Committee or by shareholders owning at least 10% of the shares with voting rights who request that such comments and proposals be so included.

Only shareholders registered as such with us, as of midnight on the fifth business day before a meeting date, are entitled to attend and vote their shares. A shareholder may appoint another individual, who does not need to be a shareholder, as his proxy to attend the meeting and vote on his behalf. Proxies for such representation shall be given for all the shares held by the owner. The proxy may contain specific instructions to approve, reject, or abstain concerning any of the matters submitted for voting at the meeting and included in the notice. Every shareholder entitled to attend and vote at a shareholders’ meeting shall have one vote for every share subscribed.

There are no limitations imposed by Chilean law or our bylaws on the right of nonresidents or foreigners to hold or vote shares of common stock. However, the registered holder of the shares of common stock represented by ADSs, and evidenced by outstanding ADSs, is the custodian for the Depositary (Citibank, N.A.), currently Banco Santander-Chile, or any successor custodian. Accordingly, holders of ADSs are not entitled to receive notice of shareholders’ meetings or vote the underlying shares of common stock represented by ADSs directly. The Deposit Agreement contains provisions under which the Depositary has agreed to request instructions from registered holders of ADSs regarding the exercise of the voting rights of the shares of common stock represented by the ADSs. Subject to compliance with the requirements of the Deposit Agreement and receipt of such instructions, the Depositary has agreed to endeavor, insofar as practicable and permitted under Chilean law and the provisions of the bylaws, to vote or cause to be voted (or grant a discretionary proxy to the Chairman of the Board or to a person designated by the Chairman of the Board to vote) the shares of common stock represented by the ADSs under any such instruction. The Depositary shall not itself exercise any voting discretion over any shares of common stock underlying ADSs. If the Depositary receives no voting instructions from a holder of ADSs concerning the shares of common stock represented by the ADSs, on or before the date established by the Depositary for such purpose, the shares of common stock represented by the ADSs may, in some situations, be voted in the manner directed by the Chairman of the Board, or by a person designated by the Chairman of the Board, subject to the limitations outlined in the Deposit Agreement.

Dividends and Liquidation Rights

According to the Chilean Corporations Law, unless otherwise decided by a unanimous vote of its issued shares eligible to vote, all publicly held limited liability stock corporations must distribute a cash dividend in an amount equal to at least 30% of their consolidated net income, unless and except to the extent we have carried forward losses. The law provides that the board of directors must agree to the dividend policy and inform such policy to the shareholders at the OSM.

For any dividend above 30% of net income, publicly held limited liability stock corporations may grant their shareholders an option to receive those dividends in cash, or shares issued by such publicly held limited liability stock corporation, or in shares of publicly held corporations owned by such company. Shareholders who do not expressly elect to receive a dividend other than cash are legally presumed to have decided to accept the dividend in cash.

Dividends declared but not paid within the appropriate period outlined in the Chilean Corporations Law (30 days after declaration for the minimum dividend, and the date set for payment at the time of declaration for additional dividends) are adjusted to reflect the change in the value of the UF, from the date set for payment to the date such dividends are paid. Such dividends also accrue interest at the prevailing rate for UF-denominated deposits during such

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period. The right to receive a dividend lapses if it is not claimed within five years from the date such dividend is payable. Payments not collected in such a period are transferred to the Chilean volunteer fire department.

In the event of our liquidation, the shareholders would participate in the assets available in proportion to the number of paid-in shares held by them after payment to all creditors.

Approval of Financial Statements

The board of directors is required to submit our consolidated financial statements to the shareholders annually for their approval. If the shareholders by a vote of a majority of shares present (in person or by proxy) at the shareholders’ meeting reject the financial statements, the board of directors must submit new financial statements no later than 60 days from the date of such meeting. If the shareholders reject the new financial statements, the entire board of directors is deemed removed from office, and a new board is elected at the same meeting. Directors who individually approved such financial statements are disqualified for reelection for the following period. Our shareholders have never rejected the financial statements presented by the board of directors.

Change of Control

The Capital Markets Law establishes a comprehensive regulation related to tender offers. The law defines a tender offer as the offer to purchase shares of companies that publicly offer their shares or convertible securities. This offer is made to shareholders to purchase their shares under conditions that allow the bidder to reach a certain percentage of ownership of the company within a fixed period. These provisions apply to both voluntary and hostile tender offers.

Acquisition of Shares

No provision in our bylaws discriminates against any existing or prospective holder of shares due to such shareholder owning a substantial number of shares.

Right of Dissenting Shareholders to Tender Their Shares

The Chilean Corporations Law provides that upon adopting any of the resolutions enumerated below at a shareholders’ meeting, dissenting shareholders acquire the right to withdraw from the company and compel the company to repurchase their shares, subject to the fulfillment of specific terms and conditions. To exercise such withdrawal rights, holders of ADRs must first withdraw the shares represented by their ADRs under the Deposit Agreement’s terms. In case of a bankruptcy proceeding, the withdrawal right from an adopted resolution is suspended until the existing debt has been paid.

“Dissenting” shareholders are defined as those at a shareholders’ meeting who vote against a resolution that results in the withdrawal right, or who, if absent from such meeting, state in writing their opposition to the respective resolution within the 30-days following the shareholders’ meeting. Shareholders who are present or represented at the meeting and who abstain from exercising their voting rights shall not be considered dissenting. The right to withdraw should be exercised for all the shares that the dissenting shareholder had registered in their name on the date on which the right is determined to participate in the meeting at which the resolution is adopted that motivates the withdrawal and which remains on the date on which their intention to withdraw is communicated to the company.

The price paid to a dissenting shareholder of a publicly held limited liability stock corporation whose shares are quoted and actively traded on one of the Chilean Stock Exchanges is the weighted average of the sales prices for the shares as reported on the Chilean Stock Exchanges on which the shares are quoted for the 60-trading-days between the ninetieth and the thirtieth trading day before the shareholders’ meeting giving rise to the withdrawal right. If the CMF determines that the shares are not actively traded on a stock exchange, the price paid to the dissenting shareholder shall be the book value. Book value for this purpose must be equal to the company's equity attributable to the parent company, divided by the total number of subscribed shares, whether entirely or partially paid. To make this calculation, the latest consolidated statement of financial position is used, as adjusted to reflect inflation up to the date of the shareholders’ meeting that gave rise to the withdrawal right.

Article 126 of the Chilean Corporations Regulation (Reglamento de Sociedades Anónimas) establishes that in cases where the right to withdraw arises, the company is obliged to inform the shareholders of this situation, the value per

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share that will be paid to shareholders exercising their right to withdraw and the term for exercising it. Such information should be given to shareholders at the same meeting at which the resolutions are adopted, giving rise to the right of withdrawal, before its voting. A special communication should be given to the shareholders with rights within two days following the date on which the rights to withdraw arise. In the case of publicly held companies, such information shall be communicated by a prominent notice in a newspaper with a wide national circulation and on its website, and via a written communication addressed to the shareholders with rights at the address they have registered with the company. The notice of the shareholders’ meeting to vote on a matter that could give rise to withdrawal rights should mention this circumstance.

The resolutions that result in a shareholder’s right to withdraw include, among others, the following:

● the transformation of the company into an entity that is not a publicly held limited liability stock corporation governed by the Chilean Corporations Law;

● the merger of the company with another company;

● disposition of 50% or more of the assets of the company, whether it includes the disposition of liabilities or not, as well as the approval or the amendment of the business plan that contemplates the disposition of assets in an amount greater than such percentage;

● the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the company, as well as any disposition of its shares that results in the parent company losing its position of controlling shareholder;

● issue of guarantees for third parties’ liabilities that exceed 50% of the assets (if the third party is a subsidiary of the company, the approval of the board of directors is sufficient and shall not give rise to the right to withdraw);

● the creation of preferential rights for a class of shares or an amendment to the existing ones. In this case, the right to withdraw only accrues to the dissenting shareholders of the class or classes of shares adversely affected;

● certain remedies for the nullification of the corporate bylaws; and

● such other causes as may be established by the law or by the company’s bylaws.

Investments by AFPs

The Pension Fund System Law permits AFPs to invest their funds in companies subject to Title XII of such law, and these companies are subject to greater restrictions than other companies. The determination of which stocks may be purchased by AFPs is made by the Risk Classification Committee. The Risk Classification Committee establishes investment guidelines and is empowered to approve or disapprove those companies that are eligible for AFP investments. Except for the period from March 2003 to March 2004, we were a Title XII company from 1985 until April 1, 2021, and we were approved by the Risk Classification Committee during that time. As a result of the effectiveness of the 2021 merger with EGP Américas, we are no longer a Title XII company.

Registrations and Transfers

Shares issued by us are registered with an administrative agent, which is DCV Registros S.A. This entity is also responsible for our shareholders’ registry. In the case of jointly owned shares, an attorney-in-fact must be appointed to represent the joint owners in dealing with us.

C. Material Contracts.

None.

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D. Exchange Controls.

The Central Bank of Chile is responsible for, among other things, monetary policies and exchange controls in Chile. Currently, applicable foreign exchange regulations are outlined in the Compendium of Foreign Exchange Regulations (the “Compendium”) approved by the Central Bank of Chile.

a) Chapter XIV

The following is a summary of certain provisions of Chapter XIV that apply to all existing shareholders (and ADS holders). This summary does not intend to be complete and is qualified in its entirety by reference to Chapter XIV. Chapter XIV regulates the following type of investments: credits, deposits, investments, and equity contributions. A Chapter XIV investor may repatriate at any time investment made in us upon selling our shares, and the profits derived from there, with no monetary ceiling, subject to the regulations in effect at the time, must be reported to the Central Bank of Chile.

Except for compliance with tax regulations and some reporting requirements, currently, there are no rules in Chile affecting repatriation rights, except that the remittance of foreign currency must be made through a Formal Exchange Market entity. However, the Central Bank of Chile has the authority to change such rules and impose exchange controls.

b) The Compendium and International Bond Issuances

Chilean issuers may offer bonds internationally, subject to the reporting requirements outlined in Chapter XIV of the Compendium.

E. Taxation.

Chilean Tax Considerations

The following discussion summarizes Chilean material income and withholding tax consequences to foreign holders arising from the ownership and disposition of shares and ADSs. The summary that follows does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a decision to purchase, own or dispose of shares or ADSs, if any, and does not purport to deal with the tax consequences applicable to all categories of investors, some of which may be subject to special rules. Holders of shares and ADSs are advised to consult their own tax advisors concerning the Chilean and other tax consequences of the ownership of shares or ADSs.

The summary that follows is based on Chilean law, in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions in statutes such as tax rates applicable to foreign investors, the computation of taxable income for Chilean purposes, and how Chilean taxes are imposed and collected may be amended only by another law. The Chilean tax authorities also enact rulings and regulations of either general or specific application and interpret the Chilean Income Tax Law provisions. Chilean tax may not be assessed retroactively against taxpayers who act in good faith, relying on such rulings, regulations, and interpretations, but Chilean tax authorities may change their rulings, regulations, and interpretations in the future. The discussion that follows is also based, in part, on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreements will be performed under its terms. As of this date, there is currently no applicable income tax treaty in effect between the United States and Chile. However, in 2010 the United States and Chile signed an income tax treaty that will enter into force once the treaty is ratified by both countries, which has not happened as of the date of this Report. There can be no assurance that either country will ratify the treaty. The following summary assumes that there is no applicable income tax treaty in effect between the United States and Chile.

As used in this Report, the term “foreign holder” means either:

● In the case of an individual holder, a person who is not a resident of Chile. For purposes of Chilean taxation, (a)  any person who remains in Chile, uninterrupted or not, for a period or periods that in total exceed 183 days, within any period of twelve months, or (b) an individual is domiciled in Chile if he resides in Chile and has the intention of remaining in Chile (such intention to be evidenced by circumstances such as the acceptance of employment in Chile or the relocation of the individual’s family to Chile), or

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● in the case of a legal entity holder, an entity that is not organized under Chile’s laws, unless the shares or ADSs are assigned to a branch, agent, representative, or permanent establishment of such entity in Chile.

Taxation of Shares and ADSs

Taxation of Cash Dividends and Property Distributions

Cash dividends paid concerning the shares or ADSs held by a foreign holder will be subject to Chilean withholding tax, which is withheld and paid by the company. The amount of the Chilean withholding tax is determined by applying a 35% rate to a “grossed-up” distribution amount (such amount equal to the sum of the actual distribution amount and the correlative Chilean corporate income tax (“CIT”), paid by the issuer), and then subtracting as a credit 65% of such Chilean CIT paid by the issuer in case the residence country of the holder of shares or ADSs does not have a tax treaty with Chile. If there is a tax treaty between both countries (in force or signed before January 1, 2021), the Foreign Holder can apply 100% of the CIT as a credit. For 2021, the Chilean CIT applicable to us is a rate of 27%, and depending on the circumstances mentioned above, the Foreign Holder may apply 100% or 65% of the CIT as a credit.

In February 2020, tax reform contemplating only a partially integrated tax regime was enacted. Under the current Chilean Income Tax Law, publicly held limited liability stock corporations, such as our company, are subject to this regime, consisting of a cash basis shareholder taxation.

Under the cash basis regime (or partially integrated regime), a company pays CIT on its annual income tax result. Foreign and local individual shareholders will only pay in Chile the relevant tax on effective profit distributions. They will be allowed to use the CIT paid by the distributing company as credit, with certain limitations. Only 65% of the CIT is creditable against the 35% shareholder-level tax. However, in those cases where tax treaties between Chile and the jurisdiction of the shareholder’s residence were signed before January 1, 2021(even if not yet in effect), the CIT is entirely creditable against the 35% withholding tax. This is the case with the tax treaty signed between Chile and the United States, which was signed before this date, but which is not in effect as of the date of this Report. In the case of treaties signed before January 1, 2021, but not ratified as of December 31, 2026, the shareholder may apply 100% of the CIT as a credit if a dividend distribution is made before December 31, 2026, on a transitional basis. Under the Chilean Tax Law in force at the date of this Report, the transitional treatment of applying the full 100% of the CIT as a credit against withholding tax of the U.S. Holders in case of dividend distributions will terminate on December 31, 2026, if the tax treaty between the United States and Chile is not ratified by that date. In that particular case, effective as of January 1, 2027, only 65% of the CIT will be creditable against the 35% U.S. Holders’ tax. On the other hand, if a tax treaty with a foreign jurisdiction is ratified by December 31, 2026, shareholders from that particular jurisdiction can continue to apply 100% of the CIT as a credit beyond such date.

The example below illustrates the effective Chilean withholding tax burden on a cash dividend received by a Foreign Holder, assuming a Chilean withholding tax base rate of 35%, an effective Chilean CIT rate of 27% (the CIT rate for 2021 under cash basis regime) and a distribution of 50% of the net income of the company distributable after payment of the Chilean CIT:

Line	Concept and Calculation Assumptions	Amount Tax Treaty Resident	Amount Non-tax Treaty Resident
1	Company taxable income (based on Line 1 = 100)	100.0	100.0
2	Chilean corporate income tax: 27% x Line 1	27	27
3	Net distributable income: Line 1—Line 2	73	73
4	Dividend distributed (50% of net distributable income): 50% of Line 3	36.5	36.5
5	Withholding tax: (35% of (the sum of Line 4 and 50% of Line 2))	17.5	17.5
6	Credit for 50% of Chilean corporate income tax: 50% of Line 2	13.5	13.5
7	CIT partial restitution (Line 6 x 35)%(1)	—	4.7
8	Net withholding tax: Line 5 - Line 6 + Line 7	4	8.7
9	Net dividend received: Line 4 - Line 8	32.5	27.8
10	Effective dividend withholding rate: Line 8 / Line 4	11.0	23.9

(1) Only applicable to non-tax treaty jurisdiction residents. From a practical standpoint, the foregoing means that the CIT is only partially creditable (65%) against the withholding tax (i.e., CIT of 8.7%).

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However, for purposes of the foregoing, the tax authority has not clarified whether the taxpayer residence will be the ADS holder’s address or the depositary’s address.

Taxation on Sale or Exchange of ADSs Outside of Chile

Gains obtained by a foreign holder from the sale or exchange of ADSs outside Chile are not subject to Chilean taxation.

Taxation on Sale or Exchange of Shares

The Chilean Income Tax Law includes a tax exemption on capital gains from the sale of shares of listed companies traded in stock markets. Although there are certain restrictions, in general terms, the law provides that in order to qualify for the capital gain exemption: (i) the shares must be of a publicly held limited liability stock corporation with a “sufficient stock market liquidity” status in the Chilean Stock Exchanges; (ii) the sale must be conducted in a Chilean Stock Exchange authorized by the CMF, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law or as the consequence of a contribution to a fund as regulated in Section 109 of the Chilean Income Tax Law; (iii) the shares which are being sold must have been acquired on a Chilean Stock Exchange, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law, or in an initial public offering (due to the creation of a company or to a capital increase), or due to the exchange of convertible publicly offered securities, or due to the redemption of a fund’s quota as regulated in Section 109 of the Chilean Income Tax Law; and (iv) the shares must have been acquired after April 19, 2001. For purposes of considering the ADSs as convertible publicly offered securities, they should be registered in the Chilean foreign securities registry (unless expressly excluded from such registry by the CMF).

Shares are considered to have a “high presence” in the Chilean Stock Exchanges when (i) they have been traded for a certain number of days at or beyond a volume threshold specified under Chilean law and regulations or (ii) in case the issuer has retained a market maker, under Chilean law and regulations. As of the date of this Report, our shares are considered to have a high presence in the Chilean Stock Exchanges, and we have not retained any market maker. Should our shares cease to have a “high presence” in the Chilean Stock Exchanges, a transfer of our shares may be subject to capital gains taxes from which holders of “high presence” securities are exempted, and which will apply at varying levels depending on the time of the transfer concerning the date of loss of sufficient trading volume to qualify as a “high presence” security. If our shares regain a “high presence,” the tax exemptions will again be available to holders thereof.

If the shares do not qualify for the exemption, capital gains on their sale or exchange of shares (as distinguished from sales or exchanges of ADSs representing such shares of common stock) could be subject to the general tax regime, with a 27% Chilean CIT, the rate applicable during 2021, and a 35% Chilean withholding tax, the former being creditable against the latter.

The date of acquisition of the ADSs is the date of purchase of the shares for which the ADSs are exchanged.

Taxation of Share Rights and ADS Rights

For Chilean tax purposes and to the extent we issue any share rights or ADS rights, the receipt of share rights or ADS rights by a Foreign Holder of shares or ADSs under a rights offering is a nontaxable event. Also, there are no Chilean income tax consequences to Foreign Holders upon the exercise or the expiration of the share rights or the ADS rights.

Any gain on the sale, exchange, or transfer of any ADS rights by a Foreign Holder is not subject to taxes in Chile.

Any gain on the sale, exchange, or transfer of the share rights by a Foreign Holder is subject to a 35% Chilean withholding tax.

Other Chilean Taxes

There is no gift, inheritance, or succession tax applicable to foreign holders’ ownership, transfer, or disposition of ADSs. However, such taxes will generally apply to the transfer at death or by a gift of the shares by a foreign holder. There is no Chilean stamp, issue, registration, or similar taxes or duties payable by holders of shares or ADSs.

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Material U.S. Federal Income Tax Considerations

This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary, and proposed Treasury regulations, all as of the date of this Report. These authorities are subject to change, possibly with retroactive effect. This discussion assumes that the depositary’s activities are clearly and appropriately defined to ensure that the tax treatment of ADSs will be identical to the tax treatment of the underlying shares.

The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning, and disposing of shares or ADSs. However, it does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a particular person’s decision to hold such securities and is based on the assumption stated above under “Chilean Tax Considerations” that there is no applicable income tax treaty in effect between the United States and Chile. The discussion applies only if the beneficial owner holds shares or ADSs as capital assets for U.S. federal income tax purposes. It does not describe all of the tax consequences that may be relevant in light of the beneficial owner’s particular circumstances. For instance, it does not describe all the tax consequences that may be relevant to:

● certain financial institutions;

● insurance companies;

● dealers and traders in securities who use a mark-to-market method of tax accounting;

● persons holding shares or ADSs as part of a “straddle” integrated transaction or similar transaction;

● persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

● partnerships or other entities classified as partnerships for U.S. federal income tax purposes or partners in such partnerships;

● persons liable for the alternative minimum tax;

● tax-exempt organizations;

● persons holding shares or ADSs that own or are deemed to own ten percent or more of our stock; or

● persons holding shares or ADSs connected with a trade or business conducted outside of the United States.

Persons or entities described above, including partnerships holding shares or ADSs and partners in such partnerships, should consult their own tax advisors about the particular U.S. federal income tax consequences of holding and disposing of shares or ADSs.

You will be a “U.S. Holder” for purposes of this discussion if you become a beneficial owner of our shares or ADSs and if you are, for U.S. federal income tax purposes:

● a citizen or an individual resident of the United States; or

● a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or any political subdivision thereof; or

● an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or

● a trust (i) that validly elects to be treated as a U.S. person for U.S. federal income tax purposes or (ii) if (A) a court within the United States can exercise primary supervision over the administration of the trust and (B) one or more U.S. persons have the authority to control all substantial decisions of the trust.

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For U.S. federal income tax purposes, it is generally expected that a U.S. Holder of ADSs will be treated as the beneficial owner of the underlying shares represented by the ADSs. The remainder of this discussion assumes that a U.S. Holder of our ADSs will be treated in this manner for U.S. federal income tax purposes. Accordingly, deposits or withdrawals of shares for ADSs will generally not be subject to U.S. federal income tax.

The U.S. Treasury has expressed concerns that parties to whom ADSs are released before shares are delivered to the depositary (pre-release) or intermediaries in the chain of ownership between beneficial owners and the issuer of the security underlying the ADSs may be taking actions that are inconsistent with the claiming of foreign tax credits for beneficial owners of depositary shares. Such actions would also be inconsistent with claiming the reduced tax rate, described below, applicable to dividends received by certain non-corporate beneficial owners. Accordingly, the analysis of the creditability of Chilean taxes and the availability of the reduced tax rate for dividends received by certain non-corporate holders, each described below, could be affected by actions taken by such parties or intermediaries.

This discussion assumes that we will not be a passive foreign investment company, as described below. The discussion below does not address the effect of any U.S. state, local, estate, or gift tax law or non-U.S. tax law or tax considerations that arise from rules of general application to all taxpayers on a U.S. Holder of the shares or ADSs or of any future administrative guidance interpreting provisions thereof. U.S. Holders should consult their own tax advisors concerning their particular tax consequences of owning or disposing of shares or ADSs, including the applicability and effect of state, local, non-U.S., and other tax laws and the possibility of changes in tax laws, including the effects of any future administrative guidance interpreting provisions thereof.

Taxation of Distributions

The following discussion of cash dividends and other distributions is subject to the discussion below under “Passive Foreign Investment Company Rules.” Distributions received by a U.S. Holder on shares or ADSs, including the amount of any Chilean taxes withheld, other than certain pro-rata distributions of shares to all shareholders, will constitute foreign-source income to the extent paid out of our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported to U.S. Holders as dividends. The amount of dividend income paid in Chilean pesos that a U.S. Holder will be required to include in income will equal the U.S. dollar value of the distributed Chilean peso, calculated by reference to the exchange rate in effect on the date the payment is received, regardless of whether the payment is converted into U.S. dollars on the date of receipt. If the dividend is converted into U.S. dollars on the date of receipt, a U.S. Holder will generally not be required to recognize foreign currency gain or loss regarding the dividend income. A U.S. Holder may have foreign currency gain or loss if the dividend is converted into U.S. dollars after the date of its receipt, which would be ordinary income or loss and would be treated as income from U.S. sources for foreign tax credit purposes. Dividends will be included in a U.S. Holder’s income on the date of the U.S. Holder’s, or in the case of ADSs, the depositary’s, receipt of the dividend.

Subject to certain exceptions for short-term and hedged positions, the discussion above regarding concerns expressed by the U.S. Treasury and the discussion below regarding rules intended to be promulgated by the U.S. Treasury, the U.S. dollar amount of dividends received by a non-corporate U.S. Holder in respect of shares or ADSs generally will be subject to taxation at preferential rates if the dividends are “qualified dividends.” Dividends paid on the ADSs generally will be treated as qualified dividends if (i) the ADSs are readily tradable on an established securities market in the United States (ii) we were not, in the year before the year in which the dividend was paid, and is not, in the year in which the dividend is paid, a passive foreign investment company (“PFIC”) and (iii) the holder thereof has satisfied certain holding period requirements. The ADSs are listed on the New York Stock Exchange and generally will qualify as readily tradable on an established securities market in the United States so long as they are so listed. We do not expect that we will be treated as having been a PFIC for U.S. federal income tax purposes concerning our 2021 taxable year. In addition, based on our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for our 2022 taxable year. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any current, prior, or future taxable year.

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Based on existing guidance, it is not entirely clear whether dividends received concerning shares will be treated as qualified dividends because they are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules under which holders of ADSs and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to establish that dividends are treated as qualified dividends. Because such procedures have not yet been issued, it is not clear whether we will comply with them. U.S. Holders should consult their own tax advisors to determine whether the favorable rate will apply to dividends they receive and whether it is subject to any special rules limiting its ability to be taxed at this favorable rate.

The amount of a dividend generally will be treated as foreign-source dividend income to a U.S. Holder for foreign tax credit purposes. As discussed in more detail below under “Foreign Tax Credits,” it is not free from doubt whether Chilean withholding taxes imposed on distributions on shares or ADSs will be treated as income taxes eligible for a foreign tax credit for U.S. federal income tax purposes. If a Chilean withholding tax is treated as an eligible foreign income tax, subject to generally applicable limitations, you may claim a credit against your U.S. federal income tax liability for the eligible Chilean taxes withheld from distributions on shares or ADSs. If the dividends are taxed as qualified dividend income (as discussed above), special rules will apply in determining the amount of the dividend taken into account to calculate the foreign tax credit limitation. The rules relating to foreign tax credits are complex. U.S. Holders are urged to consult their own tax advisors regarding the treatment of Chilean withholding taxes imposed on distributions on shares or ADSs.

Sale or Other Disposition of Shares or ADSs

If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or ADSs will be a capital gain or loss and will be a long-term capital gain or loss if the beneficial holder has held the shares or ADSs for more than one year. The amount of a beneficial owner’s gain or loss will equal the difference between the beneficial owner’s tax basis in the shares or ADSs disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. Such gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. In addition, certain limitations exist on the deductibility of capital losses by both corporate and individual taxpayers.

In certain circumstances, Chilean taxes may be imposed upon the sale of shares (but not ADSs). See “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADSs.” If a Chilean tax is imposed on the sale or disposition of shares, a beneficial owner that is a U.S. Holder may be eligible to claim a credit against its U.S. federal income tax liability for the eligible Chilean taxes withheld under a sale or disposition of shares or ADSs as discussed in “Foreign Tax Credits” below.

Foreign Tax Credits

Subject to applicable limitations that may vary depending upon a U.S. Holder’s circumstances and subject to the discussion above regarding concerns expressed by the U.S. Treasury, you may be eligible to claim a credit against your U.S. tax liability for Chilean income taxes (or taxes imposed in lieu of an income tax) imposed in connection with distributions on and proceeds from the sale or other disposition of our shares or ADSs. Chilean dividend withholding taxes generally are expected to be income taxes eligible for the foreign tax credit. The Chilean capital gains tax is likely to be treated as an income tax (or a tax paid in lieu of an income tax) and thus eligible for the foreign tax credit; however, you generally may claim a foreign tax credit only after taking into account any available opportunity to reduce the Chilean capital gains tax, such as the reduction for the credit for Chilean corporate income tax that is taken into account when calculating Chilean withholding tax. If a Chilean tax is imposed on the sale or disposition of our shares or ADSs, and a U.S. Holder does not receive significant foreign source income from other sources, such U.S. Holder may not be able to credit such Chilean tax against its U.S. federal income tax liability. If a Chilean tax is not treated as an income tax (or a tax paid in lieu of an income tax) for U.S. federal income tax purposes, a U.S. Holder would be unable to claim a foreign tax credit for any such Chilean tax withheld; however, a U.S. Holder may be able to deduct such tax in computing its U.S. federal income tax liability, subject to applicable limitations. In addition, instead of claiming a credit, a U.S. Holder may, at the U.S. Holder’s election, deduct such Chilean taxes in computing the U.S. Holder’s taxable income, subject to generally applicable limitations under U.S. law. An election to deduct foreign taxes instead of claiming foreign tax credits applies to all taxes paid or accrued in the taxable year to foreign countries and possessions of the U.S. The calculation of foreign tax credits and, in the case of a U.S. Holder that elects to deduct foreign income taxes, the availability of deductions, involves the application of complex rules that depend on such U.S. Holder’s particular circumstances. U.S. Holders are urged to consult their own tax advisors regarding the availability of foreign tax credits in their particular circumstances.

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Passive Foreign Investment Company Rules

We were not a “passive foreign investment company” or PFIC for U.S. federal income tax purposes for our 2021 taxable year. We do not anticipate being a PFIC for our 2022 taxable year. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any current, prior, or future taxable year. If we were to become a PFIC for any taxable year during which a beneficial owner held shares or ADSs, certain adverse consequences could apply to the U.S. Holder, including the imposition of higher amounts of tax than would otherwise apply and additional filing requirements. In addition, if we were treated as a PFIC in a taxable year in which we pay a dividend or in the prior taxable year, the favorable dividend rates discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply (see “— Taxation of Distributions” above). U.S. Holders should consult their own tax advisors regarding the consequences to them if we were to become a PFIC and the availability and advisability of making any election that might mitigate the adverse consequences of PFIC status.

Required Disclosure with Respect to Foreign Financial Assets

Certain U.S. Holders are required to report information relating to an interest in our shares or ADSs, subject to certain exceptions (including an exception for our shares or ADSs held in accounts maintained by certain financial institutions), by attaching a completed IRS Form 8938, Statement of Specified Foreign Financial Assets, with their tax return for each year in which they hold an interest in our shares or ADSs. U.S. Holders are urged to consult their own U.S. tax advisors regarding information reporting requirements relating to their ownership of our shares or ADSs.

Information Reporting and Backup Withholding

Payments of dividends and sales proceeds that are made within the United States or through certain U.S.- related financial intermediaries generally are subject to information reporting and backup withholding unless: (i) the U.S. Holder is an exempt recipient or (ii) in the case of backup withholding, the beneficial owner provides a correct taxpayer identification number and certifies that the U.S. Holder is not subject to backup withholding.

The amount of any backup withholding from a payment to a beneficial owner will be allowed as a credit against the beneficial owner’s U.S. federal income tax liability and may entitle the U.S. Holder to a refund, provided that the required information is furnished in a timely fashion to the U.S. Internal Revenue Service.

Medicare Contribution Tax

A U.S. Holder that is an individual or estate, or a trust that does not meet certain requirements for an exemption, is subject to a tax of 3.8% on its “net investment income.” Among other items, net investment income generally includes gross income from dividends and net gain attributable to the disposition of certain property, like the shares or ADSs, less certain deductions. A U.S. Holder should consult the holder’s own tax advisor regarding the applicability of the “net investment income” tax regarding such beneficial owner’s particular circumstances.

U.S. Holders should consult their own tax advisors with respect to the particular consequences to them of owning or disposing of shares or ADSs.

F. Dividends and Paying Agents.

Not applicable.

G. Statement by Experts.

Not applicable.

H. Documents on Display.

We are subject to the information requirements of the Exchange Act, except that as a foreign private issuer, we are not subject to the SEC proxy rules (other than general anti-fraud rules) or the short-swing profit disclosure rules of the Exchange Act. Under these statutory requirements, we file or furnish reports and other information with the SEC.

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Reports, information statements, and other information we file with or furnish to the SEC are available electronically on the SEC’s website, which can be accessed at http://www.sec.gov and on our website www.enelamericas.com. Copies of such material may also be inspected at the offices of the New York Stock Exchange, at 11 Wall Street, New York, New York 10005, on which our ADSs are listed.

I.Subsidiary Information.

For information on our principal subsidiaries, see “Item 4. Information on the Company — C. Organizational Structure — Principal Subsidiaries and Affiliates.”

Item 11.Quantitative and Qualitative Disclosures about Market Risk

We are exposed to risks arising from volatility in commodity prices, interest rates, and foreign exchange rates that affect the generation, transmission, and distribution businesses in the countries where we operate. 

Commodity Price Risk

In our electricity generation and transmission business segments, we are exposed to market risks arising from the price volatility of electricity, natural gas, diesel oil, and coal. We seek to ensure our fuel supply by securing long-term contracts with our suppliers for periods expected to match our generation assets’ lifetime. These contracts generally have provisions that allow us to purchase natural gas with a pricing formula that combines Henry Hub natural gas and Brent diesel oil at market prices.

We have designed a commercial policy that aligns sale commitment levels with the generation capacity during a dry year by including risk mitigation clauses with unregulated customers in some contracts to reduce risk under extreme drought conditions. In the case of regulated customers subject to long-term tender processes, indexed polynomials are determined to minimize commodity exposure.

Considering the operating conditions faced in the electricity generation market, drought, and the volatility of commodity prices in international markets, we continually evaluate if it is in our best interests to engage in hedging to mitigate the impact of price changes on profits.

As of December 31, 2021, and 2020, no energy futures purchase agreements had been settled to cover the contracting portfolio.

We continually analyze strategies to hedge commodity price risk, including transferring commodity price variations to customers’ contract prices, adjusting commodity indexed price formulas for new PPAs according to our exposure, or analyzing ways to mitigate risk through hydrological insurance in dry years. We may consider using price-sensitive instruments in the future.

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Interest Rate and Foreign Currency Risk

As of December 31, 2021, the carrying value according to maturity and the corresponding fair value of our interest-bearing debt are detailed below. The amounts do not include derivatives. The rates in the table below are the result of the weighted average of the effective interest rates of each obligation, including expenses associated with financing and withholding taxes on interest payments related to financing obtained outside the country of domicile of each company.

	Expected maturity date
For the year ended December 31,	2022	2023	2024	2025	2026	Thereafter	Total	Fair Value(2)
	(in millions of US$)(1)
Fixed Rate
Ch$/UF	—	—	—	—	—	—	—	—
Weighted average interest rate	—	—	—	—	—	—	—	—
US$	174	158	354	182	664	50	1,582	1,473
Weighted average interest rate	1.6%	1.4%	1.9%	2.0%	4.0%	2.9%	2.8%	n.a.
Other currencies(3)	681	337	633	108	100	299	2,157	2,099
Weighted average interest rate	3.8%	3.5%	3.4%	5.9%	5.6%	6.1%	4.1%	n.a.
Total fixed rate	855	495	987	290	764	349	3,739	3,572
Weighted average interest rate	3.4%	2.8%	2.9%	3.5%	4.2%	5.7%	3.6%	n.a.
Variable Rate
Ch$/UF	3	—	—	—	—	—	3	3
Weighted average interest rate	6.2%	—	—	—	—	—	6.2%	n.a.
US$	62	56	57	55	54	250	532	457
Weighted average interest rate	2.6%	2.6%	2.6%	2.6%	2.6%	1.8%	2.2%	n.a.
Other currencies(3)	491	692	456	394	397	923	3,352	3,181
Weighted average interest rate	5.7%	7.2%	9.1%	8.2%	8.9%	9.1%	8.1%	n.a.
Total variable rate	556	748	513	449	451	1,173	3,887	3,641
Weighted average interest rate	5.4%	6.9%	8.3%	7.5%	8.2%	7.5%	7.3%	n.a.
Total	1,411	1,243	1,500	739	1,215	1,522	7,626	7,213

(1) Calculated based on the foreign exchange rate of the applicable foreign currency to the U.S. dollar as of December 31, 2021.

(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(3) “Other currencies” include the Argentina peso, Brazilian real, Colombian peso, Costa Rican colon, Euro, Guatemalan quetzal, and Peruvian sol.

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As of December 31, 2020, the carrying values according to maturity and the corresponding fair value of our interest-bearing debt are detailed below, which do not include derivatives. The rates in the table below are the result of the weighted average of the effective interest rates of each obligation, including expenses associated with financing and withholding taxes on interest payments related to financing obtained outside the country of domicile of each company.

	Expected maturity date
For the year ended December 31,	2021	2022	2023	2024	2025	Thereafter	Total	Fair Value(2)
	(in millions of US$)(1)
Fixed Rate
Ch$/UF	—	—	—	—	—	—	—	—
Weighted average interest rate	—	—	—	—	—	—	—	n.a.
US$	408	98	7	9	7	647	1,175	1,236
Weighted average interest rate	2.5%	2.0%	0.5%	1.6%	0.3%	4.0%	3.3%	n.a.
Other currencies(3)	558	345	176	180	103	181	1,543	1,662
Weighted average interest rate	5.7%	6.9%	5.4%	5.5%	6.3%	6.3%	6.0%	n.a.
Total fixed rate	966	443	183	188	110	828	2,718	2,898
Weighted average interest rate	4.4%	5.8%	5.2%	5.3%	5.9%	4.5%	4.8%	n.a.
Variable Rate
Ch$/UF	7	4	—	—	—	—	11	12
Weighted average interest rate	6.4%	6.4%	—	—	—	—	6.4%	n.a.
US$	604	—	—	1	—	—	605	605
Weighted average interest rate	1.5%	—	—	2.3%	—	—	1.5%	n.a.
Other currencies(3)	382	375	547	517	312	594	2,726	2,747
Weighted average interest rate	4.4%	4.6%	4.6%	5.4%	6.4%	6.5%	5.3%	n.a.
Total variable rate	992	378	547	518	312	594	3,341	3,363
Weighted average interest rate	2.6%	4.6%	4.6%	5.4%	6.4%	6.5%	4.6%	n.a.
Total	1,958	822	730	706	422	1,421	6,059	6,262

(1) Calculated based on the foreign exchange rate of the applicable foreign currency to the U.S. dollar as of December 31, 2020.

(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(3) “Other currencies” include the Argentine peso, Brazilian real, Colombian peso, and Peruvian sol.

Interest Rate Risk

Our policy aims to minimize the average cost of debt and reduce the volatility of our financial results. Depending on our estimates and debt structure, we sometimes manage interest rate risk using interest rate derivatives.

As of December 31, 2021, and 2020, 31% and 38%, respectively, of our total outstanding debt was denominated in fixed terms, and 69% and 62%, respectively, was subject to variable interest rates. Because of the exposure to variable interest rate risks, we engage in derivative hedging instruments.

As of December 31, 2021, the carrying value for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest-bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2022	2023	2024	2025	2026	Thereafter	Total	Fair Value(1)
	(in millions of US$)
Variable to fixed rates	—	—	—	—	100	88	188	(3)
Variable to variable rates(2)	—	—	52	—	143	129	324	8
Total	—	—	52	—	243	217	512	5

(1) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(2) We carry out a derivative hedging instrument in Brazil from IPCA to the CDI index.

As of December 31, 2020, the carrying values for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest-bearing debt were as follows:

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	Expected Maturity Date
For the year ended December 31,	2021	2022	2023	2024	2025	Thereafter	Total	Fair Value(1)
	(in millions of US$)
Variable to fixed rates	—	—	—	—	—	—	—	—
Variable to variable rates(2)	—	—	—	—	—	154	154	19
Total	—	—	—	—	—	154	154	19

(1) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(2) We carry out a derivative hedging instrument in Brazil from IPCA to the CDI index.

Foreign Currency Risk

Our policy seeks to maintain a balance between the currencies in which cash flows are indexed and each company’s principal debt. Most of our subsidiaries have access to funding in the same currency as their revenues, thereby reducing the impact of exchange rate volatility. In some cases, we cannot fully benefit from this. Therefore, we try to manage the exposure with financial derivatives such as cross-currency swaps or currency forwards. However, this may not always be available under reasonable terms due to market conditions. For instance, in Costanera, whose revenues are in Argentine pesos, and a substantial part of its debt is denominated in U.S. dollars, we cannot hedge such debt under reasonable market conditions. Costanera’s debt denominated in U.S. dollars amounted to US$ 70 million as of December 31, 2021.

As of December 31, 2021, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest-bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2022	2023	2024	2025	2026	Thereafter	Total	Fair Value(1)
	(in millions of US$)
US$ to R$	280	284	647	166	54	231	1,662	128
US$ to other currencies	—	—	—	—	—	—	—	—
Other currencies to US$(2)	—	—	—	—	—	—	—	—
Total	280	284	647	166	54	231	1,662	128

(1) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(2) “Other currencies” may include the Argentina peso, Colombian peso, Costa Rican colon, Euro, Guatemalan quetzal, and Peruvian sol.

As of December 31, 2020, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest-bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2021	2022	2023	2024	2025	Thereafter	Total	Fair Value(1)
	(in millions of US$)
US$ to R$	400	77	77	—	—	—	554	95
US$ to other currencies	—	—	—	—	—	—	—	—
Other currencies to US$(2)	—	—	—	—	—	—	—	—
Total	400	77	77	—	—	—	554	95

(1) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(2) “Other currencies” may include the Argentine peso, Colombian peso, Euro, and Peruvian sol.

Please refer to Note 22 of the Notes to our consolidated financial statements for further detail.

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(d) Safe Harbor

The information in this “Item 11. Quantitative and Qualitative Disclosures About Market Risk” contains information that may constitute forward-looking statements. See “Forward-Looking Statements” in the Introduction of this Report for safe harbor provisions.

Item 12.  Description of Securities Other Than Equity Securities

A.  Debt Securities.

Not applicable.

B.  Warrants and Rights.

Not applicable.

C.  Other Securities.

Not applicable.

D.  American Depositary Shares.

Depositary Fees and Charges

Our ADS program’s Depositary is Citibank, N.A. The Depositary collects fees for delivery and surrender of ADS directly from investors depositing shares or surrendering ADSs for withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. For non-cash distributions, the Depositary will invoice the applicable ADS record date holders. The Depositary may generally refuse to provide the requested services until its fees for those services are paid. Under the terms of the Deposit Agreement, an ADS holder may have to pay the following service fees to the Depositary:

Service Fees	Fees
(1) Issuance of ADSs upon deposit of shares (excluding issuances as a result of distributions described in paragraph (4) below)	Up to US$ 5 per 100 ADSs (or fraction thereof) issued
(2) Delivery of deposited securities against surrender of ADSs	Up to US$ 5 per 100 ADSs (or fraction thereof) surrendered
(3) Distribution of cash dividends or other cash distributions (i.e., sale of rights and other entitlements)	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(4) Distribution of ADSs under (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADSs	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(5) Distribution of securities other than ADSs or rights to purchase additional ADSs (i.e., a spin-off of shares)	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(6) Depositary services	Up to US$ 5 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary

Depositary Payments for Fiscal Year 2021

The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2021, the Depositary reimbursed expenses related primarily to investor relations’ activities for a total amount of US$ 0.4 million (after the deduction of applicable U.S. taxes).

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PART II

Item 13.Defaults, Dividend Arrearages and Delinquencies

None.

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds

None.

Item 15.Controls and Procedures

(a) Disclosure Controls and Procedures

We carried out an evaluation under the supervision and with the participation of our senior management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2021.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error, and the circumvention or overriding of the controls and procedures. Accordingly, our disclosure controls and procedures are designed to provide reasonable assurance of achieving their control objectives.

Based upon our evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is gathered and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives, and our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

As required by Section 404 of the Sarbanes-Oxley Act of 2002, our management is responsible for establishing and maintaining “adequate internal control over financial reporting” (as defined in Rule13a-15(f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS, as issued by the IASB.

During the first half of 2021, the Company completed the acquisition of EGP Américas SpA, a wholly owned subsidiary of Enel S.p.A. Prior to the merger, EGP Américas SpA, a newly-formed company, held the renewable energy generation businesses in Central and South America (outside of Chile). EGP Américas companies represents 19.3% of our total consolidated assets and 3.7% of our total consolidated revenues as reported in our consolidated financial statements as of and for the year ended December 31, 2021.

Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.

Management assessed the effectiveness of its internal control over financial reporting for the year ended December 31, 2021. The assessment was based on criteria established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 framework”). Management has

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excluded from the scope of its assessment of internal control over financial reporting the operations and related assets of EGP Américas companies, in accordance with applicable guidance provided by the SEC. Based on the assessment, our management has concluded that as of December 31, 2021, our internal control over financial reporting was effective. 

(c)   Attestation Report of the Registered Public Accounting Firm

Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2021. Their attestation report appears on page F-4.

(d) Changes in Internal Control Over Financial Reporting

Remediation of Previously Disclosed Material Weakness

During 2021, we implemented measures to improve our internal controls over financial reporting and remediate the material weakness previously identified as of December 31, 2020, with respect to general information technology controls (GITCs), specifically program change controls and access controls, that support the consistent operation of the Company’s information technology (IT) operating system, database and IT application layers of technology over the electricity distribution business revenue process. These deficiencies also affected the effectiveness of business process automated controls, manual controls with an automated component, and the database of the reports that were used to execute certain automated and manual controls.

In an effort to remediate the material weakness and enhance our internal controls, management implemented the following actions to revise and enhance our GITCs to ensure, for the affected IT application, full enforcement of procedures related to access control and the tracking of changes, including through (i) integrating the affected IT application with additional tools to improve access review and the tracking of changes, (ii) additional training to increase awareness of control operators, and (iii) control design reviews related to the tracking of changes.

After completing our testing of the design and operating effectiveness of these new procedures, our management concluded that, as of December 31, 2021, we have remediated the previously identified material weakness as of December 31, 2020.

Additionally, during the first half of 2021, the Company completed the acquisition of EGP Américas SpA, a wholly owned subsidiary of Enel S.p.A. Prior to the merger, EGP Américas SpA, a newly-formed company, held the renewable energy generation businesses in Central and South America (outside of Chile). EGP Américas companies represents 19.3% of our total consolidated assets and 3.7% of our total consolidated revenues as reported in our consolidated financial statements as of and for the year ended December 31, 2021.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer and other members of our executive management have implemented the aforementioned remedial measures during the year ended December 31, 2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 16.   Reserved

Item 16A.   Audit Committee Financial Expert

As of December 31, 2021, the Directors Committee performed the Audit Committee’s functions, and the committee’s financial expert is Mr. Hernán Somerville, as determined by the board of directors. Mr. Somerville is an independent member of the Directors Committee under the requirements of both Chilean law and NYSE corporate governance rules.

Item 16B. Code of Ethics

Our standards of ethical conduct are governed using the following corporate rulings or policies: (i) the Manual for the Management of Information of Interest to the Market (the “Manual”); (ii) the Human Rights and Politically Exposed Person Policy (Política de Derechos Humanos); (iii) the Code of Ethics; (iv) the Zero Tolerance Anti-Corruption Plan

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(the “ZTAC Plan”); (v) the Penal Risk Prevention Model; (vi) the Enel Global Compliance Program on Corporate Criminal Liability (the “Enel Global Compliance Program”); (vii) the Risk Management and Control System; (viii) procedures issued in compliance with General Norm Regulation 385 (“NCG 385” in its Spanish Acronym), issued by the CMF, which deals with corporate governance matters; and (ix) the Diversity Policy.

The Manual, adopted by our board of directors, addresses the following issues: applicable standards and blackout periods regarding the information in connection with transactions of our securities or those of our affiliates, entered into by directors, management, principal executives, employees, and other related parties; the existence of mechanisms for the continuous disclosure of information that is of interest to the market; and procedures that protect confidential information.

Our board of directors approved a procedure for regulating the commercial and contractual relationships between Politically Exposed People (Procedimiento Personas Políticamente Expuestas y Conexas) and our Company. The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into corporate reality. The Code of Ethics is based on general principles such as impartiality, honesty, integrity, and other ethical standards of equal importance, all of which are expected from our employees. The ZTAC Plan reinforces the Code of Ethics principles, emphasizing avoiding corruption through bribes, preferential treatment, and other similar matters.

Our board of directors approved the Penal Risk Prevention Model and the Enel Global Compliance Program. The Penal Risk Prevention Model satisfies the standards imposed by Chilean Law 20,393, which imposes criminal responsibility for legal entities for certain crimes, including money laundering, financing of terrorism, and bribery of public officials. The adoption of the Penal Risk Prevention Model mitigates, and in some cases relieves, the effects of criminal responsibility even when a crime is committed. In turn, the Enel Global Compliance Program is designed to reinforce the group’s commitment to the highest ethical, legal, and professional standards for enhancing and preserving the group’s reputation. It sets several preventive measures for corporate criminal liability.

We follow the Risk Control and Management System guidelines defined by Enel for the standards, procedures, and systems applied at different levels of our companies to identify, analyze, evaluate, manage, and communicate risks. Enel classifies risk monitored in its Risk Catalogue into 6 macro-categories: Financial, Strategic, Governance & Culture, Operational, Compliance and Digital Technology.

We have a specific Risk Control and Management policy, as well as specific policies that are established in relation to certain risks, corporate functions or businesses of the Company and that include limits and indicators that are subsequently monitored. Our main risk control and management policies are described as follow:

● The Guarantee Management Policy establishes the guidelines and methodologies to apply to managing guarantees from suppliers and to ensure an effective mitigation of counterparty risk, related to the profile of the supplier and the guarantor.

● The Commodities Risk Control Policy aims to allow the Company to make informed decisions and to minimize the probability of not achieving strategic results. In addition, it allows the Company to control the risk of non-compliance with the regulation of prices, volume, exchange rate, credit and counterparty of commodities, as well as financial regulation.

● The Credit and Counterparty Risk Control Policy is designed to minimize the probability that expected results will be affected by a default or reduction in the credit quality of a counterparty.

● The Financial Risk Control Policy strives to minimize the probability of not achieving commercial and financial strategic results by controlling financial market, financial counterparty, liquidity, and operational risks.

● The Hedge Policy aims to mitigate the risk of variations in exchange rates by maintaining a balance between flows indexed to US$ or local currencies, if any, and the levels of assets and liabilities in such currency.

● The Climate Change Policy establishes a common framework for the Company to guarantee the effectiveness in strategically managing the risks and opportunities associated with climate change while integrating with the Company’s main processes and decision-making.

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The Risk Control area is ISO 31000:2018 (G31000) certified and acts under the guidelines of these international standards. The primary objective is to identify internal and external risks preemptively and to analyze, evaluate, and quantify the probability of their occurrence and impact on our companies. Each area manages risks using mitigation measures stipulated in action plans. In the risk management phase, necessary actions determined by internal policies and procedures are considered. The strict observance of ISO international standards and governmental regulations may require risk management actions to be documented to guarantee good governance practices and ensure business continuity.

In 2015, the CMF issued NCG 385 to enhance transparency standards and introduce corporate social responsibility practices by promoting, among other things, management diversity. The CMF requires us to provide them with information related to the board’s functions and composition; relationships between the company, shareholders, and the general public; third-party assessments; and internal control and risk management. The information must be provided annually by March 31 and be based on the previous calendar year. If none of them is adopted, the company must explain its reasons to the CMF. This information is available at the public’s disposal on the company’s website (www.enelamericas.com) and is sent to the stock exchanges.

In November 2021, the CMF issued General Norm Regulation No. 461 (“NCG 461”), which sets a new structure and contents for the Company’s Annual Report, including information previously reported through the NCG 385. Therefore NCG 385 will be derogated within a timeframe that depends on each company’s level of assets. In the case of Enel Américas, NCG 461 will be effective as of December 31, 2022, at which time NCG 385 will no longer apply to us.

In 2018, the board of directors approved a policy dealing with environmental and biodiversity issues. Environmental, social, and corporate governance criteria (“ESG”) are integrated into our business model. In compliance with NCG 385, the board periodically receives reports by management to identify and assess all risks associated with ESG and climate change issues, including compliance with board policies.

The board of directors approved the Diversity Policy on August 30, 2016. This policy defines the key principles required to spread a culture focused on diversity and respect, preventing arbitrary discrimination, and encouraging equal opportunities and inclusion, all fundamental values in developing the Company’s activities. Through this policy, the Company seeks to improve the work environment and the quality of life. The Company is committed to creating an inclusive work environment where workers can develop their potential and maximize their contribution.

A copy of these documents is available on our webpage at www.enelamericas.com as well as upon request, free of charge, by writing or calling us at:

Enel Américas S.A.

Investor Relations Department

Santa Rosa 76, Piso 15

Santiago, Chile

(56-2) 2353-4400

In the fiscal year 2021, there have been no amendments to any provisions of the documents described above. No waivers from any Code of Ethics provisions, the ZTAC Plan, or the Manual were expressly or implicitly granted to the Chief Executive Officer, the Chief Financial Officer, or any other senior financial officers of the Company in the fiscal year 2021.

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Item 16C. Principal Accountant Fees and Services

The following table provides information on the aggregate fees for approved services billed by our independent registered accounting firm KPMG Auditores Consultores SpA (“KPMG”) and its respective affiliates by type of services for the periods indicated.

Services Rendered	2021	2020
	(in thousands of US$)
Audit fees(1)	2,955	2,282
Audit-related fees(2)	917	2,039
Tax fees	—	—
All other fees	—	—
Total	3,872	4,321

(1) The ThUS$ 673 increase in audit fees in 2021 was mainly due to the incorporation of new companies of the EGP Américas group in South and Central America.

(2) The ThUS$ 1,122 decrease in audit-related fees in 2021 includes non-recurring services in connection with the proposed merger with EGP Américas for intermediate audits to September 2020 for ThUS$ 1,785, offset by non-recurring services in 2021 associated with intermediate audits to March 2021 for the merger with EGP Americas for ThUS$ 567.

All the fees disclosed under audit-related fees and all other fees were pre-approved by the Directors Committee pre-approval policies and procedures.

The amounts included in the table above and any related footnotes have been classified in accordance with SEC guidance.

Directors Committee Pre-Approval Policies and Procedures

The Directors Committee, which performs the functions of the Audit Committee, has a pre-approval policy regarding the contracting of our external auditor, or any affiliate of the external auditor, for professional services. The professional services covered by such policy include audit and non-audit services provided to us.

Fees payable in connection with recurring audit services are pre-approved as part of our annual budget. Fees payable in connection with non-recurring audit services, once the Chief Financial Officer has examined them, are submitted to the Directors Committee for its final consideration.

The pre-approval policy established by the Directors Committee for non-audit services and audit-related fees is as follows:

● The business unit that has requested the service and the audit firm expected to perform the service must request that the Chief Financial Officer review the nature of the service to be provided.

● The Chief Financial Officer then analyzes the request and requires the selected audit firm to issue a certificate signed by the partner responsible for the audit of our consolidated financial statements confirming such an audit firm’s independence.

● Finally, the proposal is submitted to the Directors Committee for approval or denial.

The Directors Committee has designed, approved, and implemented the necessary procedures to fulfill the SEC rules regarding the Audit Committee’s pre-approval of certain tax services.

Item 16D.   Exemptions from the Listing Standards for Audit Committees

Not applicable.

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Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth, for each of the calendar months in 2021, the total number of shares of common stock purchased by the Company, or on the Company’s behalf, or by any affiliated purchaser (which includes Enel), the average price paid per share, the number of shares purchased under a publicly announced plan or program.

Purchases of Equity Securities

2021	(a) Total Number Shares Purchased	(b) Average Price per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 1-31	—	—	—	—
February 1-28	—	—	—	—
March 1-31	—	—	—	7,608,631,104 (1)
April 1-30	7,608,559,104(2)	US$ 0.20	7,608,559,104	—
May 1-31	—	—	—	—
June 1-30	—	—	—	—
July 1-31	—	—	—	—
August 1-31	—	—	—	—
September 1-30	—	—	—	—
October 1-31	—	—	—	—
November 1-30	—	—	—	—
December 1-31	—	—	—	—

(1) On March 15, 2021, Enel launched the 2021 tender offer for the acquisition of our shares of common stock and ADS for up to a maximum of 7,608,631,104 shares of common stock, equivalent to 10% of our share capital, for a price of Ch$ 140 per share and Ch$ 7,000 per ADS (in its equivalent in U.S. dollars at the time of settlement in the case of ADS).

(2) In total, 20,194,895,308 shares (including 1,872,063,500 shares represented by 37,441,270 ADSs) were validly tendered and not properly withdrawn pursuant to the 2021 partial tender offer, resulting in a proration factor of approximately 37.7%. As a result of applying the proration factor, on April 16, 2021, Enel accepted for purchase 6,903,312,254 shares and 14,104,937 ADSs, representing an additional 705,246,850 shares in the 2021 partial tender offer.

As a result of the transactions described above, Enel increased its beneficial ownership in us from 65% as of December 31, 2020, to 82.3% as of the date of this Report. Enel’s control increased in 2021 as a result of the 2021 merger with EGP Américas and the 2021 partial tender offer.

Item 16F.   Change in Registrant’s Certifying Accountants

There has been no change in independent accountants for the Company during the two most recent fiscal years or any subsequent interim period except as previously reported in the Company’s Annual Report on Form 20-F for the fiscal year ended December 31, 2019. There have been no disagreements of the type required to be disclosed by Item 16F (b).

Item 16G.   Corporate Governance

The following summarizes the significant differences between our corporate governance practices and those applicable to U.S. domestic issuers under the NYSE’s corporate governance rules.

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Independence and Functions of the Directors Committee (Audit Committee)

Chilean law requires that at least two-thirds of the Directors Committee be independent directors. The CMF may, through a general norms’ regulation, set forth the requirements and conditions that must be met by board members to be independent directors. Notwithstanding the above, according to Article 50 bis of the Chilean Corporations Law, a member would not be considered independent if, at any time, within the last 18 months such member (i) had any relationship of a relevant nature and amount with the company, with other companies of the same group, with its controlling shareholder or with the principal officers of any of them or has been a director, manager, administrator or officer of any of them (with the CMF authorized to set forth the criteria of what will be deemed “relevant nature and amount”); (ii) had a family relationship with any of the members described in (i) above; (iii) has been a director, manager, administrator or principal officer of a non-profit organization that has received contributions from (i) above; (iv) has been a partner or a shareholder who has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of an entity that has provided consulting or legal services for a relevant consideration or external audit services to the persons listed in (i) above; and (v) has been a partner or a shareholder who has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of the top competitors, suppliers or customers. In case there are not enough independent directors on the board to serve on the Directors Committee, Chilean law determines that the independent director nominates the rest of the Directors Committee members among the remaining board members who do not meet the Chilean law independence requirements. Chilean law also requires that all publicly held limited liability stock corporations that have a market capitalization of at least UF 1,500,000 (US$ 55,035,113 as of December 31, 2021) and at least 12.5% of its voting shares are held by shareholders that individually control or own less than 10% of such shares, must have at least one independent director and a Directors Committee.

Under the NYSE corporate governance rules, all members of the Audit Committee must be independent. The Audit Committee of a U.S. company must perform the functions detailed in and otherwise comply with the requirements of NYSE Listed Company Manual Rules 303A.06 and 303A.07. As of July 31, 2005, non-U.S. companies have been required to comply with Rule 303A.06, but not with Rule 303A.07. Since July 31, 2005, we have complied with the independence and the functional requirement of Rule 303A.06.

On June 29, 2005, our board of directors created an Audit Committee composed of three directors who were also members of the board of directors, as required by the Sarbanes-Oxley Act (“SOX”) and the NYSE corporate governance rules. On April 22, 2010, our bylaws were amended at an ESM, and the Audit Committee was merged with the Directors Committee.

Under our bylaws, all Directors Committee members must satisfy the requirements of independence, as stipulated by the NYSE. The Directors Committee comprises three members of the board. It complies with Article 50 bis of the Chilean Corporations Law and the criteria and requirements of independence prescribed by the SOX, the SEC, and the NYSE. As of the date of this Report, the Directors Committee complies with the Audit Committee’s conditions as required by the SOX, the SEC, and the NYSE corporate governance rules. As a result, we have a single Committee, the Directors Committee, which includes the duties performed by an Audit Committee among its functions.

Corporate Governance Guidelines

The NYSE’s corporate governance rules require U.S.-listed companies to adopt and disclose corporate governance guidelines. Chilean law provides for this practice through the procedures related to NCG 385 and the Manual. We have also adopted the Code of Ethics. Our bylaws include provisions that govern the creation, composition, attributions, functions, and compensation of the Directors Committee, including the duties performed by an Audit Committee. Please see “Item 6. Directors, Senior Management and Employees — C. Board Practices” for more information about the Director Committee’s functions and duties.

Item 16H.   Mine Safety Disclosure

Not applicable.

Item  16I.      Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

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PART III

Item 17.  Financial Statements

Not Applicable.

Item 18.  Financial Statements

See Financial Statements included at the end of this Report.

Item 19.  Exhibits

Exhibit	Description
1.1	By-laws (Estatutos) of Enel Américas S.A. filed as Exhibit 1.1 to Enel Américas S.A’s Annual Report on Form 20-F for the ended December 31, 2020, is incorporated herein by reference.
2.1	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934 filed as Exhibit 2.1 to Enel Américas S.A.’s Annual Report on Form 20-F for the year ended December 31, 2020, is incorporated herein by reference.
8.1	List of Principal Subsidiaries as of December 31, 2021
12.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
12.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
13.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act
23.1	Consent of KPMG Auditores Consultores SpA, an independent registered public accounting firm
23.2	Consent of EY Audit SpA, an independent registered public accounting firm

101.INS	Inline XBRL Instance Document – The Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Taxonomy Extension Schema Document
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	Inline Cover Page Interactive Data File – The Cover Page Interactive Data File does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

We will furnish to the Securities and Exchange Commission, upon request, copies of any not filed instruments that define the rights of stakeholders of Enel Américas.

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SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

		ENEL AMÉRICAS S.A.
		By:	/s/ Maurizio Bezzeccheri
		Name:	Maurizio Bezzeccheri
		Title:	Chief Executive Officer
Date:	April 29, 2022

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Enel Américas and subsidiaries

Index to the Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firms:
Report of KPMG Auditores Consultores SpA (PCAOB ID No. 1273) — Enel Américas S.A. — 2021 and 2020	F-1 - F-5
Report of EY Audit SpA (PCAOB ID No. 1431) — Enel Américas S.A. — 2019	F-6
Consolidated Financial Statements:
Consolidated Statements of Financial Position	F-7
Consolidated Statements of Comprehensive Income	F-9
Consolidated Statements of Changes in Equity	F-11
Consolidated Statements of Direct Cash Flows	F-13
Notes to the Consolidated Financial Statements	F-14

Ch$	Chilean pesos
US$	U.S. dollars
UF	A “Unidades de Fomento” - Chilean inflation-indexed, Chilean peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
ThCh$	Thousands of Chilean pesos
ThUS$	Thousands of U.S. dollars
ARS	Argentine pesos
COP	Colombian pesos
BRL	Brazilian reals
PEN	Peruvian soles
EUR	Euro

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	iesco 5435, piso 4, Santiago

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Enel Américas S.A.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statement of financial position of Enel Américas S.A. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of comprehensive income, changes in equity, and cash flows for the years ended December 31, 2021 and 2020, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flow for the years ended December 31, 2021 and 2020, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited the reclassification to the 2019 consolidated financial statement of comprehensive income, as described in Note 2.2.c. In our opinion, such reclassification is appropriate and has been properly applied. We were not engaged to audit, review, or apply any procedures to the 2019 consolidated financial statements of the Company other than with respect to the reclassification and, accordingly, we do not express an opinion or any other form of assurance on the 2019 consolidated financial statements taken as a whole.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated April 29, 2022, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-1

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Unbilled revenue

As discussed in Notes 3-q and 27 to the consolidated financial statements, revenue from sales to customers  includes estimates of energy provided and not billed as of December 31, 2021, amounting to Th$958,321 related to the distribution and generation entities in Brazil, Colombia, Perú, Argentina and Central América. These estimates are made based on quantity of energy consumed by customers during the period, at the prices stipulated in the electricity tariffs in accordance with the current regulation or, if applicable, contractual arrangements with customers.

We identified the revenue recognition of energy provided and not invoiced as a critical audit matter due to the auditor judgment required to assess the complexity of the non-standardized determination of energy consumed by customers and the calculation of price formulas established in the contracts and regulations. In addition, auditor judgment was required to assess the adequacy of the nature and extent of the audit evidence obtained. The following are the primary procedures we performed to address this critical audit matter.

We evaluated the design and tested the operating effectiveness of certain internal controls related to unbilled revenue process. This includes controls:

•over the price used for estimation of unbilled sales to customers

•inputs used to estimate the quantity of energy consumed by customers, such as energy purchased from the Company and the customer’s historical consumption information, including the energy consumption by customers in the previous month

•the comparison between the estimate of unbilled revenue at the end of the month versus the actual volume of energy subsequently measured and billed to customers (back-testing) for distribution and generation entities.

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-2

We compared the volume used in the estimate of unbilled revenue at the end of the year versus the actual volume of energy subsequently measured and billed to clients (back-testing) or external data provided by the local regulator, as applicable. We reassessed a sample of the price used to calculate the unbilled sales to customers based on current contracts and decrees issued by the local regulator.  We evaluated the reconciliation of the sales ledger with the actual sales report at the end of the year. In addition, we assessed the sufficiency of the nature and extend of the audit evidence obtained, as well as the Company’s disclosures of this matter in Note 27 to the consolidated financial statements.

/s/ KPMG

KPMG Auditores Consultores SpA

We have served as the Company’s auditor since 2020.

Santiago, Chile

April 29, 2022

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-3

	iesco 5435, piso 4, Santiago

To the Stockholders and Board of Directors

Enel Américas S.A.:

Opinion on Internal Control Over Financial Reporting

We have audited Enel Américas S.A. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as of December 31, 2021 and 2020, the related consolidated statements of  comprehensive income, changes in equity, and cash flows for the years ended December 31, 2021 and 2020, and the related notes (collectively, the consolidated financial statements), and our report dated April 29, 2022 expressed an unqualified opinion on those consolidated financial statements.

The Company completed the acquisition of EGP Américas SpA, during 2021 and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021, EGP Américas’ internal control over financial reporting associated with 19.3% of consolidated assets and 3.7% consolidated revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2021. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of EGP Américas SpA.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-4

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG

KPMG Auditores Consultores SpA

Santiago, Chile

April 29, 2022

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-5

EY Chile Avda. Presidente Riesco 5435, piso 4, Las Condes, Santiago ​ Tel: +56 (2) 2676 1000 www.eychile.cl ​

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Enel Américas S.A.

Opinion on the Financial Statements

We have audited, before the effect of the adjustment to retrospectively apply the change in accounting described in Note 2.2.c), the consolidated statements of comprehensive income, shareholders' equity and cash flows of Enel Américas S.A. and Subsidiaries (the Company) for the year ended December 31, 2019 (the 2019 financial statements before the effect of the adjustment discussed in Note 2.2.c) is not presented herein). The 2019 financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

In our opinion, the 2019 financial statements, before the effect of the adjustment to retrospectively apply the change in accounting described in Note 2.2.c), present fairly, in all material respects, the results of its operations and its cash flows for the year ended December 31, 2019, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We were not engaged to audit, review, or apply any procedures to the adjustment to retrospectively apply the change in accounting described in Note 2.2.c) and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustment is appropriate and have been properly applied. This adjustment was audited by KPMG Auditores Consultores SpA.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ EY Audit SpA.        

EY Audit SpA.

We served as the Company’s auditor from 2011 to 2020.

Santiago, Chile

April 30, 2020

F-6

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Financial Position

As of December 31, 2021 and 2020

(In thousands of U.S. dollars – ThUS$)

			12-31-2021	12-31-2020
ASSETS		Note	ThUS$	ThUS$
CURRENT ASSETS
	���
Cash and cash equivalents		6	1,396,253	1,506,993
Other current financial assets		7	312,030	230,279
Other current non-financial assets		8	828,760	560,786
Trade and other receivables, current		9	3,711,141	3,234,935
Current accounts receivable from related parties		10	73,759	46,950
Inventories		11	538,276	471,433
Current tax assets		12	201,740	127,880
Total current assets other than assets or groups of assets for disposal classified as held for sale or as held for distribution to owners			7,061,959	6,179,256
Non-current assets or disposal groups held for sale			520	—
TOTAL CURRENT ASSETS			7,062,479	6,179,256
NON-CURRENT ASSETS
Other non-current financial assets		7	3,473,176	2,790,863
Other non-current non-financial assets		8	3,145,421	2,332,856
Trade and other non-current receivables		9	724,851	578,524
Non-current accounts receivable from related parties		10	26	32
Investments accounted for using the equity method		13	2,369	2,273
Intangible assets other than goodwill		14	4,756,270	4,524,826
Goodwill		15	1,470,225	945,512
Property, plant and equipment		16	12,997,528	8,354,672
Investment property			6,272	7,942
Right-of-use assets		17	327,953	222,420
Deferred tax assets		18	992,368	994,382
TOTAL NON-CURRENT ASSETS			27,896,459	20,754,302
TOTAL ASSETS			34,958,938	26,933,558

The accompanying notes are an integral part of these consolidated financial statements.

F-7

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Financial Position (continued)

As of December 31, 2021 and 2020

(In thousands of U.S. dollars – ThUS$)

		12-31-2021	12-31-2020
LIABILITIES AND EQUITY	Note	ThUS$	ThUS$
CURRENT LIABILITIES
Other current financial liabilities	19	1,232,834	1,825,130
Current lease liabilities	20	60,687	51,495
Trade and other payables, current	23	4,912,130	4,093,576
Current accounts payable to related parties	10	955,707	597,122
Other current provisions	24	164,844	220,425
Current tax liabilities	12	183,060	222,870
Other current non-financial liabilities	8	286,272	266,604
TOTAL CURRENT LIABILITIES		7,795,534	7,277,222
NON-CURRENT LIABILITIES
Other non-current financial liabilities	19	4,917,583	3,837,706
Non-current lease liabilities	20	187,891	91,070
Trade payables, non-current	23	2,689,067	2,061,475
Non-current accounts payable to related parties	10	1,062,498	144,391
Other long-term provisions	24	838,819	833,900
Deferred tax liabilities	18	879,400	612,953
Non-current provisions for employee benefits	25	1,423,481	1,624,217
Other non-current non-financial liabilities	8	134,572	116,961
TOTAL NON-CURRENT LIABILITIES		12,133,311	9,322,673
TOTAL LIABILITIES		19,928,845	16,599,895
EQUITY
Share and paid-in capital	26.1.1	15,799,499	9,763,078
Retained earnings		5,768,691	5,415,698
Treasury shares in portfolio		(272)	—
Other reserves	26.5	(8,735,261)	(7,072,917)
Equity attributable to shareholders of Enel Américas		12,832,657	8,105,859
Non-controlling interests	26.6	2,197,436	2,227,804
TOTAL EQUITY		15,030,093	10,333,663
TOTAL LIABILITIES AND EQUITY		34,958,938	26,933,558

The accompanying notes are an integral part of these consolidated financial statements.

F-8

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Nature

For the years ended December 31, 2021, 2020 and 2019

(In thousands of U.S. dollars – ThUS$)

		For the years ended December 31,
STATEMENTS OF PROFIT (LOSS)		2021	2020 (*)	2019 (*)
Profit (loss)	Note	ThUS$	ThUS$	ThUS$
Revenue	27	14,535,024	11,238,976	13,053,376
Other income, by nature	27	1,657,312	1,052,769	1,334,081
Revenues and Other income, by nature		16,192,336	12,291,745	14,387,457
Raw materials and consumables used	28	(10,451,383)	(7,555,915)	(8,541,023)
Contribution Margin		5,740,953	4,735,830	5,846,434
Other work performed by the entity and capitalized		210,552	147,151	181,565
Employee benefits expenses	29	(729,902)	(565,046)	(809,753)
Depreciation and amortization expense	30	(993,096)	(858,099)	(948,330)
Impairment (loss) reversal recognized in profit or loss	30	(100,057)	—	2,126
Impairment (loss) impairment gain and reversal of impairment loss determined in accordance with IFRS 9	30	(345,172)	(242,372)	(279,125)
Other expense, by nature	31	(1,119,232)	(1,065,278)	(1,150,709)
Operating income		2,664,046	2,152,186	2,842,208
Other gains (losses)		3,218	4,671	14,196
Finance income	32	295,442	222,406	376,316
Finance costs	32	(1,052,065)	(768,453)	(1,088,631)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	13	1,181	3,133	583
Foreign currency translation differences	32	(1,686)	57,171	136,960
Gains (losses) from indexed assets and liabilities	32	30,667	76,698	124,477
Profit (loss) before taxes		1,940,803	1,747,812	2,406,109
Income tax expense	18	(806,292)	(566,560)	(236,346)
PROFIT (LOSS)		1,134,511	1,181,252	2,169,763
Profit (loss) attributable to
Profit (loss) attributable to owners of the parent		740,859	825,197	1,614,085
Profit (loss) attributable to non-controlling interests	26.6	393,652	356,055	555,678
Profit (loss)		1,134,511	1,181,252	2,169,763
Basic earnings per share
Basic earnings (losses) per share	US$/Share	0.00744	0.01085	0.02465
Weighted average number of outstanding shares	Thousands	99,587,960	76,086,311	65,480,641
Diluted earnings per share
Diluted earnings (losses) per share	US$/Share	0.00744	0.01085	0.02465
Weighted average number of outstanding shares	Thousands	99,587,960	76,086,311	65,480,641

(*) See Note 2.2.c

The accompanying notes are an integral part of these consolidated financial statements.

F-9

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Nature (continued)

For the years ended December 31, 2021, 2020 and 2019

(In thousands of U.S. dollars – ThUS$)

		For the years ended December 31,
		2021	2020 (*)	2019 (*)
STATEMENTS OF COMPREHENSIVE INCOME	Note	ThUS$	ThUS$	ThUS$
Gains (losses)		1,134,511	1,181,252	2,169,763
Profit (loss) from defined benefit plans	25	9,312	(476,805)	(576,143)
Other comprehensive income that will not be reclassified subsequently to profit or loss		9,312	(476,805)	(576,143)
Components of other comprehensive income that will be reclassified subsequently to profit or loss before taxes
Losses (gains) from foreign currency translation difference	2.9	(1,193,451)	(2,249,915)	(765,005)
Losses (gains) from measuring financial assets at fair value through other comprehensive income		(9)	(10)	(598)
Gains (losses) from cash flow hedges		18,205	(15,547)	6,100
Adjustments from reclassification of cash flow hedges, transferred to profit or loss		2,570	2,571	(194)
Other comprehensive income that will be reclassified subsequently to profit or loss		(1,172,685)	(2,262,901)	(759,697)
Total components of other comprehensive loss (income) before taxes		(1,163,373)	(2,739,706)	(1,335,840)
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss
Income tax related to defined benefit plans		(3,023)	161,766	195,098
Income tax related to components of other comprehensive (loss) income that will not be reclassified subsequently to profit or loss		(3,023)	161,766	195,098
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss
Income tax related to cash flow hedge		(8,826)	5,038	(2,165)
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss		(8,826)	5,038	(2,165)
Total Other Comprehensive Income (Loss)		(1,175,222)	(2,572,902)	(1,142,907)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(40,711)	(1,391,650)	1,026,856
Comprehensive income (loss) attributable to:
Owners of Enel Américas		(131,803)	(1,521,532)	623,512
Non-controlling interests		91,092	129,882	403,344
TOTAL COMPREHENSIVE INCOME (LOSS)		(40,711)	(1,391,650)	1,026,856

(*) See Note 2.2.c

The accompanying notes are an integral part of these consolidated financial statements.

F-10

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Changes in Equity

For years ended December 31, 2021, 2020 and 2019

(In thousands of U.S. dollars – ThUS$)

			Changes in Other Reserves
Consolidated Statement of Changes in Equity	Share and paid-in capital (1) ThUS$	Treasury Shares ThUS$	Reserve for Exchange Differences in Translation (2) ThUS$	Reserves for Cash Flow Hedges ThUS$	Reserve for Gains and Losses for Defined Benefit Plans ThUS$	Reserve for Gains and Losses on Remeasuring Financial Asset at Fair Value of Other Comprehensive Income ThUS$	Other Miscellaneous Reserves ThUS$	Total Other Reserves (3) ThUS$	Retained Earnings ThUS$	Equity Attributable to Owners of Enel Américas ThUS$	Non-Controlling Interests (4) ThUS$	Total Equity ThUS$
Equity at beginning of period 1-1-2021	9,763,078	—	(4,308,296)	(9,383)	—	(692)	(2,754,546)	(7,072,917)	5,415,698	8,105,859	2,227,804	10,333,663
Changes in equity
Comprehensive income:
Profit (loss)	—	—	—	—	—	—	—	—	740,859	740,859	393,652	1,134,511
Other comprehensive income (loss)	—	—	(881,898)	9,809	(568)	(5)	—	(872,662)	—	(872,662)	(302,560)	(1,175,222)
Comprehensive income	—	—	—	—	—	—	—	—	—	(131,803)	91,092	(40,711)
Share issuance	6,036,421	—	—	—	—	—	—		—	6,036,421	—	6,036,421
Dividends	—	—	—	—	—	—	—	—	(387,298)	(387,298)	(534,870)	(922,168)
Increase (decrease) due to other changes	—	—	—	—	568	—	(790,250)	(789,682)	(568)	(790,250)	413,410	(376,840)
Increase (decrease) through treasury share transactions	—	(272)	—	—	—	—	—		—	(272)		(272)
Total changes in equity	6,036,421	(272)	(881,898)	9,809	—	(5)	(790,250)	(1,662,344)	352,993	4,726,798	(30,368)	4,696,430
Equity at end of period 12-31-2021	15,799,499	(272)	(5,190,194)	426	—	(697)	(3,544,796)	(8,735,261)	5,768,691	12,832,657	2,197,436	15,030,093

			Changes in Other Reserves
Consolidated Statement of Changes in Equity	Share and paid-in capital (1) ThUS$	Treasury Shares ThUS$	Reserve for Exchange Differences in Translation (2)	Reserves for Cash Flow Hedges	Reserve for Gains and Losses for Defined Benefit Plans	Reserve for Gains and Losses on Remeasuring Financial Asset at Fair Value of Other Comprehensive Income	Other Miscellaneous Reserves	Total Other Reserves (3)	Retained Earnings	Equity Attributable to Owners of Enel Américas	Non-Controlling Interests (4)	Total Equity
Equity at beginning of period 1-1-2020	9,783,875		(2,283,155)	(1,334)	—	(687)	(3,006,823)	(5,291,999)	5,474,411	9,966,287	2,279,899	12,246,186
Changes in equity
Comprehensive income
Profit (loss)	—		—	—	—	—	—	—	825,197	825,197	356,055	1,181,252
Other comprehensive income (loss)	—		(2,025,141)	(8,049)	(313,534)	(5)	—	(2,346,729)	—	(2,346,729)	(226,173)	(2,572,902)
Comprehensive income (loss)	—		—	—	—	—	—	—	—	(1,521,532)	129,882	(1,391,650)
Dividends	—		—	—	—	—	—	—	(570,376)	(570,376)	(306,309)	(876,685)
Increase (decrease) due to other changes	(20,797)	—	—	—	313,534	—	252,277	565,811	(313,534)	231,480	124,332	355,812
Total changes in equity	(20,797)	—	(2,025,141)	(8,049)	—	(5)	252,277	(1,780,918)	(58,713)	(1,860,428)	(52,095)	(1,912,523)
Equity at end of period 12-31-2020	9,763,078	—	(4,308,296)	(9,383)	—	(692)	(2,754,546)	(7,072,917)	5,415,698	8,105,859	2,227,804	10,333,663

F-11

			Changes in Other Reserves
Consolidated Statement of Changes in Equity	Share and paid-in capital (1) ThUS$	Treasury Shares ThUS$	Reserve for Exchange Differences in Translation (2)	Reserves for Cash Flow Hedges	Reserve for Gains and Losses for Defined Benefit Plans	Reserve for Gains and Losses on Remeasuring Financial Asset at Fair Value of Other Comprehensive Income	Other Miscellaneous Reserves	Total Other Reserves (3)	Retained Earnings	Equity Attributable to Owners of Enel Américas	Non-Controlling Interests (4)	Total Equity
Equity at beginning of period 1-1-2019	6,763,204		(1,666,109)	(5,094)	—	(397)	(3,209,283)	(4,880,883)	4,841,687	6,724,008	2,107,892	8,831,900
Changes in equity
Comprehensive income
Profit (loss)	—		—	—	—	—	—	—	1,614,085	1,614,085	555,678	2,169,763
Other comprehensive income (loss)	—		(617,046)	3,760	(376,997)	(290)	—	(990,573)	—	(990,573)	(152,334)	(1,142,907)
Comprehensive income	—		—	—	—	—	—	—	—	623,512	403,344	1,026,856
Share issuance	3,020,671		—	—	—	—		—	—	3,020,671	—	3,020,671
Dividends	—		—	—	—	—	—	—	(604,364)	(604,364)	(289,052)	(893,416)
Increase (decrease) due to other changes	—	—	—	—	376,997	—	202,460	579,457	(376,997)	202,460	57,715	260,175
Total changes in equity	3,020,671	—	(617,046)	3,760	—	(290)	202,460	(411,116)	632,724	3,242,279	172,007	3,414,286
Equity at end of period 12-31-2019	9,783,875	—	(2,283,155)	(1,334)	—	(687)	(3,006,823)	(5,291,999)	5,474,411	9,966,287	2,279,899	12,246,186

(1) See Note 26.1

(2) See Note 26.2

(3) See Note 26.5

(4) See Note 26.6

The accompanying notes are an integral part of these consolidated financial statements.

F-12

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Cash Flows, Direct

For the years ended December 31, 2021, 2020 and 2019

(In thousands of U.S. dollars – ThUS$)

		For the years ended December 31,
		2021	2020	2019
Consolidated Statements of Cash Flows, Direct Method	Note	ThUS$	ThUS$	ThUS$
Cash flows from (used in) operating activities
Collections from the sale of goods and services		19,737,179	14,770,122	18,408,759
Collections from royalties, payments, commissions, and other revenue		54,073	36,171	38,223
Collections from premiums and services, annual payments, and other benefits from policies held		11,675	28,364	26,940
Other collections from operating activities		700,664	1,269,911	828,859
Payments to suppliers for goods and services		(11,673,564)	(8,185,560)	(9,343,478)
Payments to and on behalf of employees		(718,763)	(731,887)	(867,683)
Payments of premiums and services, annual payments, and other obligations from policies held		(12,624)	(13,014)	(11,723)
Other payments for operating activities	6.c	(4,479,954)	(4,013,788)	(5,723,433)
Interests paid		(17)	(4,675)	(8,343)
Cash flows from (used in) operating activities
Income taxes paid		(720,829)	(527,952)	(561,805)
Other cash inflows (outflows)		(282,264)	(202,182)	(258,805)
Net cash flows from (used in) operating activities		2,615,576	2,425,510	2,527,511
Cash flows from (used in) investing activities
Cash flows used in the purchase of non-controlling interests		—	—	(97,517)
Other collections from the sale of equity or debt instruments belonging to other entities		1,248,281	176,383	284,939
Other payments to acquire equity or debt instruments of other entities		(1,265,183)	(215,626)	(245,390)
Loans to related parties		(48,545)	—	—
Purchases of property, plant and equipment		(1,841,204)	(813,827)	(891,599)
Purchases of intangible assets		(1,170,407)	(739,664)	(767,291)
Payments from future, forward, option and swap contracts		(22,787)	(5,070)	(3,909)
Collections from future, forward, option and swap contracts		43,544	21,037	14,981
Collections from related entities		82,597	—	—
Dividends received		1,089	2,120	1,521
Interest received		28,693	43,400	111,730
Other inflows (outflows) of cash, net	6.d	1,009,625	(4,369)	(7,263)
Net cash flows used in investing activities		(1,934,297)	(1,535,616)	(1,599,798)
Cash flows from (used in) financing activities
Proceeds from issuance of shares	26.1.1	—	—	2,999,874
Payments for acquiring treasury shares		(282)	—	—
​ Payments for other equity interests		(29,547)	—	—
Total proceeds from loans	6.e	2,727,331	1,646,135	4,898,823
Proceeds from long-term loans		1,670,872	437,284	1,164,306
Proceeds from short-term loans		1,056,459	1,208,851	3,734,517
Loans from related parties		1,274,799	295,299	—
Payment of borrowings	6.e	(2,858,855)	(1,775,865)	(4,782,344)
Payment of lease liabilities	6.e	(65,009)	(77,292)	(59,177)
Payment of loans to related parties	6.e	(445,257)	—	(2,662,433)
Dividends paid		(962,959)	(1,057,692)	(723,983)
Interest paid	6.e	(338,978)	(326,703)	(614,599)
Other cash inflows (outflows)	6.e	104,007	109,583	120,935
Net cash flows used in financing activities		(594,750)	(1,186,535)	(822,904)
Net increase (decrease) in cash and cash equivalents before effect of exchange rate changes		86,529	(296,641)	104,809
Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents		(197,269)	(135,363)	(70,097)
Net increase (decrease) in cash and cash equivalents		(110,740)	(432,004)	34,712
Cash and cash equivalents at beginning of period	6	1,506,993	1,938,997	1,904,285
Cash and cash equivalents at end of period	6	1,396,253	1,506,993	1,938,997

The accompanying notes are an integral part of these consolidated financial statements.

F-13

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contents		Page
1.	GENERAL INFORMATION	F-17
2.	BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS	F-18
2.1	Accounting principles	F-18
2.2	New accounting pronouncements	F-18
2.3	Responsibility for the information, judgments and estimates provided	F-25
2.4	Subsidiaries	F-27
	2.4.1 Changes in the scope of consolidation	F-27
	2.4.2 Consolidated companies with an economic equity interest of less than 50%	F-28
2.5	Investments in associates	F-28
2.6	Joint arrangements	F-28
2.7	Basis of consolidation and business combinations	F-29
2.8	Functional Currency	F-30
2.9	Conversion of financial statements denominated in foreign currency	F-30
3.	ACCOUTING POLICIES	F-32
a)	Property, plant and equipment	F-32
b)	Investment Property	F-34
c)	Goodwill	F-34
d)	Intangible assets other than goodwill	F-35
	d.1) Concessions	F-35
	d.2) Research and development expenses	F-36
	d.3) Other intangible assets	F-36
e)	Impairment of non-financial assets	F-37
f)	Leases	F-39
	f.1) Lessee	F-39
	f.2) Lessor	F-40
g)	Financial instruments	F-40
	g.1) Financial assets other than derivatives	F-40
	g.2) Cash and cash equivalents	F-41
	g.3) Impairment of financial assets	F-41
	g.4) Financial liabilities other than derivatives	F-43
	g.5) Derivative financial instruments and hedging transactions	F-43
	g.6) Derecognition of financial assets and liabilities	F-44
	g.7) Offsetting financial assets and liabilities	F-45
	g.8) Financial guarantee contracts	F-45
h)	Fair value measurment	F-45
i)	Investments accounted for using the equity method	F-46
j)	Inventories	F-47
k)	Non-current assets (or disposal groups) classified as held for sale or as held for distribution to owners and discontinued operations	F-47
l)	Treasury shares	F-48
m)	Provisions	F-48
	m.1) Provisions for post-employment benefits and similar obligations	F-48
n)	Translation of balances in foreign currency	F-49
o)	Classification of balances as current or non-current	F-49
p)	Income taxes	F-49
q)	Revenues and expense recognition	F-50
r)	Earnings per share	F-52
s)	Dividends	F-52
t)	Share issuance costs	F-52

F-14

u)	Statement of cash flows		F-53
4.	SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS		F-53
i.	Regulatory framework		F-53
ii.	Limits on integration and concentration		F-69
iii.		Unregulated customers market	F-69
5.		BUSINESS COMBINATION UNDER COMMON CONTROL	F-70
6.		CASH AND CASH EQUIVALENTS	F-72
7.		OTHER FINANCIAL ASSETS	F-75
8.		OTHER NON-FINANCIAL ASSETS AND LIABILITIES	F-76
9.		TRADE AND OTHER RECEIVABLES	F-78
10.		BALANCES AND TRANSACTIONS WITH RELATED PARTIES	F-81
10.1		Balances and transactions with related parties	F-81
		a) Receivables from related companies	F-81
		b) Accounts payable to related companies	F-82
		c) Significant transactions and effects on profit or loss	F-83
		d) Significant transactions of Enel Américas	F-83
10.2		Board of directors and key management personnel	F-85
		a) Accounts receivable and payable and other transactions	F-86
		b) Guarantees given by the Company in favor of the directors	F-86
		c) Compensation for directors	F-86
10.3		Compensation of key management personnel	F-88
		a) Remunerations received by key management personnel	F-88
		b) Guarantees established by the Company in favor of key management personnel	F-88
10.4		Compensation plans linked to share price	F-88
11.		INVENTORIES	F-89
12.		CURRENT TAX ASSETS AND LIABILITIES	F-89
13.		INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD	F-90
13.1		Investments accounted for using the equity method	F-90
14.		INTANGIBLE ASSETS OTHER THAN GOODWILL	F-92
15.		GOODWILL	F-94
16.		PROPERTY, PLANT AND EQUIPMENT	F-96
17.		RIGHT-OF-USE ASSETS	F-99
18.		INCOME TAX AND DEFERRED TAXES	F-101
		a) Income taxes	F-101
		b) Deferred taxes	F-102
19.		OTHER FINANCIAL LIABILITIES	F-106
		a) Interest-bearing borrowings	F-106
		b) Unsecured liabilities	F-110
		c) Secured liabilities	F-113
		d) Hedged debt	F-114
		e) Other information	F-115
		f) Future undiscounted debt flows	F-115
20.		LEASE LIABILITIES	F-117
20.1		Individualization of Lease Liabilities	F-118
20.2		Undiscounted debt cash flows	F-120
21.		RISK MANAGEMENT POLICY	F-121
22.		FINANCIAL INSTRUMENTS	F-125
22.1		Financial instruments, classified by type and category	F-125
22.2		Derivative instruments	F-126
22.3		Fair value hierarchies	F-129
23.		CURRENT AND NON-CURRENT PAYABLES	F-130
24.		PROVISIONS	F-131
25.		POST-EMPLOYMENT BENEFIT OBLIGATIONS	F-132
25.1		General information	F-132
25.2		Details, changes and presentation in financial statements	F-133
25.3		Other disclosures	F-138

F-15

26.	EQUITY	F-140
26.1	Equity attributable to the shareholders of Enel Américas	F-140
26.2	Foreign currency translation reserves	F-142
26.3	Capital Management	F-142
26.4	Restrictions on subsidiaries transferring funds to the parent	F-142
26.5	Other reserves	F-143
26.6	Non-controlling Interests	F-145
27.	REVENUE AND OTHER OPERATING INCOME	F-146
28.	RAW MATERIALS AND CONSUMABLES USED	F-147
29.	EMPLOYEE BENEFITS EXPENSE	F-147
30.	DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES OF PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS UNDER-IFRS 9	F-147
31.	OTHER EXPENSES, BY NATURE	F-148
32.	FINANCIAL RESULTS	F-149
33.	INFORMATION BY SEGMENT	F-151
33.1	Basis of segmentation	F-151
33.2	Generation and transmission, distribution and others	F-153
33.3	Segment information by country	F-155
33.4	Generation and Transmission, and Distribution by Country	F-157
34.	GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS	F-161
34.1	Direct guarantees	F-161
34.2	Indirect guarantees	F-161
34.3	Litigation and Arbitration Proceedings	F-163
34.4	Financial restrictions	F-174
34.5	COVID-19 contingency	F-179
34.6	Other Information	F-180
35.	HEADCOUNT	F-182
36.	SANCTIONS	F-182
37.	ENVIRONMENT	F-188
38.	FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED	F-191
39.	SUBSEQUENT EVENTS	F-193
APPENDIX 1 COMPANIES FROM THE ENEL AMERICAS GROUP		F-194
APPENDIX 2 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY		F-198
APPENDIX 3 ADDITIONAL INFORMATION OFFICIAL BULLETIN No. 715 OF FEBRUARY 3, 2012		F-200
APPENDIX 3.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES		F-202
APPENDIX 3.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY		F-204
APPENDIX 4 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS		F-205

F-16

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2021 AND 2020 AND FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019.

(In thousands of U.S. dollars – ThUS$)

1.  GENERAL INFORMATION

Enel Américas S.A. (hereinafter “Enel Américas”, the “Company” or the “Parent Company”) and its subsidiaries comprise the Enel Américas Group (hereinafter the “Group”).  

The Company is a publicly traded corporation with registered address and head office located at Avenida Santa Rosa, No. 76, in Santiago, Chile. The Company is registered with the securities register of the Financial Market Commission of Chile, hereinafter “CMF”, under number 0175. In addition, the Company is registered with the Securities and Exchange Commission of the United States of America (hereinafter the “U.S. SEC”) and its shares have been listed on the New York Stock Exchange since 1993.

The Company is a subsidiary of Enel S.p.A. (hereinafter “Enel”), an entity that owns a 82.3% interest.

The Company was initially incorporated in 1981 under the corporate name Compañía Chilena Metropolitana de Distribución Eléctrica S.A. Subsequently, on August 1, 1988 the Company became Enersis S.A., by means of an amendment to the articles of incorporation. Within the context of the reorganization process carried out by the Group, on March 1, 2016, the Company became Enersis Américas S.A. On December 1, 2016, the corporate name was changed from Enersis Américas S.A. to Enel Américas S.A. For tax purposes, the Company operates under Chilean tax identification number 94.271.000‑3.

The Group recorded a staff of 16,461 employees as of December 31, 2021. On average, during the period 2021 the Group had 16,780 employees. For more information regarding the distribution of our employees, by category and geographic location, see Note 35.

The Company’s corporate purpose consists of exploring for, developing, operating, generating, distributing, transmitting, transforming, and/or selling energy of any kind or form, whether in Chile or abroad, either directly or through other companies. It is also engaged in telecommunications activities, and it provides engineering consulting services in Chile and abroad. The Company’s corporate purpose also includes investing in, and managing, its investments in subsidiaries and associates which generate, transmit, distribute, or sell electricity, or whose corporate purpose includes any of the following:

(i) Energy of any kind or form,

(ii) Supplying public services, or services whose main component is energy,

(iii) Telecommunications and information technology services, and

(iv) Internet-based intermediation business.

F-17

2.  BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1. Accounting principles

The consolidated financial statements of Enel Américas as of December 31, 2021, approved by its Board of Directors at its meeting held on April 29, 2022, have been prepared in accordance with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB).

These consolidated financial statements present fairly the financial position of Enel Américas and its subsidiaries as of December 31, 2021 and 2020, and the results of operations, changes in equity and cash flows for the years ended December 31, 2021, 2020 and 2019, and the related notes.

These consolidated financial statements have been prepared under going concern assumptions on a historical cost basis except when, in accordance with IFRS, those assets and liabilities are measured at fair value.

Appendix 1 – Detail of Assets and Liabilities in Foreign Currency; Appendix 2 – Additional Information Circular No. 715 of February 2, 2012; Appendix 2.1 – Supplementary Information on Trade Receivables; Appendix 2.2 – Estimated Sales and Purchases of Capacity and Toll and Appendix 3 – Detail of Due Dates of Payments to Suppliers, form an integral part of these consolidated financial statements.

2.2. New accounting pronouncements

a) The following accounting pronouncements have been adopted by the Group effective as of January 1, 2021:

Amendments and Improvements	Mandatory application for annual periods beginning on or after:
Amendments to IFRS 16: COVID-19-Related Rent Concessions	June 1, 2020
Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16: Interest Rate Benchmark Reform – Phase 2	January 1, 2021

● Amendments to IFRS 16: COVID-19-Related Rent Concessions

As a result of the COVID-19 pandemic, lessees in many countries have been granted rent payment concessions, such as grace periods and delaying of lease payments for a period of time, sometimes followed by an increase in the payment in future periods. Within this context, on May 28, 2020, the IASB issued amendments to IFRS 16: Leases, in order to provide a practical expedient for lessees, through which they can opt for not evaluating whether the rent concessions are a modification of the lease. Lessees that elect this option, will account for such rent concessions as a variable payment.

The practical expedient is only applicable to rent concessions that occur as a direct consequence of the COVID-19 pandemic and only if they comply with all the following conditions:

i) the change in lease payments is the product of a revised lease payment that is substantially the same, or less than the lease payment immediately before the change;

ii) any reduction in lease payments affects only the payments originally due up to June 30, 2021; and

iii) there is no substantial change in the other terms and conditions of the lease.

The amendments are applicable to annual periods beginning on or after June 1, 2020. These amendments must be applied retroactively, recognizing the accumulated effect from initial application as an adjustment in the beginning balance of retained earnings (or other equity component, as applicable) at the beginning of the annual period in which the amendment is applied for the first time.

F-18

The application of these improvements did not generate an impact on the Group’s consolidated financial statements.

● Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16: Interest Rate Benchmark Reform (Phase 2)

On August 27, 2020, the IASB finalized a reform that phased out benchmark interest rates, such as Interbank Offering Interest Rates (IBORs), by issuing a package of amendments to the following IFRS:

- IFRS 9 Financial Instruments

- IAS 39 Financial Instruments: Recognition and Measurement

- IFRS 7 Financial Instruments: Disclosures

- IFRS 4 Insurance Contracts

- IFRS 16 Leases

These amendments are intended to help companies provide investors with useful information about the effects of the reform on their financial statements.

Background information

IBORs are interest rates published on a daily basis, compared with the average interest rates that a specific number of financial institutions grant unsecured interbank financing, according to different terms and currencies.

Because of concerns regarding attempts to manipulate benchmark interest rates in recent years, regulators around the world started a radical reform on these rates to increase the reliability of benchmark interest rates within the international financial system. The aim of the reform is to replace interbank offering interest rates with alternative risk-free reference rates (RFR), which are based on liquid transactions in underlying markets and do not depend on expert judgments, such as the Secured Overnight Funding Rate (SOFR).

 ​

Phase 1 Amendments

Phase 1 of the IASB’s work was focused on providing temporary exceptions that allow entities to continue to apply hedge accounting during the uncertain period prior to IBOR replacement. This phase culminated in 2019 with the issuance of amendments to IFRS 9, IAS 39 and IFRS 7, which became effective on January 1, 2020.

Phase 2 Amendments

Phase 2 complements the previous amendments and addresses the effects on financial statements when a company replaces a previous benchmark interest rate with an alternative benchmark interest rate. These amendments mainly relate to the following:

- Changes in contractual cash flows: a company will not have to derecognize accounts or adjust the carrying amounts of financial instruments due to changes required by the reform, but rather will update the effective interest rate to reflect the change in the alternative interest rate benchmark;

- Hedge accounting: a company will not have to discontinue its hedge accounting solely because it makes the changes required by the reform, if the hedge complies with other hedge accounting criteria; and

- Disclosures: a company will be required to disclose information about new risks that arise from the reform and how it manages the transition to alternative interest rate benchmarks.

Phase 2 amendments issued became effective beginning on January 1, 2021, with retrospective application, subject to certain exceptions. It is not necessary to restate previous periods.

F-19

Hedging relationships

The Group has assessed the impact of the uncertainty generated by the reform in the current hedging relationships, with reference to both the hedging instruments and hedged items. The Group’s most relevant exposure is to the USD LIBOR rate.

The hedging relationships affected by the IBOR reform could be rendered ineffective due to the expectations of market participants regarding the time when interbank market-based benchmark rates will transition to risk-free alternative rates. This transition could occur at different times for hedged items and hedging instruments and could lead to ineffectiveness. Therefore, the Group is applying the amendments to IFRS 9 issued in September 2019 (Phase 1 amendments) to the hedging relationships directly affected by the reform.

Group Exposure

In March 2021, the succession dates of LIBOR were announced: December 31, 2021, for LIBOR in euros, Swiss francs, yen and British pounds regardless of terms, and LIBOR in USD at one week and two months, and June 30, 2023, for all other USD LIBOR terms. Accordingly, the Group has completed an evaluation of the impact of the LIBOR reform on loan agreements and derivative instrument contracts after having defined the scope regarding number and nominal value, including the determination of fallback rates for new transactions. The alternative benchmark rates will begin to be applied as of July 1, 2023, with the elimination of the remaining USD LIBOR rates.

 ​

As of December 31, 2021, the Group’s exposure in terms of the notional amounts of the contracts that must transition to an alternative reference rate, by type of instrument and interest rate, is detailed as follows:

	Notional as of 12-31-2021
Type of interest rate	Non-derivative financial liabilities MUS$	Derivative instruments MUS$	Total MUS$
USD LIBOR	1,620	390	2,010

F-20

b) Accounting pronouncements applicable beginning on January 1, 2021 and thereafter:

As of the date of issuance of these consolidated financial statements, the following accounting pronouncements had been issued by the IASB, but their application was not mandatory:

Amendments and Improvements	Mandatory application for annual periods beginning on or after:
Amendments to IFRS 16: COVID-19-Related Rent Concessions beyond June 30, 2021	April 1, 2021
Amendments to IFRS 3: References to the Conceptual Framework	January 1, 2022
Amendments to IAS 16: Proceeds before Intended Use	January 1, 2022
Amendments to IAS 37: Onerous Contracts – Cost of Fulfilling a Contract	January 1, 2022
Annual Improvements to IFRS: 2018-2020 Cycle -IFRS 1: First-time Adoption of International Financial Reporting Standards -IFRS 9: Financial Instruments -Amendment to Illustrative Examples accompanying IFRS 16 -IAS 41: Agriculture	January 1, 2022
Amendments to IAS 1: Classification of Liabilities as Current or Non-current	January 1, 2023
Amendments to IAS 1 and IFRS Practice Statement 2: Disclosure of Accounting Policies	January 1, 2023
Amendments to IAS 8: Definition of Accounting Estimates	January 1, 2023
Amendments to IAS 12: Deferred Tax related to Assets and Liabilities arising from a Single Transaction	January 1, 2023

● Amendments to IFRS 16: COVID-19-Related Rent Concessions after June 30, 2021

Because of the continued impact of the COVID-19 pandemic, the IASB issued an amendment to IFRS 16 Leases on March 31, 2021, that extended by one year the period of application of the practical expedient that helps lessees to account for rental concessions linked to COVID-19. With these amendments, the IASB extended the practical expedient to rent concessions that reduce lease payments originally due on or before June 30, 2022.

The amendment is effective for annual periods beginning on or after April 1, 2021, retrospectively, recognizing the cumulative effect of initially applying the amendment as an adjustment to the opening balance of retained earnings (or other component of equity, as appropriate) at the beginning of the annual reporting period in which the lessee first applies the amendment. Earlier application is permitted, even for Financial Statements that have not been authorized for publication as of March 31, 2021. Enel Américas has decided not to early apply these amendments.

Management has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

● Amendments to IFRS 3: “References to the Conceptual Framework”.

On May 14, 2020, the IASB issued a package of limited-scope amendments, including amendments to IFRS 3: Business Combinations. The amendments update references to the Conceptual Framework issued in 2018, in order to determine an asset or a liability in a business combination. In addition, the IASB added a new exception to IFRS 3 for liabilities and contingent liabilities, which specifies that, for certain types of liabilities and

F-21

contingent liabilities, an entity that applies IFRS 3 must refer to IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”, or IFRIC 21: “Levies”, instead of the 2018 Conceptual Framework. Without this exception, an entity would have recognized certain liabilities in a business combination that would not be recognized in accordance with IAS 37.

The amendments are applicable prospectively to business combinations with acquisition dates beginning on the first annual period beginning on or after January 1, 2022. Early application is permitted.

Management has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

● Amendments to IAS 16: “Proceeds before Intended Use”

As part of the package of limited-scope amendments issued in May 2020, the IASB issued amendments to IAS 16 Property, Plant and Equipment, which prohibit a company from deducting from the cost of property, plant and equipment amounts received from selling items produced while the company is preparing the asset for its intended use. Instead, the company will recognize such sales proceeds and related costs in profit or loss for the period. The amendments also clarify that an entity is “testing whether an asset operates correctly” when it evaluates the technical and physical performance of the asset.

These amendments are applicable to annual reporting periods beginning on or after January 1, 2022. Early application is permitted. The amendments will be applied retroactively, but only from the beginning of the first period presented in the financial statements in which the entity applies the amendments for the first time. The accumulated effect of initial application of the amendments will be recognized as an adjustment to the opening balance of retained earnings (or other equity components as applicable) at the beginning of the first reported period.

Management has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

● Amendments to IAS 37: “Onerous Contracts: Cost of Fulfilling a Contract”

The third standard amended by the IASB in the package of limited-scope amendments issued in May 2020 was IAS 37 Provisions, Contingent Liabilities and Contingent Assets. The amendments specify which costs a company should include when evaluating whether a contract is onerous. In this sense, the amendments clarify that the direct cost of fulfilling a contract comprises both the incremental costs of fulfilling this contract (for example, direct labor and materials), as well as the allocation of other costs that are directly related to compliance with the contracts (for example, an allocation of the depreciation charge for an item of property, plant and equipment used to fulfill the contract).

These amendments are applicable for reported annual periods beginning on or after January 1, 2022. Early application is permitted. Companies must apply these amendments to contracts for which all obligations have still not been fulfilled at the beginning of the reported annual period in which the amendments are applied for the first time. They do not require restatement of comparative information. The accumulated effect of initially applying the amendments will be recognized as an adjustment to the opening balance of retained earnings (or another equity component as applicable) on the date of initial application.

Management has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

F-22

● Annual Improvements to IFRS: 2018-2020 Cycle

On May 14, 2020, the IASB issued a number of minor amendments to IFRSs, in order to clarify or correct minor issues or overcome possible inconsistencies in the requirements of certain standards. The amendments with potential impact on the Group are the following:

- IFRS 9 “Financial Instruments”: clarifies that for the purpose of the 10% test for derecognition of financial liabilities, when determining commissions paid net of commissions received, the borrower must only consider the commissions paid or received between the borrower and the lender.

These improvements are applicable to reported annual periods beginning on January 1, 2022. Early application is allowed. Entities must apply these amendments to financial liabilities that are modified or exchanged at the beginning of the reported annual period, in which the amendments are applied for the first time.

- Examples accompanying “IFRS 16 Leases”: amendment of illustrative example 13, in order to eliminate a possible confusion regarding the treatment of lease incentives. The example included as part of its background information, a reimbursement from the lessor to the lessee, related to leasehold improvements. Since the example was not sufficiently clear as to whether the reimbursement complied with the definition of a lease incentive, the IASB decided to eliminate from the illustrative example any reference to this reimbursement, thus avoiding any possibility of confusion.

Management has assessed the impacts of this amendment and has concluded that its implementation does not have a significant impact on the Group’s consolidated financial statements.

 ​

● Amendments to IAS 1: “Classification of Liabilities as Current and Non-Current”

On January 23, 2020, the IASB issued limited-scope amendments to IAS 1 “Presentation of Financial Statements”, in order to clarify how to classify debt and other liabilities as current or non-current. The amendments clarify that a liability is classified as non-current if the entity has, at the end of the reporting period, the substantial right to defer settlement of the liability during at least 12 months. The classification is not affected by the expectations of the entity or by events after the reporting date. The amendments include clarification of the classification requirements for debt that a company could settle converting it to equity.

The amendments only affect the presentation of liabilities as current and non-current in the statement of financial position, not the amount and timing of their recognition, or the related disclosures. However, they could lead to companies reclassifying certain current liabilities to non-current and vice versa. This could affect compliance with covenants in the debt agreements of companies.

These amendments are applicable retroactively beginning on January 1, 2023. In response to the COVID-19 pandemic, in July 2020 the IASB extended its mandatory effective date established initially for January 1, 2022 by a year in order to provide companies more time to implement any change in classification resulting from these amendments. Early application is permitted.

Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements.

● Amendments to IAS 1 and IFRS Practice Statement 2: “Disclosure of Accounting Policies”

On February 12, 2021, the IASB issued limited-scope amendments to IAS 1 “Presentation of Financial Statements” and IFRS Practice Statement No. 2 “Making Materiality Judgements”. This related to the final stage of its materiality improvement work, in order to help entities with their accounting policy disclosures. The aim was to provide more useful information to investors and other primary users of the financial statements.

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Amendments to IAS 1 require entities to disclose their material accounting policies rather than their significant accounting policies. The amendments to IFRS Statement of Practice No. 2 provide guidance on how to apply the concept of materiality to accounting policy disclosures.

The amendments are effective for annual periods beginning on or after January 1, 2023. Early application is permitted.  

Management is assessing the potential impact of the application of these amendments on the Group’s consolidated financial statements.

● Amendments to IAS 8: Definition of Accounting Estimates

On February 12, 2021, the IASB issued limited-scope amendments to IAS 8 “Accounting Policies, Changes to Accounting Estimates and Errors”. The aim was to clarify how companies should distinguish between changes to accounting policies and accounting estimates, in order to reduce diversity in practice.

This distinction is important because accounting estimate changes only apply prospectively to future transactions and other future events. In addition, accounting policy changes generally apply retrospectively to past transactions and other past events.

The amendments are effective for annual periods beginning on or after January 1, 2023, and will be applied prospectively to changes to estimates and accounting policies that occur from the beginning of the first year in which the entity applies the amendments. Early application is permitted.

Management is assessing the potential impact of the application of these amendments on the Group’s consolidated financial statements.

● Amendments to IAS 12: Deferred Tax related to Assets and Liabilities arising from a Single Transaction

On May 7, 2021, the IASB issued specific amendments to IAS 12 “Income Taxes”, with the aim of clarifying how companies should account for deferred taxes on transactions, such as leases and decommissioning obligations.

In certain circumstances, companies are exempt from recognizing deferred taxes when they recognize assets or liabilities for the first time. Previously, there was some uncertainty about whether the exemption applied to transactions such as leases and decommissioning obligations, transactions for which companies recognize both an asset and a liability. The amendments clarify that the exemption is not applicable to these transactions and companies are required to recognize deferred taxes on such transactions.

The amendments are effective for annual periods beginning on or after January 1, 2023. Early application is permitted.

Management is assessing the potential impact of the application of these amendments on the Group’s Consolidated Financial Statements.

c) Reclassification to consolidated statements of comprehensive income

The Group decided to reclassify from finance income to operating income the indexation of certain financial assets related to the concession contracts of the electricity distribution subsidiaries in Brazil. These financial assets represent the value to be recovered at the end of the related concessions (indemnification amount).

As a result of such reclassification, the Group retrospectively reclassified in the consolidated statements of comprehensive income the amounts of ThUS$ 99,071 and ThUS$ 73,345 from finance income to operating

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income for the years ended December 31, 2020 and 2019, respectively. These reclassifications, the amount of which is not significant, did not modify total assets, equity, profit for the year and cash flows previously reported by the Group.

For more information regarding the recognition policies of this kind of financial assets, as well as their associated values, see Note 3.d.1, Note 7(2) and Note 27.

For comparability purposes, the reclassifications are presented below:

	12-31-2020			12-31-2019
Consolidated Statements of Comprehensive Income, by Nature	Amounts previously reported	Reclassification	Amounts as revised	Amounts previously reported	Reclassification	Amounts as revised
STATEMENTS OF PROFIT (LOSS)	ThUS$		ThUS$	ThUS$		ThUS$
Revenue	11,238,976	—	11,238,976	13,053,376	—	13,053,376
Other income, by nature	953,698	99,071	1,052,769	1,260,736	73,345	1,334,081
Revenues and Other income, by nature	12,192,674	99,071	12,291,745	14,314,112	73,345	14,387,457
Raw materials and consumables used	(7,555,915)	—	(7,555,915)	(8,541,023)	—	(8,541,023)
Contribution Margin	4,636,759	99,071	4,735,830	5,773,089	73,345	5,846,434
Other work performed by the entity and capitalized	147,151	—	147,151	181,565	—	181,565
Employee benefit expenses	(565,046)	—	(565,046)	(809,753)	—	(809,753)
Depreciation and amortization expenses	(858,099)	—	(858,099)	(948,330)	—	(948,330)
Impairment (loss) reversal recognized in profit or loss	—	—	—	2,126	—	2,126
Impairment (loss) impairment gain and reversal of impairment loss determined in accordance with IFRS 9	(242,372)	—	(242,372)	(279,125)	—	(279,125)
Other expense, by nature	(1,065,278)	—	(1,065,278)	(1,150,709)	—	(1,150,709)
Operating Income	2,053,115	99,071	2,152,186	2,768,863	73,345	2,842,208
Other gains (losses)	4,671	—	4,671	14,196	—	14,196
Finance income	321,477	(99,071)	222,406	449,661	(73,345)	376,316
Finance costs	(768,453)	—	(768,453)	(1,088,631)	—	(1,088,631)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	3,133	—	3,133	583	—	583
Foreign currency translation differences	57,171	—	57,171	136,960	—	136,960
Gains (losses) from indexed assets and liabilities	76,698	—	76,698	124,477	—	124,477
Profit (loss) before taxes	1,747,812	—	1,747,812	2,406,109	—	2,406,109
Income tax expense	(566,560)	—	(566,560)	(236,346)	—	(236,346)
PROFIT (LOSS)	1,181,252	—	1,181,252	2,169,763	—	2,169,763

 ​

2.3. Responsibility for the information, judgments and estimates provided

The Company’s Board of Directors is responsible for the information contained in these consolidated financial statements and expressly states that all IFRS principles and standards have been fully implemented.

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In preparing the consolidated financial statements, certain judgments and estimates made by the Group’s management have been used to quantify some of the assets, liabilities, revenue, expenses and commitments recognized.

The most significant areas where critical judgment was required are:

- In a service concession agreement, determination of whether a grantor controls or regulates what services the operator must provide, to whom and at what price, are critical factors for the application of IFRIC 12 “Service Concession Arrangements” (see Note 3.d.1).

- The identification of Cash Generating Units (CGU) for impairment testing (see Note 3.e).

- The hierarchy of information used to measure assets and liabilities at fair value (see Note 3.h).

- The determination of the Group’s functional currency (see Note 2.8).

- Application of the revenue recognition model in accordance with IFRS 15 (see Note 3.q).

The estimates refer basically to:

- The valuations performed to determine the existence of impairment losses in non-financial assets and goodwill (see Note 3.e).

- The assumptions used to calculate the actuarial liabilities and obligations with employees, such as discount rates, mortality tables, salary increases, etc. (see Notes 3.m.1 and 25).

- The useful lives of property, plant and equipment and intangible assets (see Notes 3.a and 3.d).

- The assumptions used to calculate the fair value of financial instruments (see Notes 3.h and 22).

- The energy supplied to customer whose meters have not yet been read (see Note 3.q).

- Certain assumptions inherent in the electricity system affecting transactions with other companies, such as production, customer billings, energy consumption, that allow for estimation of electricity system settlements that occur on the corresponding final settlement dates, but that are pending as of the date of issuance of the consolidated financial statements and could affect the balances of assets, liabilities, income and expenses recognized in the financial statements (see Appendix 3.2).

- The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 3.m).

- Future disbursements for closure of facilities and restoration of land, as well as associated discount rates to be used (see Note 3.a).

- The tax results of the different Group subsidiaries that will be reported to the respective tax authorities in the future, and other estimates have been used as a basis for recording the different income tax related balances in these consolidated financial statements (see Note 3.p).

- The fair value of assets acquired, and liabilities assumed, and any pre-existing interest in an entity acquired in a business combination.

- Determination of expected credit losses on financial assets (see Note 3.g.3).

- In the measurement of lease liabilities, determination of the lease term of contracts with renewal options, as well as the rates to be used to discount lease payments (see Note 3.f).

Regarding the COVID-19 pandemic, the degree of uncertainty generated in the macroeconomic and financial environment in which the Group operates could affect the valuations and estimates made by Management to determine the carrying amounts of the more volatile assets and liabilities. As of December 31, 2021, according to the information available and considering a scenario in constant evolution, the main areas that required Management to use their judgment and make estimates were the following: i) measurement of expected credit losses on financial assets; ii) determination of impairment losses on non-financial assets; and iii) measurement of employee benefits, including actuarial assumptions.

Although these judgments and estimates have been based on the best information available as of the date of issuance of these consolidated financial statements, future events may occur that would require a change (increase or decrease) to these judgments and estimates in subsequent periods. This change would be made prospectively, recognizing the effects of this change in judgment or estimation in the related future consolidated financial statements.

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2.4. Subsidiaries

Subsidiaries are defined as those entities controlled either, directly or indirectly by Enel Américas. Control is exercised if and only if the following conditions are met: the Company has i) power over the subsidiary; ii) exposure, or rights to variable returns from these entities; and iii) the ability to use its power to influence the amount of these returns.

Enel Américas has power over its subsidiaries when it holds the majority of the substantive voting rights or, should that not be the case, when it has rights granting the practical ability to direct the entities’ relevant activities, i.e., the activities that significantly affect the returns from the subsidiary.

The Group will reassess whether or not it controls a subsidiary if facts and circumstances indicate that there are changes to one or more of the control elements listed above.

Subsidiaries are consolidated as described in Note 2.7.

Appendix N° 1 to these Consolidated Financial Statements, entitled “Companies from the Enel Américas Group”, describes the Company’s relationships with each of its subsidiaries.

2.4.1. Changes in the scope of consolidation

2021

- On January 20, 2021, the companies Fontibon ZE SAS and USME ZE SAS were incorporated in Colombia. These companies are 100% owned by the Company’s subsidiary Bogotá ZE SAS. The main purpose of these companies is to perform any activities related to electric mobility and public transport in Colombia and abroad.

- On April 1, 2021, EGP Américas SpA (hereinafter “EGP Américas”) merged with Enel Américas, which acquired all the assets and liabilities of EGP Américas, including the non-conventional renewable energy generation business and assets that EGP Américas owned in Central and South America (except Chile). As a consequence, all the shareholders and equity of EGP Américas were incorporated into Enel Américas, and EGP Américas was dissolved without liquidation (see Note 5).

- On November 4, 2021, Enel Green Power Brasil Participacoes Ltda. merged with Enel Brasil S.A., with the latter becoming the legal successor company (see Note 5).

- During the second half of 2021, the Company’s subsidiary Enel Brasil acquired 100% interests in the companies Enel Green Power Lagoa do Sol 08 S.A., Enel Green Power Lagoa do Sol 09 S.A., Fazenda Aroeira Empreendimento de Energia Ltda., Enel Green Power Nova Olinda 01 S.A., Enel Green Power Nova Olinda 07 S.A., Enel Green Power Nova Olinda 05 S.A., Enel Green Power Nova Olinda 09 S.A., Enel Green Power Nova Olinda 04 S.A., Enel Green Power Nova Olinda 02 S.A. and Enel Green Power Nova Olinda 03 S.A., for the purpose of developing renewable energy projects.

- During the second half of 2021, the Company’s subsidiary Enel Green Power Colombia S.A.S. ESP acquired 100% interests in the companies Guayepo Solar S.A.S., Latamsolar Fotovoltaica Fundación S.A.S, and Atlántico Photovoltaic S.A.S. ESP, for the purpose of developing renewable energy projects.

2020

- On September 22, 2020, the Company’s subsidiary Enel X Brasil S.A. acquired 51% of the share capital of Luz de Angra Energía S.A., whose corporate purpose is to perform works and services related to public lighting and signage in streets, ports and airports.

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- On October 22, 2020, Bogotá ZE SAS was incorporated, which is 100% owned by the Company’s subsidiary Enel X Colombia S.A.S. The new company is engaged in performing any acts related to sustainable electromobility in Colombia and abroad.

2.4.2. Consolidated companies with an economic equity interest of less than 50%

Although the Group has an interest of less than 50% in Codensa S.A. E.S.P. and Emgesa S.A. E.S.P. in Colombia, representing 48.3% and 48.48%, respectively, these companies are considered to be “subsidiaries” since Enel Américas exercises control over them by virtue of a shareholders’ agreement or as a result of its share structure, composition and classes. In this respect Enel Américas has 57.15% and 56.43% of the voting shares of Codensa S.A. E.S.P., and Emgesa S.A. E.S.P., respectively.

2.5. Investments in associates

Associates are those entities over which Enel Américas, either directly or indirectly, exercises significant influence.

Significant influence is the power to participate in the decisions related to the financial and operating policy of the associate but without having control or joint control over those policies. In assessing significant influence, the Group takes into account the existence and effect of currently exercisable voting rights or convertible rights at the end of each reporting period, including currently exercisable voting rights held by the Company or other entities. In general, significant influence is presumed to be present in those cases in which the Group has more than 20% of the voting power of the investee.

Associates are accounted for in the consolidated financial statements using the equity method of accounting as described in Note 3.i.

The detail of the companies that qualify as associates is the following:

			Functional	% Ownership as of 12-31-2021			% Ownership as of 12-31-2020
Taxpayer ID No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Yacylec S.A	Argentina	Argentine peso	33.33%	—	33.33%	33.33%	—	33.33%
Foreign	Central Vuelta Obligado S.A.	Argentina	Argentine peso	—	40.90%	40.90%	—	40.90%	40.90%

2.6. Joint arrangements

Joint arrangements are defined as those entities in which the Group exercises control under an agreement with other shareholders and jointly with them, i.e., when decisions on the entities’ relevant activities require the unanimous consent of the parties sharing control.

Depending on the rights and obligations of the participants, joint agreements are classified as:

- Joint venture: an agreement whereby the parties exercising joint control have rights to the entity’s net assets. Joint ventures are included in the consolidated financial statements using the equity method of accounting, as described in Note 3.i.

- Joint operation: an agreement whereby the parties exercising joint control have rights to the assets and obligations with respect to the liabilities relating to the arrangement. Joint operations are included in the consolidated financial statements recognizing the proportional interest in the assets and liabilities impacted by such operation.  

In determining the type of joint arrangement in which it is involved, the Group’s Management assesses its rights and obligations arising from the arrangement by considering the structure and legal form of the arrangement, the terms agreed by the parties in the contractual arrangement and, when relevant, other facts and circumstances. If facts and circumstances change, the Group reassesses whether the type of joint arrangement in which it is involved has changed.

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The detail of companies classified as joint ventures is as follows:

				% Ownership as of			% Ownership as of
Taxpayer ID No.	Company	Country	Functional Currency	12-31-2021			12-31-2020
				Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Sacme S.A.	Argentina	Argentine Peso	-	50.00%	50.00%	-	50.00%	50.00%

The Company does not have any joint agreements classified as joint operations.

2.7. Basis of consolidation and business combinations

The subsidiaries are consolidated and all their assets, liabilities, revenues, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations of intra-group transactions have been made.

The comprehensive income from subsidiaries is included in the consolidated statement of comprehensive income from the date when the Parent Company obtains control of the subsidiary until the date on which it loses control of the subsidiary.

The Group records its business combinations using the acquisition method when the set of activities and assets acquired meet the definition of a business, and control is transferred to the Group. To be considered a business, a set of activities and assets acquired must include, as a minimum, an input and a substantive process applied to it which, as a whole, significantly contribute to the capacity to create products. IFRS 3 offers the option to apply a “concentration test” as a simplified evaluation of whether or not an acquired set of activities and assets is a business. The concentration test is positive if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets.

The operations of the Parent Company and its subsidiaries have been consolidated under the following basic principles:  

1. At the date the parent obtains control, the subsidiary’s assets acquired, and its liabilities assumed are recorded at fair value, except for certain assets and liabilities that are recorded using valuation principles established in other IFRS standards. If the fair value of the consideration transferred plus the fair value of any non-controlling interests exceeds the fair value of the net assets acquired, this difference is recorded as goodwill. In the case of a bargain purchase, the resulting gain is recognized in profit or loss after reassessing whether all of the assets acquired, and the liabilities assumed have been properly identified and following a review of the procedures used to measure the fair value of these amounts.

For each business combination, IFRS allow valuation of the non-controlling interests in the acquiree on the date of acquisition: i) at fair value; or ii) for the proportional ownership of the identifiable net assets of the acquiree, with the latter being the methodology that the Group has systematically applied to its business combinations.

If the fair value of all assets acquired and liabilities assumed at the acquisition date has not been completed, the Group reports the provisional values accounted for in the business combination. During the measurement period, which shall not exceed one year from the acquisition date, the provisional values recognized will be adjusted retrospectively as if the accounting for the business combination had been completed at the acquisition date, and also additional assets or liabilities will be recognized to reflect new information obtained about events and circumstances that existed on the acquisition date, but which were unknown to Management at that time. Comparative information for prior periods presented in the financial statements is revised as needed, including making any change in depreciation, amortization or other income effects recognized in completing the initial accounting.

F-29

For business combinations achieved in stages, the Company measures at fair value the participation previously held in the equity of the acquiree on the date of acquisition and the resulting gain or loss, if any, is recognized in profit or loss of the period.

2. Non-controlling interests in equity and in the comprehensive income of the consolidated subsidiaries are presented, respectively, under the line items “Total Equity: Non-controlling interests” in the consolidated statement of financial position and “Profit (loss) attributable to non-controlling interests” and “Comprehensive income attributable to non-controlling interests” in the consolidated statement of comprehensive income.

3. Balances and transactions between consolidated companies have been fully eliminated on consolidation.

4. Changes in the ownership interests in subsidiaries that do not result in the Group obtaining or losing control are recognized as equity transactions. The carrying amounts of the controlling and non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received is recognized directly in equity attributable to shareholders of the Parent Company.

5. Business combinations under common control are accounted for using the “pooling of interest” method. Under this method, the assets and liabilities involved in the transaction remain reflected at the same carrying amounts at which they were recorded in the ultimate parent company, although subsequent accounting adjustments may be needed to align the accounting policies of the companies involved. The Group does not apply a retrospective item of business combinations under common control.

Any difference between assets and liabilities contributed to the consolidation and the consideration paid is recorded directly in equity, as a debit or credit to “Other reserves.”

2.8. Functional Currency

The functional currency of Enel Américas is the United States Dollar (US$), as is the presentation currency of the Group’s consolidated financial statements.

The functional currency has been determined, considering the economic environment in which the Company operates. This conclusion is based on the fact that the US$ is the currency that fundamentally influences its financing, capital issuance and cash and cash equivalent activities. Accordingly, the US$ reflects the underlying transactions, events and conditions for Enel Américas.

Any information presented in US$ has been rounded to the closest thousand (ThUS$) or million (MUS$), unless indicated otherwise.

2.9. Conversion of financial statements denominated in foreign currency

Conversion of the financial statements of the Group companies that have functional currencies different than US$, and do not operate in hyperinflationary economies, is carried out as follows:

a. Assets and liabilities, using the exchange rate prevailing at the closing date of the financial statements.

b. Comprehensive income statements using the average exchange rate for the period (unless this average is not a reasonable approximation of the cumulative effect of the exchange rate existing on the transaction dates, in which case the exchange rate on the date of each transaction is used).

c. Equity is maintained at the historical exchange rate on the date of its acquisition or contribution, and at the average exchange rate as of the date of generation for retained earnings.

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d. Foreign currency translation differences generated in the conversion of the financial statements are recorded under “Foreign currency translation gains (losses)” in Other comprehensive income in the consolidated statement of comprehensive income (see Note 26.2).

The financial statements of subsidiaries whose functional currency is that of a hyperinflationary economy, are first adjusted for inflation, recording any gain or loss in the net monetary position in profit or loss. Subsequently, all items (assets, liabilities, equity items, expenses and revenue) are converted at the exchange rate prevailing at the closing date of the most recent statement of financial position. Changes in the Company’s net investment in the subsidiary operating in a hyperinflationary economy, arising from the application of the restatement/conversion method, are recorded as follows: (i) the effect of restatement due to inflation is recognized directly in Equity, under the "Other reserves" account; and (ii) the effect of foreign currency translation is recognized in Gain (losses) from foreign currency translation, in the consolidated statements of comprehensive income: Other comprehensive income.

Argentine Hyperinflation

Beginning on July 2018, the Argentine economy has been considered to be hyperinflationary in accordance with the criteria established in IAS 29 “Financial Reporting in Hyperinflationary Economies”. This determination was made on the basis of a number of qualitative and quantitative criteria, especially the presence of accumulated inflation in excess of 100% during the three previous years.

In accordance with IAS 29, the financial statements of investees in Argentina have been restated retrospectively, applying the general price index at historical cost, in order to reflect changes in the purchasing power of the Argentine peso, as of the closing date of these consolidated financial statements.

Non-monetary assets and liabilities were restated from February 2003, the last date on which an inflation adjustment was applied for accounting purposes in Argentina. Within this context, note that the Group carried out its transition to IFRS on January 1, 2004, and applied the deemed cost exception to property, plant and equipment.

For consolidation purposes in Enel Américas and as a result of the application of IAS 29, the results of our subsidiaries in Argentina were converted at the prevailing period-closing exchange rate (ARS/US$), in accordance with IAS 21 “Effects of Changes in Foreign Exchange Rates”, when dealing with a hyperinflationary economy. Previously, the profit or loss of Argentine subsidiaries were converted using the average exchange rate for the period, as used for the other subsidiaries operating in other countries whose economies are not considered to be hyperinflationary.

The general price indexes used at the end of the reporting periods are as follows:

	General price index
From January to December 2019	53.64%
From January to December 2020	36.13%
From January to December 2021	50.95%

The effects of the application of this standard on these consolidated financial statements are detailed in Note 32.

Exchange rates

The exchange rates used to convert the financial statements of the different foreign subsidiaries are detailed as follows (local currency versus the US$):

	12-31-2021		12-31-2020		12-31-2019
Currency	Closing Date	Average	Closing Date	Average	Average
Argentine peso	102.72	102.69	84.15	84.07	59.88
Brazilian real	5.58	5.39	5.20	5.16	3.94
Peruvian sol	4.00	3.88	3.62	3.50	3.34
Colombian peso	3,981.16	3,743.86	3,432.50	3,693.52	3,281.39

F-31

Note: The functional currency of the Group’s subsidiaries in Central America is the United States Dollar (US $).

3. ACCOUNTING POLICIES

The main accounting policies used in preparing the accompanying consolidated financial statements are the following:

a) Property, plant and equipment

Property, plant and equipment are generally measured at acquisition cost, net of accumulated depreciation and any impairment losses experienced. In addition to the price paid to acquire each item, the cost also includes, the following concepts, where applicable:

● Finance costs accrued during the construction period that are directly attributable to the acquisition, construction, or production of qualifying assets, which require a substantial period of time before being ready for use (e.g., electricity generation or distribution facilities). The Group defines “substantial period” as a period exceeding twelve months. The interest rate used is that of the specific financing or, if none exists, the weighted average financing rate of the company making the investment (see Note 16.b.1).

● Employee expenses directly related to construction in progress (see Note 16.b.2).

● Future disbursements that the Group will have to make to close its facilities are added to the value of the asset at fair value, recognizing the related provision for dismantling or restoration. The Group reviews its estimate of these future disbursements on an annual basis, increasing or decreasing the value of the asset based on the results of this estimate (see Note 24).

Assets under construction are transferred to operating assets once the testing period has been completed and they are available for use, at which time depreciation begins.

Expansion, modernization or improvement costs that represent an increase in productivity, capacity or efficiency, or a longer useful life are capitalized as an increase in the cost of the related assets.

The replacement or overhaul of entire components that increase the asset’s useful life or economic capacity are recorded as an increase in cost of the related assets, derecognizing the replaced or overhauled components.

Expenditures for periodic maintenance and repair are recognized directly as an expense for the year in which they are incurred.

Property, plant and equipment, net of its residual value, is depreciated by distributing the cost of the different items that comprise it on a straight-line basis over its estimated useful life, which is the period during which the Group expects to use the assets. Useful life estimates and residual values are reviewed on an annual basis and if appropriate adjusted prospectively.

In addition, the Group recognizes right-of-use assets for leases relating to property, plant and equipment in accordance with the criterion established in Note 3.f.

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The following are the main categories of property, plant and equipment with their related estimated useful lives:

Classes of property, plant and equipment	Years of estimated useful life
Buildings	10 – 85
Plant and equipment	10 – 85
IT equipment	3 – 15
Fixtures and fittings	3 – 75
Motor vehicles	5 – 20

In addition, for further information, the following is a more detailed breakdown of the plant and equipment classes:

Classes of property, plant and equipment	Years of estimated useful life
Generating plant and equipment:
Hydroelectric plants
Civil engineering works	10 – 85
Electromechanical equipment	10 – 60
Coal/Fuel power plants	10 – 40
Combined cycle power plants	10 – 50
Distribution plant and equipment:
High-voltage network	15 – 50
Low- and medium-voltage network	30 – 50
Measuring and remote control equipment	10 – 30
Primary substations	20 – 40

Land is not depreciated since it has an indefinite useful life, unless it relates to a right-of-use asset in which case it is depreciated over the term of the lease.

Regarding the administrative concessions held by the Group’s electric companies, the following table lists the remaining periods until expiration of the concessions that do not have an indefinite term:

Concession holder and operator	Country	Year concession started	Concession term	Remaining period to expiration
Empresa Distribuidora Sur S.A. - Edesur (Distribution)	Argentina	1992	95 years	66 years
Enel Generación El Chocón S.A. (Generation) (*)	Argentina	1993	30 years	2 years
Transportadora de Energía S.A. (Transmission)	Argentina	2002	85 years	66 years
Compañía de Transmisión del Mercosur S.A. (Transmission)	Argentina	2000	87 years	66 years
EGP Cachoeira Dourada S.A. (Generation)	Brazil	1997	30 years	6 years
Enel Generación Fortaleza S.A (Generation)	Brazil	2001	30 years	10 years
Enel CIEN S.A. (Garabi I) (Transmission) (**)	Brazil	2000	22 years	0.6 years
Enel CIEN S.A. (Garabi II) (Transmission) (**)	Brazil	2002	20 years	0.6 years

(*) The Chocón Complex Concession Contract (Chocón and Arroyito plants) expires on August 11, 2023. This contract does not foresee any extension or new call for proposals, but rather the restitution to the licensor (Argentine State). However, some proceedings are being carried out to achieve a temporary extension.

(**) The main assets of our subsidiary Enel CIEN are the Garabi I and Garabi II energy interconnection systems, which through two frequency conversion stations and 2,200 MW transmission lines, transport energy between Brazil and Argentina. In June 2020, the Ministry of Mines and Energy of Brazil enacted an ordinance that allows Enel CIEN to continue operating the Garabi I line after the end of the concession on June 20, 2020, approving its term to correspond with the concession of the Garabi II line, up to July 31, 2022. During 2022, there will be a new tender for the operation of both lines, and Enel CIEN has the possibility of participating in such process. If the concession is not renewed, Enel CIEN will recover the carrying amount of the underlying assets.

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To the extent that the Group recognizes the assets as Property, plant and equipment, these are amortized over their economic life or the concession term, whichever is shorter, when the economic benefit from the asset is limited to its use during the concession term.

Any required investment, improvement or replacement made by the Group is considered in the impairment test to Property, plant, and equipment as a future contractual cash outflow that is necessary to obtain future cash inflows.

The Group’s Management analyzed the specific contract terms of each of the aforementioned concessions, which vary depending on the by country, business activity and jurisdiction, and concluded that, with the exception of Enel CIEN, there are no determining factors indicating that the grantor, which in every case is a government entity, controls the infrastructure and, at the same time, can continuously set the price to be charged for the services. These requirements are essential for applying IFRIC 12, Service Concession Arrangements, an interpretation that establishes how to recognize and measure certain types of concessions (see Note 3.d.1).

On April 19, 2011, the Company’s subsidiary Enel CIEN successfully completed its change in business model. Under the new agreement, the Brazilian government continues to control the infrastructure, but Enel CIEN receives fixed payments, which places it at an equal level with a public transmission concession (with regulated prices). Under this business model, its concessions fall within the scope of IFRIC 12; however, the infrastructure has not been derecognized due to the fact that Enel CIEN has not substantially transferred the significant risks and benefits to the Brazilian government.

An item of property, plant and equipment is derecognized when it is sold or otherwise disposed of, or when no future economic benefits are expected from its use, sale or other disposal.

Gains or losses arising from the sale or disposal of items of property, plant and equipment are recognized as “Other gains (losses)” in the statement of comprehensive income and calculated by deducting the amount received for the sale from the net carrying amount of the asset and the selling value.

b) Investment property

“Investment property” basically includes land and buildings that are kept for the purpose of obtaining gains from future sales or lease arrangements.

Investment property is measured at acquisition cost, net of accumulated depreciation and any impairment losses experienced. Investment property, excluding land, is depreciated by distributing the cost of the several elements that comprise it on a straight-line basis over the years of useful life.

An investment property is derecognized on disposal, or when no future economic benefits are expected from use or disposal.

Gains or losses arising from the sale or disposal of items of investment property are recognized as “Other gains (losses)” in the statement of comprehensive income and determined as the difference between the sales amount and the net carrying amount of the asset.

c) Goodwill

Goodwill arising from business combinations, and reflected upon consolidation, represents the excess value of the consideration paid plus the amount of any non-controlling interests over the Group’s share of the net value of the assets acquired and liabilities assumed, measured at fair value at the acquisition date. If the accounting for a business combination is completed within the following year after the acquisition date, and thus the goodwill determination as well, the entity recognizes the related adjustments to the provisional amounts as if the accounting for the business combination had been completed at the acquisition date. If the accounting for a business combination is completed within the following year after the acquisition date, and thus the goodwill determination as well, the entity recognizes

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the related adjustments to the provisional amounts as if the accounting for the business combination had been completed at the acquisition date (see Note 2.7.1).

Goodwill arising from acquisition of companies with functional currencies other than the functional currency of the Parent is measured in the functional currency of the acquiree and translated to U.S. dollar using the exchange rate effective as of the date of the statement of financial position.

Goodwill is not amortized; instead, at the end of each reporting period or when there are indicators that an impairment might have occurred, the Group estimates whether any impairment loss has reduced its recoverable amount to an amount less than the carrying amount and, if so, an impairment loss is immediately recognized in profit or loss (see Note 3.e).

d) Intangible assets other than goodwill

Intangible assets are initially recognized at their acquisition cost or production cost, and are subsequently measured at their cost, net of their accumulated amortization and impairment losses experienced.

Intangible assets are amortized on a straight line basis during their useful lives, starting from the date when they are ready for use, except for those with an indefinite useful life, which are not amortized. As of December 31, 2021 and 2020, there are no significant amounts in intangible assets with an indefinite useful life.

The criteria for recognizing these assets’ impairment losses and, if applicable, recovery of impairment losses recorded in previous periods are explained in Note e) below.

An intangible asset is derecognized when it is sold or otherwise disposed of, or when no future economic benefits are expected from its use, sale or other disposal.

Gains or losses arising from sales of intangible assets are recognized in profit or loss for the period and determined as the difference between the amount of the sale and the carrying amount of the asset.

d.1) Concessions

Public-to-private service concession agreements are recognized according to IFRIC 12: Service Concession Arrangements. This accounting interpretation applies if:

a) The grantor controls or regulates what services the operator should provide with the infrastructure, to whom it must provide them, and at what price; and,

b) The grantor controls – through ownership, beneficial entitlement, or otherwise – any significant residual interest in the infrastructure at the end of the term of the arrangement.

If both of the above conditions are met simultaneously, the consideration received by the Group for the constructed infrastructure is initially recognized at its fair value, as either:

-An intangible asset when the Group receives the right to charge users of the public service, as long as these charges are conditional on the degree to which the service is used;

-A financial asset when the Group has an unconditional contractual right to receive cash or another financial asset directly from the grantor or from a third party.

However, both types of considerations are classified as a contract asset during the construction or improvement period, in accordance with IFRS 15 (see Note 8).

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The Group recognizes the contractual obligations assumed for maintenance of the infrastructure during its use, or for its return to the grantor at the end of the concession agreement within the conditions specified in the agreement, as long as it does not involve an activity that generates income, in accordance with the Group’s accounting policy to recognize provisions (see Note 3.m).

Finance costs attributable to the concession arrangements are capitalized based on the criteria established in a) above, provided that the operator has a contractual right to receive an intangible asset.

The Company’s subsidiaries that have recognized an intangible asset and/or a financial asset from their service concession arrangements are the following:

Concession holder and operator	Country	Year concession started	Concession term	Remaining period to expiration
Enel Distribución Río S.A. (Distribution) (*)	Brazil	1996	30 years	5 years
Enel Distribución Ceará S.A. (Distribution) (*)	Brazil	1997	30 years	6 years
Enel Distribución Goiás S.A. (Distribution) (*)	Brazil	2015	30 years	23 years
Enel Green Power Proyectos I (Volta Grande) (Generation) (**)	Brazil	2017	30 years	26 years
Enel Distribución Sao Paulo S.A. (Distribution) (*)	Brazil	1998	30 years	7 years
P.H. Chucas S.A. (Generation) (*)	Costa Rica	2011	20 years	10 years

(*) Because part of the rights acquired by these subsidiaries are unconditional an intangible asset and financial asset at fair value through profit and loss have been recognized for the concession (See Notes 3.g.1 and 7).

(**) Because all of the rights acquired by this subsidiary are unconditional, only a financial asset measured at amortized cost has been recognized for this concession (see Notes 3.g.1 and 7).

At the end of each concession period, this can be renewed at the discretion of the granting authority, otherwise all assets and facilities will be returned to the government or its assignee, upon reimbursement for investments made and not yet amortized.

d.2) Research and development expenses

The Group recognizes the costs incurred in a project’s development phase as intangible assets in the statement of financial position as long as the project’s technical feasibility and future economic benefits have been demonstrated.

Research costs are recorded as an expense in the consolidated statement of comprehensive income in the period in which they are incurred.

d.3) Other intangible assets

Other intangible assets correspond to computer software, water rights, and easements. They are initially recognized at acquisition or production cost and are subsequently measured at cost less accumulated amortization and impairment losses, if any.

Computer software is amortized (on average) over five years. Certain easements and water rights have indefinite useful lives and are therefore not amortized, while others have useful lives ranging from 40 to 60 years, depending on their characteristics, and they are amortized over that term.

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e) Impairment of non-financial assets

During the period, and mainly at the end of each reporting period, the Group evaluates whether there is any indication that an asset has been impaired (or reversed of impairment). If any such indication exists, the Group estimates the recoverable amount of that asset to determine the amount of the impairment loss. For identifiable assets that do not generate cash flows independently, the Group estimates the recoverable amount of the Cash Generating Unit (CGU) to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

Notwithstanding the preceding paragraph, for CGUs to which goodwill or intangible assets with indefinite useful life have been allocated, a recoverability analysis is performed routinely at each year-end.

The criteria used to identify the CGUs are based, in line with Management’s strategic and operating vision, within the specific characteristics of the business, the operating rules and regulations of the market in which the Group operates and corporate organization.

Recoverable amount is the higher of fair value less costs of disposal and value in use, which is defined as the present value of the estimated future cash flows. In order to calculate the recoverable amount of Property, plant, and equipment, as well as of goodwill and intangible assets, the Group uses value in use criteria in practically all cases.

To estimate value in use, the Group prepares future pre-tax cash flow forecasts based on the most recent budgets available. These budgets include Management’s best estimates of a CGU’s revenue and costs using sector forecasts, past experience and future expectations.  

In general, these projections cover the next three years, estimating cash flows for subsequent years by applying reasonable growth rates which, in no case, are increasing rates nor exceed the average long-term growth rates for the particular sector and country in which the Group operates. The growth rates used to extrapolate the projections as of December 31, 2021 and 2020 were the following:

		12-31-2021		12-31-2020
Country	Currency	Minimum	Maximum	Minimum	Maximum
Argentina	Argentine peso	10.0%		10.1%	12.8%
Brazil	Brazilian real	3.0%		3.5%
Peru	Peruvian sol	2.5%		2.5%
Colombia	Colombian peso	3.0%		3.0%
Costa Rica	U.S. Dollar	2.0%		0.0%
Guatemala	U.S. Dollar	2.0%		0.0%
Panamá	U.S. Dollar	2.0%		0.0%

Future cash flows are discounted to calculate their present value at a pre-tax rate that covers the cost of capital for the business activity and the geographic area in which it is being carried out. The time value of money and risk premiums generally used among analysts for the business activity and the geographic zone are taken into account to calculate the pre-tax rate.

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The following are the pre-tax discount rates applied as of December 31, 2021 and 2020 expressed in nominal terms:

		December 31, 2021		December 31, 2020
Country	Currency	Minimum	Maximum	Minimum	Maximum
Argentina	Argentine peso	36.6%	66.1%	35.8%	63.4%
Brazil	Brazilian real	9.3%	60.5%	9.6%	40.2%
Peru	Peruvian sol	6.7%	11.9%	7.4%	11.1%
Colombia	Colombian peso	8.5%	11.3%	8.7%	10.5%
Costa Rica	U.S. Dollar	9.0%	11.7%	0.0%	0.0%
Guatemala	U.S. Dollar	7.8%	8.6%	0.0%	0.0%
Panamá	U.S. Dollar	7.3%	11.1%	0.0%	0.0%

The pre-tax discount rates are calculated using the iterative method, by which a discount rate is determined, thereby ensuring that the value in use calculated with the pre-tax cash flows is equal to that which was calculated with the after-tax cash flows, discounted at the after-tax discount rate.

The Company’s approach to allocate value to each key assumption used to project cash flows, considers:

● Evolution of demand: the growth estimate has been calculated based on the projected increase in the Gross Domestic Product (GDP), in addition to other assumptions used by the Company regarding the evolution of consumption. For instance, the number of clients.

● Energy purchase and sale prices: based on specifically developed internal projection models. The price of the planned “pool” is estimated by considering a number of determining factors, such as the different technologies costs and productions and energy demand, among other items.

● Regulatory measures: an important part of the Company’s business is regulated and subject to extensive standards, which could undergo revisions, either as a result of new laws or the amendment of existing laws, and therefore the projections include adequate application of the current standards and those that are currently being developed, and those expected to be effective during the projected period. 

● Installed capacity: in the estimating of the Group’s installed capacity, the existing facilities are taken into account, as well as the plans for both increasing capacity and capacity closure. The investment plan is constantly updated based on the evolution of the business, quality of service regulations determined by the regulator and changes in the business development strategy adopted by management. In the field of generation, the investments necessary to maintain the installed capacity in adequate operating conditions are taken into account, in the distribution activity the investments for maintenance, improvement and strengthening of the network are considered.

● Hydrology and NCRE: the projections are made from historical series of meteorological conditions and projecting an average year, based on these.

● Fuel costs: to estimate fuel costs, existing supply contracts are taken into account and long-term projections of oil, gas or coal prices are made, based on forward markets and available analyst estimates.

● Fixed costs: these are projected considering the foreseen level of business activities, both in terms of the evolution of the workforce (considering salary raises in line with the CPI), and in term of other operating and maintenance costs, the level of projected inflation and long-term existing maintenance or other contracts. The efficiencies that the Group is adopting over time are also considered, such as those that arise from the initiatives for the digitalization for the internal processes.

● External sources: these are always considered to verify the assumptions related to the macroeconomic environment such as price evolution, GDP growth, demand, inflation, interest rates and exchange rates, among others.

Past experience has demonstrated the reliability of the Company’s forecasts, which allows it to base key assumptions on historical information. During 2021, the deviations observed with respect to the projections used to perform impairment testing as of December 31, 2020, were not significant and cash flows generated in 2021 remained in a reasonable variance range compared to those expected for that period.

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Regarding the non-conventional renewable energy generation assets that the Group owns in Central and South America included in the consolidation scope as of April 1, 2021 (see Note 5), Management concluded after a recoverability analysis that there are no indications of any impairment losses that could affect the Company’s profit or loss.

If the recoverable amount of the CGU is less than the net carrying amount of the asset, the related impairment loss is recognized for the difference, and charged to “Impairment loss (impairment reversals) recognized in profit or loss” in the consolidated statement of comprehensive income. The impairment is first allocated to the CGU’s goodwill carrying amount, if any, and then to the other assets comprising it, prorated on the basis of the carrying amount of each one, limited to the fair value less costs of disposal, or value in use, where no negative amount could be obtained.

Impairment losses recognized in prior periods for an asset other than goodwill are reversed, if and only if, there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If this is the case, the carrying amount of the asset is increased to its recoverable amount with a credit to profit or loss, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had 0 impairment loss been recognized for the asset. For goodwill, impairment losses are not reversed in subsequent periods.

f) Leases

In order to determine whether an arrangement is, or contains, a lease, the Company assesses the economic substance of the agreement, assessing whether the agreement conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Control is considered to exist if the customer has: i) the right to obtain substantially all the economic benefits arising from the use of an identified asset; and ii) the right to direct the use of the asset.

f.1) Lessee

When the Group acts as a lessee at the commencement of the lease (i.e. on the date on which the underlying asset is available for use) it records a right-of-use asset and a lease liability in the statement of financial position.

The Group initially recognizes right-of-use assets at cost. The cost of right-of-.use assets comprises: (i) the amount of the initial measurement of the lease liability; (ii) lease payments (made until the commencement date less lease incentives received), (iii) initial direct costs incurred; and (iv) the estimate of decommissioning or restoration costs.

Subsequently, the right-of-use asset is measured at cost, adjusted by any re measurement of the lease liability, less accumulated depreciation and accumulated impairment losses. A right-of-use asset is depreciated on the same terms as other similar depreciable assets, as long as there is reasonable certainty that the lessee will acquire ownership of the asset at the end of the lease. If no such certainty exists, the leased assets are depreciated over the shorter of the useful lives of the assets and their lease term. The same criteria detailed in Note 3.e are applied to determine whether the right-of-use asset has become impaired.

The lease liability is initially measured at the present value of the lease payments, discounted at the Company’s incremental borrowing rate, if the interest rate implicit in the lease cannot be readily determined. The incremental borrowing rate is the interest rate that the company would have to pay to borrow over a similar term, and with similar security, the funds necessary to obtain an asset of similar value to the right-of-use asset in a similar economic environment. The Group determines its incremental borrowing rate using observable data (such as market interest rates) or by making specific estimates when there are no observable rates available (e.g., for subsidiaries that do not carry out financing transactions) or when they must be adjusted to reflect the terms and conditions of the lease (e.g., when the leases are not in the functional currency of the subsidiary).

Lease payments included in the measurement of liabilities comprise: i) fixed payments, less any lease incentive receivable; ii) variable lease payments that depend on an index or a rate; iii) residual value guarantees; iv) the exercise

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price of a purchase option, if the Group is it is reasonably certain to exercise that option; and v) penalties for terminating the lease, if any.

After the commencement date, the lease liability increases to reflect the accrual of interest and is reduced by the lease payments made. In addition, the carrying amount of the liability is remeasured if there is a change in the terms of the lease (changes in the lease term, in the amount of expected payments related to a residual value guarantee, in the evaluation of a purchase option or in an index or rate used to determine lease payments). Interest expense is recognized as finance cost and distributed over the years making up the lease period, so that a constant interest rate is obtained in each year on the outstanding balance of the lease liability. 

Short-term leases of one year or less or leases of low value assets are exempt from the application of the recognition criteria described above, with the payments associated with the lease recorded as an expense on a straight-line basis over the term of the lease.

Right-of-use assets and lease liabilities are presented separately from other assets and liabilities, respectively in the consolidated statement of financial position.

f.2) Lessor

When the Group acts as a lessor, it classifies at the commencement of the agreement whether the lease is an operating or finance lease, based on the substance of the transaction. Leases in which all the risks and rewards incidental to ownership of an underlying asset are substantially transferred are classified as finance leases. All other leases are classified as operating leases.

For finance leases, at the commencement date, the Company recognizes in its statement of financial position the assets held under finance leases and presents them as an account receivable, for an amount equal to the net investment in the lease, calculated as the sum of the present value of the lease payments and the present value of any accrued residual value, discounted at the interest rate implicit in the lease. Subsequently, finance income is recognized over the term of the lease, based on a model that reflects a constant rate of return on the net financial investment made in the lease.

For operating leases, lease payments are recognized as income on a straight-line basis, over the term of the lease unless another type of systematic basis of distribution is deemed more representative. The initial direct costs incurred in obtaining an operating lease are added to the carrying amount of the underlying asset and are recognized as expense throughout the lease period, applying the same basis as for rental income.

g) Financial instruments

Financial instruments are contracts that give rise to both a financial asset in one entity and a financial liability or equity instrument in another entity.

g.1) Financial assets other than derivatives

The Group classifies its non-derivative financial assets, whether permanent or temporary, excluding investments accounted for using the equity method (see Notes 3.i and 13) and non-current assets and disposal groups held for sale or distribution to owners (see Note 3.k), into three categories:

(i) Amortized cost:

This category includes the financial assets that meet the following conditions (i) the business model that supports the financial assets seeks to maintain such financial assets to obtain contractual cash flows, and (ii)

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the contractual terms of such financial assets give rise on specific dates to cash flows that are solely payments of principal and interest (SPPI criterion).

Financial assets that meet the conditions established in IFRS 9, to be valued at amortized cost in the Group are: cash equivalents, accounts receivable and, loans. Such assets are recorded at amortized cost, which is the initial fair value, less repayments of principal, plus uncollected accrued interest, calculated using the effective interest method.  

The effective interest method is a method for calculating the amortized cost of a financial asset or a financial liability (or a group of financial assets or financial liabilities) and allocating the finance income or finance costs throughout the relevant period. The effective interest rate is the discount rate that exactly matches the estimated cash flows to be received or paid over the expected useful life of the financial instrument (or when appropriate in a shorter period of time), with the net carrying amount of the financial asset or financial liability.

(ii) Financial Assets Recorded at Fair Value through Other Comprehensive Income:

This category includes the financial assets that the meet the following conditions: (i) they are classified in a business model, the purpose of which is to maintain the financial assets both to collect the contractual cash flows and to sell them, and (ii) the contractual conditions meet the SPPI criterion.

These financial assets are recognized in the consolidated statement of financial position at fair value when this can be determined reliably. For the holdings in unlisted companies or companies with low liquidity, it is usually not possible to determine the fair value reliably. Therefore, when this occurs, such holdings are valued at their acquisition cost or for a lower amount if there is evidence of their impairment.

Changes in fair value, net of their tax effect, are recorded in the consolidated statement of comprehensive income: Other comprehensive income, until the disposal of these financial assets, where the accumulated amount in this section is fully allocated to profit or loss for the period except for investments in equity instruments where the accumulated balance in other comprehensive income is never reclassified to profit or loss.

In the event that the fair value is lower than the acquisition cost, if there is objective evidence that the asset has suffered an impairment that cannot be considered as temporary, the difference is recorded directly in the loss for the period.

(iii) Financial Assets Recorded at Fair Value through Profit or Loss:

This category includes the trading portfolio of the financial assets that have been allocated as such upon their initial recognition and which are managed and assessed according to the fair value criterion, and the financial assets that do not meet the conditions to be classified in the two categories indicated above.

These are measured at fair value in the consolidated statement of financial position and any changes in value are recorded directly in profit or loss when they occur.

g.2) Cash and cash equivalents

This item within the consolidated statement of financial position includes cash and bank balances, time deposits, and other highly liquid investments (with original maturity of less than or equal to 90 days) that are readily convertible into cash and are subject to insignificant risk of changes in value.

g.3) Impairment of financial assets

Under IFRS 9, the Group applies an impairment model based on expected credit losses, based on the Group’s past history, existing market conditions, and prospective estimates at the end of each reporting period. The

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impairment model is applied to financial assets measured at amortized cost or those measured at fair value through other comprehensive income, except for investments in equity instruments.

Expected credit loss is the difference between the contractual cash flows that are due in accordance with the contract and all the cash flows that are expected to be received, i.e. all cash shortfalls), discounted at the original effective interest rate. It is determined considering: i) the probability of default (PD); ii) loss given default (LGD), and iii) exposure at default (EAD).

To determine the expected credit losses the Group applies two separate approaches:

● General approach: applied to financial assets other than trade accounts receivable, contractual assets or lease receivables. This approach is based on the evaluation of significant increases in the credit risk of financial assets, from the date of initial recognition. If on the reporting date of the financial statements the credit risk has not increased significantly, the impairment losses are measured related to the expected credit losses in the next 12 months; if, on the contrary, the credit risk has increased significantly, the impairment is measured considering the expected credit losses throughout the lifetime of the asset.

In general, the measurement of expected credit losses for financial assets other than trade accounts receivable, contractual assets or lease receivables, are performed separately.

● Simplified approach: The Group applies a simplified approach for trade receivables, contract assets and lease receivables so that the impairment provision is always recognized related to the lifetime expected credit losses for the asset. This is the approach that the Group has mostly most applied because trade receivables represent the main financial asset of Enel Américas and its subsidiaries.

For trade accounts receivable, contractual assets and lease receivables, the Group applies two types of evaluations of expected credit losses:

● Collective evaluation: based on grouping accounts receivable into specific groups or “clusters”, taking into account each business and the local regulatory context. Accounts receivable are grouped according to the characteristics of customer portfolios in terms of credit risk, maturity information and recovery rates. A specific definition of default is considered for each group.

To measure the expected credit losses collectively, the Group considers the following assumptions:

PD: average default estimate, calculated for each group of trade receivables, taking into account a minimum of 24-month historical data.

LGD: calculated based on the recovery rates of a predetermined section, discounted at the effective interest rate; and

EAD: accounting exposure on reporting date, net of cash deposits, including invoices issued, but not due and invoices to be issued.  

● Analytical or individual evaluation: if accounts receivables are considered individually significant by Management and there is specific information regarding any significant increase in the credit risk, the Group applies an individual evaluation of accounts receivable. For the individual evaluation, the PD is obtained mainly from an external supplier, when it is possible to do so, and the LGD through an internal model that considers the recovery rate and other contractual and financial characteristics of accounts receivable. The expected credit loss is obtained by multiplying both factors by the EAD, which is defined as the accounting exposure at the reporting date, including the invoices issued but not due and invoices to be issued for services rendered, net of potential cash deposits obtained as guarantees.

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On the basis of the benchmark market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for those accounts receivable, the Group mainly applies a predetermined definition of 180 days overdue to determine expected credit losses, since this is considered an effective indicator of a significant increase in credit risk.

Based on specific evaluations performed by Management, the prospective adjustment can be applied considering qualitative and quantitative information to reflect possible future events and macroeconomic scenarios, which may affect the risk of the portfolio or the financial instrument.

g.4) Financial liabilities other than derivatives

General financial liabilities are initially recognized, at fair value net of any costs incurred in the transaction. In subsequent periods, these obligations are measured at their amortized cost using the effective interest method (see Note 3.g.1).

Lease liabilities are initially measured at the present value of future lease payments, determined in accordance with the criteria described in Note 3.f.

In the particular case that a liability is the hedged item in a fair value hedge, as an exception, such liability is measured at its fair value for the portion of the hedged Risk.

In order to calculate the fair value of debt, both when it is recorded in the statement of financial position and for fair value disclosure purposes as shown in Note 22, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and floating interest rate debt (hereinafter “floating-rate debt”). Fixed-rate debt is that on which fixed-interest coupons established at the beginning of the transaction are paid explicitly or implicitly over its term. Floating-rate debt is that debt issued at floating interest rate, i.e., each coupon is established at the beginning of each period based on the benchmark interest rate. All debt has been measured by discounting expected future cash flows with a market interest rate curve based on the payment currency.

g.5) Derivative financial instruments and hedge accounting

Derivatives held by the Group are transactions entered into to hedge interest and/or exchange rate risk, intended to eliminate or significantly reduce these risks in the underlying transactions being hedged. 

Derivatives are recorded at fair value at the end of each reporting period as follows: if their fair value is positive, they are recorded within “Other financial assets” and if their fair value is negative, they are recorded within “Other financial liabilities”. For derivatives on commodities, positive fair value is recorded in “Trade and other receivables”, and negative fair value, if any, is recognized in “Trade and other liabilities.”

Changes in fair value are recorded directly in profit or loss, except when the derivative has been designated for hedge accounting purposes as a hedging instrument and all of the conditions for applying hedge accounting established by IFRS are met, including that the hedge is highly effective. In this case, changes are recognized as follows:

● Fair value hedges: The underlying portion for which the risk is being hedged and the hedging instrument are measured at fair value, and any changes in the value of both items are recognized in the statement of comprehensive income offsetting the effects in the same caption of the statement comprehensive income.

● Cash flow hedges: Changes in the fair value of the effective portion of the hedged item and hedging instrument are recognized in other comprehensive income and accumulated in an equity reserve referred to as “Hedging reserve.” The cumulative loss or gain in this caption is transferred to the consolidated statement of comprehensive income to the extent that the hedged item impacts the consolidated statement of comprehensive income offsetting the effect in the same comprehensive income statement caption. Gains or

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losses from the ineffective portion of the hedging relationship are recognized directly in the statement of comprehensive income.

Hedge accounting is discontinued only when the hedging relationship (or a part of the relationship) fails to meet the required criteria, after making any rebalancing of the hedging relationship, if applicable. If it is not possible to continue the hedging relationship, including when the hedging instrument expires, is sold, settled or exercised, any gain or loss accumulated in equity at that date remains in the equity until the forecast transaction affects the statement of comprehensive income. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in equity is immediately transferred to the statement of income.

The Group does not apply hedge accounting to its investments abroad.

As a general rule, long-term commodity purchases or sales agreements are recognized in the statement of financial position at their fair value at the end of each reporting period, recognizing any differences in value directly in profit or loss, except for, when all of the following conditions are met:

● The sole purpose of the agreement is for its own use, which is understood as: for fuel purchase agreements such use is to generate electricity; for electrical energy purchased for sale, its sale is to the end-customers; and for electricity sales its sale is to the end-customers.

● The Group’s future projections evidence the existence of these agreements for own use.

● Past experience with agreements shows that they have been used for the Group’s “own use”, except for certain isolated cases when for exceptional reasons or reasons associated with logistical issues, these have been used for other purposes beyond the Group’s control and expectations.

● The agreement does not establish net settlement of differences and there has been no practice to settle similar differences in similar contracts in the past.

The long-term commodity purchase or sale agreements maintained by the Group, which are mainly for electricity, fuel, and other supplies, meet the conditions described above. Accordingly, the purpose of fuel purchase agreements is to use them to generate electricity, electricity purchase contracts for use in sales to end-customers, and electricity sale contracts for sale of the Group’s own products.  

The Group also evaluates the existence of derivatives embedded in contracts or financial instruments to determine if their characteristics and risk are closely related to the host contract, provided that when taken as a whole they are not being accounted for at fair value. If they are not closely related, they are recorded separately and changes in value are accounted for directly in the statement of comprehensive income.

g.6) Derecognition of financial assets and liabilities

Financial assets are derecognized when:

● The contractual rights to receive cash flows from the financial asset expire or have been transferred or, even when, the Group has assumed a contractual obligation to pay these cash flows to one or more recipients.

● The Group has substantially transferred all the risks and rewards of their ownership, or, if it has neither assigned nor retained substantially all the risks and rewards, when it does not retain control of the financial asset.

For transactions in which the Group retains substantially all the inherent risks and rewards of ownership of the financial asset assigned, it recognizes them as a financial liability for the consideration received. Transactions costs are recognized in profit and loss by using the effective interest method (see Note 3.g.1).

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Financial liabilities are derecognized when they are extinguished; i.e., when the obligation arising from the liability has been paid or cancelled, or has expired. An exchange for a debt instrument with substantially different conditions, or a substantial modification in the current conditions of an existing financial liability (or a part thereof), is recorded as a cancellation of the original financial liability, and a new financial liability is recognized.

g.7) Offsetting of financial assets and financial liabilities

The Group offsets financial assets and liabilities and the net amount is presented in the statement of financial position only when:

● there is a legally binding right to offset the amounts recognized; and

● the Group intends to settle them on a net basis, or to realize the asset and settle the liability simultaneously.

Such rights may only be legally enforceable in the normal course of business, or in the event of default, or in the event of insolvency or bankruptcy, of one or all the counterparties.

g.8) Financial guarantee contracts

The financial guarantee contracts, defined as the guarantees issued by the Group to third parties, are initially measured at their fair value, adjusted for transaction costs that are directly attributable to the issuance of the guarantee.

Subsequent to initial recognition, financial guarantee contracts are recognized at the higher of:

● the amount of the liability determined in accordance with the accounting policy described in Note 3.m; and

● the amount of the asset initially recognized less, if applicable, any accumulated amortization recognized in accordance with the revenue recognition policies described in Note 3.q.

h) Fair value measurement

The fair value of an asset or liability is defined as the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market, namely, the market with the greatest volume and level of activity for that asset or liability. In the absence of a principal market, it is assumed that the transaction is carried out in the most advantageous market available to the entity, namely, the market that maximizes the amount that would be received to sell the asset or minimizes the amount that would be paid to transfer the liability.

In estimating fair value, the Group uses valuation techniques that are appropriate for the circumstances and for which there is sufficient data to perform the measurement where it maximizes the use of relevant observable data and minimizes the use of unobservable data.

Given the hierarchy explained below, data used in the valuation techniques, assets and liabilities measured at fair value can be classified at the following levels:

Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities;

Level 2: Inputs other than quoted prices included in Level 1 that are observable for the assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices). The methods and assumptions used to determine the fair values at Level 2 by type of financial assets or financial liabilities take into

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consideration estimated future cash flows discounted at market rates. Future cash flows for financial assets and financial liabilities are discounted with the zero coupon interest rate curves for each currency (these valuations are performed using external tools such as Bloomberg); and

Level 3: Inputs for assets or liabilities that are not based on observable market data (unobservable inputs).

The Group takes into account the characteristics of the asset or liability when measuring fair value, in particular:

● For non-financial assets, fair value measurement takes into account the ability of a market participant to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset at its highest and best use;

● For liabilities and equity instruments, the fair value measurement assumes that the liability would not be settled and an equity instrument would not be cancelled or otherwise extinguished on the measurement date. The fair value of the liability reflects the effect of non-performance risk, namely, the risk that an entity will not fulfill the obligation, which includes but is not limited to, the Company’s own credit risk; 

● For derivatives not traded in active markets, the fair value is determined by using the discounted cash flow method and generally accepted options valuation models, based on current and future market conditions as of the closing date of the financial statements. This methodology also adjusts the value based on the Company’s own credit risk (Debt Valuation Adjustment, DVA), and the counterparty risk (Credit Valuation Adjustment, CVA). These CVA and DVA adjustments are measured on the basis of the potential future exposure of the instrument (asset or liability position) and the risk profile of both the counterparties and the Group itself; and

● For financial assets and financial liabilities with offsetting positions in market risks or counterparty credit risks, measuring the fair value on a net basis is allowed. However, this must be consistent with the manner in which market participants would price the net risk exposure at the measurement date.

Financial assets and financial liabilities measured at fair value are shown in Note 22.3.

i) Investments accounted for using the equity method

The Group’s interests in joint ventures and associates (see Notes 2.5 and 2.6 respectively) are recognized using the equity method of accounting.

Under the equity method of accounting, an investment in an associate or joint venture is initially recognized at cost. As of the acquisition date, the investment is recognized in the statement of financial position based on the share of equity that the Group’s interest represents in capital, adjusted for, if appropriate, the effect of transactions with the Group plus any goodwill generated in acquiring the company. If the resulting amount is negative, zero is recorded for that investment in the statement of financial position, unless the Group has a present obligation (either legal or constructive) to reinstate the Company’s equity position, in which case a provision is recognized.

The financial statements of associates or joint ventures are prepared for the same reporting period as the Group. When required, adjustments are made to align the accounting policies with those of the Group.

Goodwill from the associate or joint venture is included in the carrying amount of the investment. It is not amortized but is subject to impairment testing as part of the overall investment carrying amount when there are indicators of impairment.

Dividends received from these investments are deducted from the carrying amount of the investment, and any profit or loss obtained from them to which the Group is entitled based on its ownership interest is recognized under “Share of profit (loss) of associates accounted for using the equity method of accounting.”

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j) Inventories

Inventories are measured at their weighted average acquisition cost or the net realizable value, whichever is lower.

The net realizable value is the estimated selling price in the ordinary course of business less the applicable costs to sell.

The cost of inventories includes all costs of purchase and all necessary costs incurred in bringing the inventories to their present location and condition net of trade discounts and other rebates.

k) Non-current assets (or disposal groups of assets) held for sale or held for distribution to owners and discontinued operations

Non-current assets, including property, plant and equipment; intangible assets; investments accounted for using the equity method of accounting and joint ventures and disposal groups (a group of assets for disposal or distribution together with liabilities directly associated with those assets), are classified as:

● Held for sale, if their carrying amount will be recovered mainly through a sale transaction rather than through continuing use, or

● Held for distribution to owners, when the entity is committed to distribute the assets (or disposal groups) to the owners.

For the above classifications, the assets must be available for immediate sale or distribution in their present condition and their sale or distribution must be highly probable. For a transaction to be considered highly probable, management must be committed to the sale or distribution and actions to complete the transaction must have been initiated and should be expected to be completed within one year from the date of classification.

Actions required to complete the sale or distribution plan should indicate that it is unlikely that significant changes to the plan can be made or that the plan will be cancelled. The probability of shareholders’ approval (if required in the jurisdiction) should be considered as part of the assessment of whether the sale or distribution is highly probable.

The assets or disposal groups classified as held-for-sale or held for distribution to owners are measured at the lower of their carrying amount and fair value less costs to sell or costs to distribute, as appropriate.

Depreciation and amortization on these assets cease when they meet the criteria to be classified as non-current assets held for sale or held for distribution to owners.

Assets that are no longer classified as held for sale or held for distribution to owners, or are no longer part of a disposal group, are measured at the lower of their carrying amounts before being classified as held for sale or held for distribution, less any depreciation, amortization or revaluation that would have been recognized had they had not been classified as held for sale or held for distribution to owners and their recoverable amount at the date of reclassification non-current assets.

Non-current assets held for sale and the components of the disposal groups classified as held for sale or held for distribution to owners are presented in the consolidated statement of financial position as a single line item within assets referred to as “Non-current assets or disposal groups held for sale or for distribution to owners”, and the related liabilities are presented as a single line item within liabilities referred to as “Liabilities included in disposal groups held for sale or for distribution to owners”.

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The Group classifies as discontinued operations those components of the Group that either have been disposed of, or are classified as held for sale and:

(i) represent a separate major line of business or geographical area of operations;

(ii) is part of a single coordinated plan to dispose of a separate major line of business or geographical area of operations; or

(iii) is a subsidiary acquired exclusively with a view to its resale.

The after-tax results of discontinued operations are presented in a single line of the statement of comprehensive income referred to as “Profit (loss) from discontinued operations”, as well as the gain or loss recognized from the measurement at fair value less costs to sell or from the disposal of the assets or groups for disposal comprising the discontinued operation.

l) Treasury shares

Treasury shares are presented deducting the caption “Total equity” in the consolidated statement of financial position and measured at acquisition cost.

Gains and losses from the disposal of treasury shares are recognized directly in “Total Equity – Retained earnings (losses)”, without affecting profit or loss for the period.

m) Provisions

Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material). The unwinding of the discount is recognized as finance cost. Incremental legal costs expected to be incurred in resolving a legal claim are included in measuring of the provision.

Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of resources embodying economic benefits will be required to settle the obligation, the provision is reversed.

A contingent liability does not result in the recognition of a provision. Legal costs expected to be incurred in defending a legal claim are expensed as incurred. Significant contingent liabilities are disclosed unless the likelihood of an outflow of resources embodying economic benefits is remote.

m.1) Provisions for post-employment benefits and similar obligations

Certain of the Group’s companies have entered into pension and other similar commitments with their employees. Those defined benefit and defined contribution commitments are basically through pension plans, except for those related to certain benefits in lieu of payment, basically commitments to supply electric energy, which, due to their nature have not been outsourced and their coverage is provided through the related internal provision.  

For defined benefit plans, the companies record the related expense for these commitments following the accrual criteria over the service life of the employees through timely actuarial studies performed as of the reporting date

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calculated applying the projected credit unit method. The cost of past services which correspond to variances in benefits is recognized immediately.

The defined benefit plan obligations in the statement of financial position represent the present value of the accrued obligations, upon deduction of the fair value of the different plans’ assets, if any.

For each defined benefit plan, if the difference between the actuarial liability for past services and the plan assets is positive, it is recognized under line item “Provisions for employee benefits” in liabilities in the consolidated statement of financial position, and if such difference is negative is recognized under line item “Other financial assets” in the consolidated statement of financial position, provided that is recoverable for the Group, usually through a reduction in future contributions and taking into consideration the limit established in IFRIC 14, IAS 19 The Limit on a Defined Benefit Asset, Minimum Funding Requirements, and their interaction.

Actuarial gains and losses arising from measurements of both the plan liabilities and the plan assets, including the limit in IFRIC 14, are recognized directly as a component of other comprehensive income.

Contributions to defined contribution benefit plans are recognized as an expense when the employees have rendered provide their services.

n) Translation of balances in foreign currency

Transactions performed by each entity in a currency other than its functional currency are recognized using the exchange rates prevailing as of the date of the transactions. During the period, differences arising between the prevailing exchange rate at the date of the transaction and the exchange rate as of the date of collection or payment are recognized as “Foreign currency translation differences” in the consolidated statement of comprehensive income.

Likewise, at the end of each reporting period, balances receivable or payable denominated in a currency other than each entity’s functional currency are remeasured using the closing date exchange rate. Any differences are recorded as “Foreign currency translation differences” in the consolidated statement of comprehensive income.

The Group has established a policy to hedge the portion of revenue from its consolidated entities that is directly linked to variations in the U.S. dollar, through obtaining financing in such currency. Exchange differences related to this debt, which is regarded as the hedging instrument in cash flow hedge transactions, are recognized, net of taxes, in other comprehensive income and are accumulated in an equity reserve and recorded in profit or loss in the term in which the cash flows hedged will be realized. This term has been estimated as ten years.

o) Classification of balances as current or non-current

In these consolidated statements of financial position, balances are classified according to their maturity, i.e., those maturing within twelve months are classified as current (except for provisions for post-employment obligations and other similar ones). Balances maturing in more than twelve months are classified non-current. Deferred tax assets and liabilities are classified as non-current. 

When the Group has any obligations that mature in less than twelve months but can be refinanced over the long term at the Group’s discretion, through unconditionally available loan agreements with long-term maturities, such obligations are classified as non-current liabilities.

p) Income taxes

Income tax expense for the period is determined as the sum of current taxes from each of the Group’s subsidiaries and results from applying the tax rate to the taxable income for the period, after deductions allowed have been made, plus any changes in deferred tax assets and liabilities and tax credits, both for tax losses and deductions. Differences between the carrying amount and tax basis of assets and liabilities generate deferred tax assets and liabilities, which

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are calculated using the tax rates expected to be applied when the assets and liabilities are realized or settled, based on tax rates that have been enacted or substantively enacted by the end of the reporting period.

Deferred tax assets are recognized for all deductible temporary differences, tax losses and unused tax credits to the extent that it is probable that sufficient future taxable profits exist to recover the deductible temporary differences and use the tax credits. Such deferred tax asset is not recognized if the deductible temporary difference arises from the initial recognition of an asset or liability that:

● did not arise from a business combination; and

● at initial recognition provide it affected neither accounting profit nor taxable profit (loss).

With respect to deductible temporary differences associated with investments in subsidiaries, associates and joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profits will be available against which the temporary differences can be utilized.

Deferred tax liabilities are recognized for all temporary differences, except for those derived from the initial recognition of goodwill and those that arose from investments in subsidiaries, associates and joint ventures in which the Group can control their reversal and where it is probable that they will not be reversed in the foreseeable future.

Current tax and changes in deferred tax assets or liabilities are recorded in profit or loss or in equity, depending on where the gains or losses that triggered these tax entries have been recognized.

Any tax deductions that can be applied to current tax liabilities are credited to earnings within the line item “Income tax expenses”, except when uncertainty exists about their tax realization, in which case they are not recognized until they are effectively realized, or when they relate to specific tax incentives, in which case they are recorded as grants.

At the end of each reporting period, the Group reviews the deferred tax assets and liabilities recognized, and makes, any necessary adjustments based on the results of this analysis.

Deferred tax assets and deferred tax liabilities are offset in the consolidated statement of financial position if the Group has a legally enforceable right to set off current tax assets against current tax liabilities, and only when the deferred taxes relate to income taxes levied by the same tax authority.

q) Revenue and expense recognition

Revenue is recognized when (or as) the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which the Group is expected to be entitled for said transfer of control, excluding the amounts collected on behalf of third parties.

The Group analyzes and takes into consideration all the relevant facts and circumstances for revenue recognition, applying the five step model established by IFRS 15: 1) Identifying the contract with a customer; 2) Identifying the performance obligations; 3) Determining the transaction price; 4) Allocating the transaction price; and 5) Recognizing revenue.

The following are the criteria for revenue recognition by type of good or service provided by the Group:

● Electricity supply (sale and transportation): Corresponds to a single performance obligation that transfers to the customer a number of different goods/services that are substantially the same and that have the same transfer pattern. Since the customer receives and simultaneously consumes the benefits provided by the Company, it is considered a performance obligation met over time. In these cases, the Group applies an output method to recognize revenue in the amount to which it is entitled to bill for electricity supplied to date.

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● Generation: revenue is recorded according to the physical deliveries of energy and power, at the prices established in the respective contracts, at the prices established in the electricity market by the current regulations, or at the marginal cost of energy and power, depending on whether they are unregulated customers, regulated customers or energy trading in the spot market are involved, respectively.

● Distribution of electricity: revenue is recognized based on the amount of energy supplied to customers during the period, at prices established in the related contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate.

These revenues include an estimate of the service provided and not invoiced, at the reporting date (see Notes 2.3 and 27 and Appendix 3.2).

● Other Services: mainly the provision of supplementary services to the electricity business, construction of works and engineering and consulting services. Customers control committed assets as they are created or improved. Therefore, the Company recognizes this revenue over time based on the progress, measuring progress through output methods (percentage of completion through the present date, milestones reached, etc.), or costs incurred (resources consumed, hours of labor spent, etc.), as appropriate in each case.

● Sale of goods: revenue from the sale of goods is recognized at a certain time, when control of the goods has been transferred to the customer, which generally occurs at the time of the physical delivery. Revenues are measured at the independent sale price of each good, and any type of applicable variable compensation.

In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance obligations of the transaction, based on the control transfer pattern of each good or service that is separate and an independent selling price allocated to each of them, or jointly to two or more transactions, when these are linked to contracts with customers that are negotiated with a single business purpose and the goods and services committed represent a single performance obligation and their selling prices are not independent. 

Enel Américas determines the existence of significant financing components in its contracts, adjusting the value of the consideration if applicable, to reflect the effects of the time value of money. However, the Group applies the practical expedient provided by IFRS 15, and will not adjust the value of the consideration committed for the purpose of a significant financing component, if it expects, at the beginning of the contract, that the period between the payment and the transfer of goods or service to the customer is one year or less.

The Group excludes the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue amount. The Group only records as revenue the payment or commission to which it expects to be entitled.

Because the Group mainly recognizes revenue for the amount to which it has the right to invoice, it has decided to apply the disclosure practical expedient provided in IFRS 15, through which it is not required to disclose the aggregate amount of the transaction price allocated to the performance obligations not met (or not met partially) at the end of the reporting period.

In addition, the Group evaluates the existence of incremental costs of obtaining a contract and costs directly related to the fulfillment of a contract. These costs are recognized as an asset, if their recovery is expected, and amortized in a manner consistent with the transfer of the related goods or services. As a practical expedient, the incremental costs of obtaining a contract are recognized as an expense, if the depreciation period of the asset that has been recognized is one year or less. Costs that do not qualify for capitalization are recognized as expenses at the time they are incurred, unless they are explicitly attributable to the customer.

As of December 31, 2021 and 2020, the Group has not incurred costs to obtain or perform a contract which meet the conditions for their capitalization. The costs incurred to obtain a contract are substantially commission payments for

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sales that, although are incremental costs, relate to short-term contracts or performance obligations that are met at a certain time, therefore, the Group has decided to recognize these costs as an expense when they occur.

Interest income (expenses) are recorded considering the effective interest rate applicable to the principal pending amortization, during the related accrual period.

r) Earnings per share

Basic earnings per share are calculated by dividing net income attributable to shareholders of the Parent Company by the weighted average number of common shares outstanding during the period, excluding the average number of shares of the Company held by other subsidiaries within the Group, if any.

Basic earnings per share for continuing and discontinued operations are calculated by dividing net income from continuing and discontinued operations attributable to shareholders of the Company (the numerator) by the weighted average number of shares of common stock outstanding (the denominator) during the year, excluding the average number of shares of the Company held by other subsidiaries within the Group.

Diluted earnings per share is calculated by dividing profit attributable to shareholders of the Parent Company by the weighted average number of common shares outstanding during the period plus the weighted average number of common shares of that would be issued on conversion of all the potential dilutive securities into common shares, if any.

s) Dividends

Article No. 79 of Law No. 18,046 (the Chilean Corporations Law) establishes that, unless unanimously agreed otherwise by the shareholders of all issued shares, listed corporations must distribute a cash dividend to shareholders on an annual basis, pro rata among the shares owned or the proportion established in the Company’s by-laws if there are preferred shares, of at least 30% of profit for each year, except when accumulated losses from prior years must be absorbed.

As it is practically impossible to achieve a unanimous agreement given Enel Américas’ highly fragmented share ownership, at the end of each reporting period the amount of the minimum statutory dividend obligation to its shareholders is determined, net of interim dividends approved during the period, and then accounted for in “Trade and other payables, current” and “Current accounts payable to related parties”, as appropriate, and recognized in equity.

The interim and final dividends are deducted from equity when approved by the relevant authority, which in the first case is normally the Board of Directors and in the second case is the responsibility of the shareholders as agreed at a General Shareholders’ Meeting.

t) Share issuance costs

Share issuance costs, only when they represent incremental expenses directly attributable to the transaction, are recognized directly in net equity as a deduction from “Share premiums,” net of any applicable taxes.

If the share premium account has a zero balance or if the costs described exceed the balance, they are recognized in “Other reserves”. Subsequently, these costs must be deducted from paid-in capital, and this deduction must be approved at an Extraordinary Shareholders’ Meeting, which occurs immediately after the date on which the disbursements were incurred.

Share issuance and placement expenses directly related to a probable future transaction are recorded as prepaid expenses in the statement of financial position. These expenses are recorded in equity upon issuance and placement of the shares, or in profit or loss when the conditions change and the transaction is no longer expected to occur.

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u) Statement of cash flows

The statement of cash flows reflects changes in cash and cash equivalents that took place during the period, determined with the direct method. It uses the following definitions and related meanings:

● Cash flows: inflows and outflows of cash or cash equivalents, which are defined as highly liquid investments maturing in less than three months with a low risk of changes in value.

● Operating activities: the principal revenue-producing activities of the Group and other activities that cannot be considered investing or financing activities.

● Investing activities: the acquisition and disposal of long-term assets and other investments not included in cash and cash equivalents.

● Financing activities: activities that result in changes in the size and composition of the total equity and borrowings of the Group.

4. SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS

i.Regulatory Framework:

a) Argentina

Structure and regulatory entities of the Argentine Electricity Market

The Argentine electric regulatory framework is set up by Law No. 24,065, which defines vertical segmentation for electricity generation, transmission, and distribution activities.

Law No. 24,065 established the bases for the creation of the Electricity Regulatory Body (“ENRE”), management of the Wholesale Electricity Market (“MEM”), the setting of spot prices and regulated tariffs.

In the Argentine Wholesale Electricity Market (MEM), there are 4 categories of local agents: generation companies, transmission companies, distribution companies and large customers, and 2 external agents: generation trading companies and demand trading companies, which are authorized to buy and sell electricity and related products. The Argentine autonomous entity in charge of operating the “MEM” is “Compañía Administradora del Mercado Mayorista Eléctrico S.A.” (CAMMESA), which also manages the fuel used by generating plants.

Despite Law No. 24,065 and its subsequent regulations, the continuous economic crises that Argentina has been experiencing has led the government to intervene in the electricity market.

Electric Power Generation

The electricity generation segment consists of companies that own electricity generation plants. These companies sell electricity to the market, at a price set by the regulatory body, which also carries out pricing updates and readjustments. The latest readjustment to generators’ tariffs reached 29% and was established by Resolution No. 440, published on May 21, 2021. This readjustment has been applied retroactively on the tariffs identified in Resolution SE No. 31/2020, from February 2021 onwards.

On November 2, 2021, Resolution SE No. 1,037/21 was passed, which gives a compensation benefit in addition to that established in Resolution No. 440 for thermal and hydraulic power generators that export energy to interconnected neighboring countries, and which will cover transactions between September 1, 2021, and February 28, 2022.

The revenue collected by CAMMESA will be assigned to a stabilization fund for the MEM to ultimately fund energy infrastructure works, which will be assigned at the time as established by the Ministry of Energy.

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Renewable Energy

In Argentina, on October 21, 2015, Law No. 27,191 for Renewable Energy was issued. The new regulation postpones reaching an 8% share in the national demand of energy with renewable sources for generation to December 31, 2017 and establishes a second stage goal of reaching a 20% share in 2025 by establishing milestones of 12% at the end of 2019, 16% at the end of 2021 and 18% at the end of 2023.

Electric Power Transmission

The electricity transmission sector is a public service that operates under monopolistic conditions and is made up of several companies to which the Argentine government grants concessions. A concessionaire operates and maintains the highest voltage facilities, and 8 concessionaires operate and maintain the medium and low voltage facilities, to which generating companies, distribution companies and large customers are connected. Transmission companies are authorized to charge different tariffs for their services.

Electric Power Distribution

Electricity distribution is a public service that operates under monopolistic conditions and is made up of companies that the Argentine government has granted concessions to. Distribution companies have the obligation to supply electricity to individual customers within a specific concession area, whether or not these customers have a contract with the distribution company or directly with a generating company. Distribution companies have regulated tariffs and are subject to quality standards. Distribution companies can purchase electricity on the Argentine “MEM” spot market, at the so-called “seasonal price” defined by the Argentine SEE as “the maximum cost of electricity purchased by distributors that can be passed on to regulated customers”.

On August 17, 2021, by Resolution No. 267, the ENRE ordered the creation of a "Database for monitoring outages" within the context of compliance with the service that electricity distribution companies must provide. The aim was to evaluate the technical and operational response of distribution companies to users’ complaints of a lack of supply. This resolution seeks to oversee how distribution companies assist and follow up on their customers’ complaints, in order to restore their access to power as quickly as possible.  Priority is given to customers who have been identified as “electro-dependent”, for health reasons.

Electricity tariffs are regulated by the Argentine “ENRE”, based on the Comprehensive Tariff Review (“RTI”) process, which determines tariff charts, their duration and relevant adjustments over time.

In 2006 and during the last Comprehensive Tariff Review in 2017, a series of disputes arose between Edesur and the regulatory body ENRE. This cumulated with the signing of the “Obligation Regularization Agreement” on May 10, 2019.  On September 21, MECON´s Resolution No. 590/21 declared that this agreement is harmful to public interest and ordered the suspension of its administrative procedures with respect to the agreement. MECON also instructed the Litigation Department of Energy to initiate judicial actions to nullify the aforementioned Agreement.

The Resolution does not attribute any breach of the Agreement to Edesur. However, the Agreement is still in force, as it has been signed by the parties’ representatives. Therefore, it is being carried out and is considered to be firm.

Tariff Revisions

On February 1, 2017, the ENRE published Resolution No. 64/2017 in the Argentine Official Gazette, by which the tariff charts resulting from the Comprehensive Tariff Review (RTI) process were approved. However, the Argentine authorities have been postponing and freezing electricity tariffs throughout 2020, and part of 2021, by means of Law No. 27,541 on Social Solidarity and Productive Reactivation. This is due to the economic crises experienced by the country, which have been aggravated by the Covid-19 pandemic.

DNU No. 1,020 recognizes that under Law No. 27,541 there has been a tariff reduction (maintenance of tariffs in an inflationary environment), that was necessary to mitigate the emergency economic situation. At the same time, DNU

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No. 1,020 recognizes that a tariff readjustment mechanism must be established to guarantee the normal provision of services. Consequently, this DNU establishes the obligation to start a Comprehensive Tariff Renegotiation Process that results in a Definitive Renegotiation Agreement, in a period less than 2 years.

Until a definitive RTI is reached, under the new scenario according to DNU No. 1,020, the ENRE is authorized to establish transitory tariff readjustments, thus ensuring stability to the provision of services.

On March 21, 20__the ENRE established a new transitory tariff chart by means of Resolution No. 79/2021, which was readjusted by 9% through resolution No. 106, dated April 30, 2021, pending the Comprehensive Tariff Renegotiation Process.

The ENRE approved new tariff charts effective as of August 1, 2021, by Resolutions No. 263/2021 and No. 266/2021. These tariff charts only modify the Stabilized Seasonal Price for Demands Greater than 300 kWh/month under Resolution No. 748/21 of Secretary of Energy (+3.1%, from ARS$ 5,020 to ARS$ 5,176 / kWh), and do not modify the Distribution Added Value perceived by Edesur.

Other regulatory aspects

Due to the health crisis, a series of regulations has been issued to regulate different situations produced by the Covid-19 pandemic. It should be noted that these measures are still in effect thanks to the extension of the state of health emergency until December 31, 2022, by way of Decree 867 of December 24, 2021, which prevents electricity shut-offs for certain customers, agreements to assign Edesur’s pending debts due to service outages between 2017 and 2020 to works to improve the electricity service and status of the network that supplies lower-class neighborhoods with collective meters and other sensitive zones in the concession areas, as mechanisms to repair debts held by distributors with CAMMESA, the temporary suspension of the issuance of Debit Notes and Complementary Liquidations for unrecorded consumption.

In this context, on January 21, 2021, the Ministry of Energy issued Resolution No. 40, establishing a “Special Regime for Obligation Regularization” for debts incurred by distribution companies with CAMMESA arising from energy consumption, power, as well as interest and/or penalties accumulated as of September 30, 2020. This Resolution initiates the regularization process established by Article 87 of Law No. 27,591. On April 28, 2021, the Secretariat of Energy issued Resolution No. 371/2021, which establishes the criteria that must be considered in agreements for the regularization of obligations with the MEM to which the Distribution Agents will adhere. All the above is established within the provisions of Article 87 of Law No. 27,591 on the 2021 National Budget, which establishes a recognition of credits in favor of Distributing Agents for up to five times the average monthly invoicing of the last year or sixty six percent (66%) of the debt accumulated with CAMMESA as of September 30, 2020. Likewise, mechanisms that promote investments in energy efficiency and improvements to the quality of electric power distribution services can be agreed upon and executed. Subsequently, on May 14, 2021, the SE was instructed to carry out a new extension (until May 30, 2021) of the term provided by Article 6 of Resolution S.E. No. 40/2021 within the same framework, and to apply the same treatment of terms and reduced interest rates to debts taken out after September 30, 2020 and until April 30, 2021. Hence, negotiations were upheld regarding the transition regime between the Secretariat, the regulatory bodies and the distribution companies.

b)   Brazil

Structure and regulatory bodies in the Brazilian Electricity System

The legislation in Brazil allows the participation of private equity in the electricity sector, upholds free competition among companies in electricity generation and transmission, and defines criteria to avoid certain levels of economic concentration and/or market practices that may cause a decline in free competition.

The main electricity regulatory entity in Brazil is the National Electric Energy Agency (“ANEEL”). Its role includes auditing concessions and authorizations for the generation, transmission and distribution of electric power, the promulgation of the sectorial regulatory framework, the regulation of use of primary electrical resources, including

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the use of hydroelectric resources, and the establishment of bidding processes under the supervision of the Ministry of Mines and Energy (“MME”), among other responsibilities.

Brazil’s National Interconnected System (“SIN”) is made up of 4 large subsystems: South, Southeast/Central-West (which is the largest in the country in terms of demand, as it serves the region with the largest population and industrial production), North and Northeast.

The National Electric System Operator (“ONS”) was created in 1998 and is the entity that is responsible for the coordination and supervision of the “SIN” electric power generation and transmission facilities.

The Electric Power Trading Chamber (“CCEE”) operates the electricity purchase and sales market in Brazil through carrying out the financial settlement of the market, which includes contracts negotiated in the free and regulated market.

Electric Power Generation

The electric power generation sector is organized on a competitive basis. Independent electricity producers execute Power Purchase Agreements (“PPAs”) with regulated distributors through centralized energy auctions and non-regulated marketers or customers through bilateral contracts. In both the regulated and non-regulated markets, differences between production and sales (demand) are traded in the short term or in cash at the “Settlement Price for Differences” (“PLD”). Although a generator can sell its electricity in the regulated or unregulated market, all contracts must be registered with the CCEE.

Sales to the regulated market must be made through auctions, which seek to organize the existing electric power generation capacity and future projects. Prices differ according to the type of technology used and the deadlines agreed on. 

Currently, Enel Green Power Brazil is building 692 MW of installed capacity from solar (São Gonçalo III) and wind projects (Lagoa dos Ventos III, Morro do Chapéu Sul II, Fontes dos Ventos II, Cumaru e Aroeira). These clean energies were essentially traded on the free market.

There is also a mechanism called the Electricity Relocation Mechanism (“MRE”) used by hydroelectric generators to reallocate the hydrological risk by compensating differences between the established production capacity of a hydrological plant and its actual production.

On November 30, 2021, the Electricity Regulator (ANEEL) passed the new regulations for Hybrid Power Plants (REN 954/2021) as of January 2022. The rule, which establishes requirements and procedures to obtain the necessary authorizations, will allow for a complementary exchange in connection from different generation sources in order to optimize system transmission.

A new Decree establishes that the Regulator will grant the authorization of electric power plants for protocols performed up to March 3, 2022, with no need for a specific document issued by the system operator (access information). This document indicates the viability, or unviability, of network connection in relation to the generation capacity margin. Moreover, the Decree foresees the possibility of the Regulator and Ministry carrying out a competitive bid process with respect to generation margin capacity to access the national interconnected system.

Electric Power Transmission

The electricity transmission sector operates under public/private monopoly conditions with concession contracts granted through bids. The ANEEL sets the annual revenues of all electricity transmission companies operating in Brazil. Transmission revenue considers a fixed tariff for the availability of transmission assets, which does not depend on the amount of electricity that flows through the transmission lines. The transmission network comprises any transmission asset that operates above 138 kV.

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On June 19, 2020, the Ministry of Mining and Energy published ordinance No. 255, which officially designates Enel CIEN to continue operating the Garabi 1 facilities until a new operator is designated through the bid process, which will probably start in August 2022. Until that date, Enel CIEN will receive annual revenue (RAP) calculated according to the current criteria and methodology.

Electric Power Distribution

Distribution is a public service that operates under the conditions of natural monopoly. The companies authorized to distribute electricity have been granted a concession to operate in a geographically defined concession area. Electricity concession holders must acquire electric power from the regulated market.

These regulatory mechanisms ensure the creation of regulatory assets/liabilities, whose tariff adjustment for possible deficits will be made from in the subsequent tariff adjustments that will occur in 2023 (March 15 for Enel Distribución Río S.A. (formerly Ampla), April 22 for Enel Distribución Ceará S.A. (formerly Coelce), July 4 for Enel Distribución São Paulo (formerly Eletropaulo) and October 22 for Enel Distribución Goiás). This mechanism has existed since 2001, and is called the Securities Compensation Account - Part A (CVA in its Portuguese acronym) which is aimed at maintaining consistent operating margins for the dealer by allowing tariff revenue from costs of Part A. 

The final tariff revisions of Enel distributors were performed in 2018 (Enel Distribución Río and Enel Distribución Goiás) and 2019 (Enel Distribución Ceará and Enel Distribución São Paulo). The Enel distributors’ next revisions will be performed in 2023.

The latest tariff modifications are summarized as follows:

		Average gain setting
	Rate adjustment
Company	date	High voltage	Low voltage
Enel Distribución Rio	March 2021	+10.38%	+4.63%
Enel Distribución Ceará	April 2021	+10.21%	+8.54%
Enel Distribución Sao Paulo	June 2021	+3.67%	+11.38%
Enel Distribución Goias	October 2020	+14.21%	+17.32%

In January 2015, based on the mismatches between the costs recognized in tariffs and actual costs other than those related to operations of distribution entities, ANEEL began the application of a Pricing System known as “Tariffs Flags” of additional monthly charges over the tariff to the customers, provided that the marginal cost of the system is higher than the regulatory standard.

The Tariff Flags System is comprised of three levels of colored flags: Red, Yellow and Green.

On August 31, 2021, the Ministry of Mines and Energy (“MME”) determined, through CREG Resolution No. 3/2021, that the National Electric Power Agency (“ANEEL”) implement the Flag Fee for Water Scarcity in the amount of BRL 142.00 / MWh (US $ 26.28 / MWh), effective from September 2021 to April 2022, for captive customers except low-income customers

For low-income customers, ANEEL ratified a level 2 red flag for the months of September and October 2021, yellow for November 2021, and green from December 2021, due to the improvement in the Brazilian water system.

In conclusion, under this tariff system the generation cost that is currently transferred to the customer only once a year (when the annual tariff adjustment is performed), will have a variation on a monthly basis and the customer will be able to better manage its electricity consumption.

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Other regulatory aspects

Due to the adverse hydrological conditions that Brazil has been experiencing as a result of the lack of rainfall, several measures are being adopted, such as:

MME Resolution No. 22/2021 establishes guidelines for the Voluntary Electric Power Demand Reduction Offer for free consumers, which is effective until April 30, 2022. Free consumers and Aggregators may offer products with a minimum volume of 5MW per hour for a reduced consumption of four or seven hours at market prices. Due to the improvement in hydrological conditions, the offers were suspended in November 2021, but considering the validity of the program, the ONS can request new offers at any time. 

CREG Resolution No. 2/2021 establishes the Incentive Program for the Voluntary Reduction of Electricity Consumption: rebates will be granted on the bill, starting in January 2022. This program consists of bonuses of BRL 50.00 (US$ 9) per 100kWh that will be granted to customers that reduce their electricity consumption between 10% and 20% during September and December 2021, compared to the same months of 2020.

CNPE Resolution No. 15/2021 allocated BRL 29.8 billion (US $5.5B) to the “CDE” (BRL $5 billion (US $0.9B) in 2022). This allocation is related to the devaluation of Eletrobrás and aims to mitigate its impact on tariffs in 2022.

CREG Resolution No. 4/2021 has determined a simplified competitive procedure for the auction ���Contracting Electricity Capacity Reserves in the Southeast/Midwest and South subsystems for the period between 2022 to 2025”. The details regarding the type of technology that will be able to participate in this auction have not yet been defined.

On November 23, 2021, ANEEL approved rules for the evaluation of economic adjustment requests as a result of the impact caused by the pandemic. Additionally, on December 7, 2021, ANEEL passed an updated regulatory recognition methodology for non-technical losses and bad debts, to be applied in the rate revisions to be performed in 2023.

Simplification of network connection terms - connection in 45 days for units with contracted power of up to 140 kVA, in urban areas, and up to 150 meters from the network where there is no need for expansion, reinforcement, or improvement works to the distribution system.

c)   Colombia

Structure and regulatory entities of the Colombian Electricity Market

In 1994, Act 142 or the Public Utility Act (Ley de Servicios Públicos Domiciliarios) and Act 143 or the Electricity Act (Ley Eléctrica) were issued, which established the general criteria and policies regulating the public utility service provision in Colombia, as well as the procedures and mechanisms for its regulation, monitor and oversight.

The Electricity Act make the constitutional approach viable, regulates the generation, transmission, distribution and sale of electricity, creates a market and competitive environment, strengthens the industry and delimit the government intervention. Considering the characteristics of each activity or business, general guidelines were established for the development of the regulatory framework, creation and implementation of the rules that would allow free competition in the power generation and sales industries, while the guidelines for the transmission and distribution industries were aimed to address these activities as monopolies, looking for competitive conditions if possible.

The main institution in the electricity sector is the Ministry Mining and Energy, which through the Mining Energy Planning Unit (Unidad de Planeación Minero Energética, or UPME) develops the national Energy Plan and the Generation and Transmission Expansion Plan. The Energy and Gas Regulatory Commission (Comisión de Regulación de Energía y Gas, or CREG) and the Public Service Superintendency (Superintendencia de Servicios Públicos, or SSPD) regulate and oversee, respectively, the companies in the industry. In addition, the Superintendency of Industry and Commerce is the national authority for free trade protection issues.

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The electricity industry operates on the basis of electricity-selling companies and the large consumers are able to buy and sell energy through bilateral contracts or on a short-term energy exchange market, called the “energy exchange” that operates freely according to supply and demand conditions. In addition, there are two mechanisms to promote the expansion of the system: i) auctions of Firm Energy within a “Reliable Charge” scheme and ii) long-term auctions to enhance the Non-conventional Renewable Energy Sources (FRNCE in its Portuguese acronym).

Electric Power Generation

The generation segment is made up of companies that own electricity generation plants. Electricity generators sell their energy and power to the wholesale electricity market (MEM), at a price established by the regulator, or to large clients called free clients through bilateral contracts.

Renewable Energy

In 2014, Law No. 1,715 was enacted, creating a legal framework for the development of non-conventional renewable energies, which established guidelines on the declaration of public utility, tax, tariff and accounting incentives. As part of the regulation, the Ministry of Mining and Energy issued Decree No. 2,469 of 2014, which established the energy policy guidelines for the delivery of self-generation surpluses to promote the growth of a clean energy matrix, auctions have been carried out with the participation and additional benefits for FRNCEs. The benefits include rebates of up to 50% of the total investment and the obligation for marketing agents to acquire a percentage of 10% of this type of electric power.

For its part, the Ministry of Environment and Sustainable Development (MADS in its Portuguese acronym) has been developing the regulatory framework through Terms of Reference with which the characteristics and obligations that must be met by those interested in developing FRNCER projects that require an environmental license are established.

Energy transition act

Law No. 2,099, published on July 10, 2021, aims to modernize current legislation and establish other provisions for energy transition, as well as revitalizing the energy market through the use, development and promotion of non-conventional sources of energy. It also seeks to reactivate the country’s economy and strengthen the electricity and gas supply market in general.

This law addresses issues related to tax benefits for investment in the field of electricity production with non-conventional energy sources and efficient energy management. In addition, it will encourage green and blue hydrogen, streamline procedures to implement infrastructure projects for electric power supply to the public, electric mobility, smart metering and institutional development.

Law No. 2,099 also states that the Ministry of Environment and Sustainable Development (MADS) will establish the environmental requirements that must be met by projects developed with geothermal energy, and it prioritizes environmental licensing (and any modifications) for projects with a startup date that is less than two years ahead, and establishes that connection assets to the SIN will not require “Alternative Environmental Diagnosis (DAAs) in electric power generation projects that decide to share these connection assets according to the terms defined by the applicable regulation of the CREG. In this sense, the MADS, through Resolution No. 1,060 of 2021, establishes the Terms of Reference for the preparation of the Environmental Impact Study (EIA) for the environmental license process for projects using biomass for power generation. 

Finally, this Law gives rise to the Clean Production Seal, which the Ministry of Mines and Energy will grant to all companies that only use non-conventional sources of renewable energy in their production processes and also invest in improving energy efficiency.

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Electric Power Transmission

Transmission companies that operate transmission lines of at least 220 kV are part of the National Transmission System (SNT). These companies must give access to their networks on equal terms and are authorized to charge a fee for their services. The transmission fee includes a connection charge that covers their facilities’ operating costs and a usage fee.

Electric Power Distribution

Electricity distribution companies are natural, regional monopolies. These companies operate according to tariffs regulated by the CREG, which are based on criteria such as service provision efficiency and quality. Any customer can access the distribution network by paying the connection fee.

Tariff Revisions

CREG is the entity that defines the method by which distribution networks are paid. Distribution charges are reviewed every five years and updated monthly according to the Producer Price Index (“PPI”).

In February 2018, the CREG Regulatory Commission published Resolution No. 15, establishing the definitive Distribution Remuneration Methodology for the new tariff period (2018-2023). Subsequently, on June 24, 2020, the CREG issued Resolution No. 122/2020, which approved the final distribution tariffs that Codensa is authorized to charge.

In short, the Commission determines the distribution tariffs based on the available distribution assets, operating and maintenance expenses and the presentation of investment plans. Remuneration also includes loss absorption mechanisms and incentives for the quality of service. The application of the rate began from the month of July 2020.

In June 2021, the CREG approved the modification of the Codensa Investment Plan by means of Resolution No. 68 of 2021.

In June 2021, the Ministry of Mining issued Resolution No. 40172, which establishes the maximum rate increase to compensate coverage expansions projects, which shall not exceed 1% of the distribution charge.

In June 2021, the Commission published CREG Resolution No. 075 of 2021. The resolution establishes provisions and procedures for the assignment of transport capacity to the national interconnected system (SIN) as requested by the MME under the public policy guidelines for connection established by MME Resolution No. 40311 of 2021.

In July 2021, Law No. 2099 was passed to establish provisions for the energy transition, the dynamization of the energy market, reactivation of the national economy, and others. It addresses topics related to tax benefits for investment in the field of energy production using non-conventional sources and efficient energy management, the promotion of green and blue hydrogen, rationalization of proceedings in the execution of infrastructure projects for the provision of public electricity services, e-mobility, and smart and institutional measurement. 

At the end of August 2021, the CREG presented two regulatory proposals to agents that look to make modifications to the Reliability Charge system. On the one hand, Resolution No. 132 of 2021 is under discussion, which proposes the definition of an option to assign Firm Energy Obligations to existing plants supported by natural gas. On the other hand, the Commission published Resolution No. 133 of 2021, which proposes a competitive scheme for the assignment of Firm Energy Obligations to existing plants. These proposals were still under discussion at the close of 2021.

In September 2021, the Ministry of Mining and Energy published the Registry with the roadmap actions for the energy transformation mission.

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In November 2021, the Commission issued CREG Resolution No. 148 of 2021, which established the connection and operation of solar and wind power plants in the SDL, with net effective capacity or maximum declared power equal or greater than 5 MW.

In November 2021, the Commission issued CREG Resolution No. 174 of 2021, which regulated operational and commercial aspects to allow for the integration of small-scale self-generation and distributed generation to the National Interconnected System (SIN). It also regulates aspects of the connection procedure for large-scale self-generators with a maximum declared power of less than 5 MW and totally repealed CREG Resolution No. 030 of 2018 on this topic.

In December 2021, the Energy and Gas Regulation Commission issued CREG Resolution No. 215 of 2021, modifying the return rate for electricity distribution activities, and passed by CREG Resolution No. 016 of 2018, which shall be 12.09% starting in 2022.

In December 2021, the Energy Mining Planning Unit (UPME in its Spanish acronym) published Resolution No. 528 of 2021 to establish the procedures for requesting connection to the National Interconnected System (SIN) and provisions on the assignment of transport capacity to class 1 projects and how to define general parameters for the One-Stop Window.

In December 2021, through Resolution No. 647 of 2021, the National Spectrum Agency (ANE in its Spanish acronym) updated the National Table of Frequency Band Attribution, adding the frequency band of 169 MHz for the implementation of telemetric communications, wireless remote control, and the implementation of advanced measurement infrastructure networks.

d)Costa Rica

Structure and regulatory bodies of the Costa Rican Electricity System

The activities of generation, transmission, distribution, and marketing of electricity are classified by Law No. 7,593 as public services, therefore, the participation of different agents in this sector is highly concentrated in the State. In Costa Rica, there are 8 electricity distribution companies, 2 of which belong to the State and account for three-quarters of demand, another 2 are municipal companies and the remaining 4 are cooperatives. The participation of private entities (other than cooperatives) only occurs at the level of electricity generation, which is regulated by Laws No. 7,200 and 7,508.

The Ministry of the Environment and Energy (MINAE in its Spanish acronym) is in charge of preparing and coordinating public policies and programs related to the environmental and energy sectors, particularly the electricity sector, which is in charge of the Energy Subsector Planning Secretariat (SEPSE in its Spanish acronym). The SEPSE is the entity in charge of establishing and promoting national energy planning, through policies and strategic actions that guarantee the timely supply and quality of energy, thus contributing to the sustainable development of the country. Acording to Law No. 7,593, the Public Service Regulatory Authority (ARESEP in its Spanish acronym) is responsible for regulating and overseeing the quality and price of public electricity services. Law No. 7,593 grants ARESEP sufficient powers to exercise the regulation of public services provided in the country, including electricity supply for the generation, transmission, distribution, and marketing phases. The Costa Rican Electricity Institute (ICE in its Spanish acronym) is a State company that provides electricity generation, transmission, and distribution services. It is the largest electricity generator in the country and is the sole purchaser of the energy generated by private generating companies under Laws No. 7,200 and 7,508. According to its foundational Law (No. 449 of April 8, 1949), the ICE is responsible for satisfying the domestic demand for electricity. For this reason, it has the largest capacity among the country’s generating plants, mainly of a hydrological nature. In addition, the National Center for Energy Control (CENCE in its Spanish acronym) is dependent on the ICE to fulfill its responsibility for dispatching all the electricity generated for national consumption. Lastly, the ICE, the generating companies under Laws Nos. 7,200, 7,508 and 8,345 and any distribution companies that have their own generation capacity are obligated to provide the System Operator with the required information regarding their generation plants that have a capacity equal to or greater than 5 MW.

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Generating Segment

As mentioned above, the State company “Costa Rican Electricity Institute” (ICE) is the largest generator in the country and the only purchaser of the energy that is produced. To date, only rural electrification cooperatives and municipal companies can sell the energy they generate directly to customers in their concession area, as provided in Law No. 8,345.

Law No. 7,200, authorizes the private generation of electricity in Costa Rica by plants with up to 20 MW of installed capacity, as well as from hydroelectric and unconventional sources. In addition, this law establishes that it is not permitted for private electricity generation projects to exceed 15% of the total power plants that comprise the National Electric System. As an additional requirement, at least 35% of the total stock capital of any private company that wishes to generate electricity to sell to the ICE must be owned by Costa Rican citizens.

However, a second regime of private participation in electricity generation was created by Law No. 7,508, which corresponds to the second chapter of Law No. 7,200. Through a regime of “Building, Operation and Transfer” (BOT), (granted by means of a public tender), the ICE can buy up to 15% of the energy in addition to that which is authorized by Law No. 7,200, thereby amounting to 30% of the national installed capacity. The process for negotiating electric power purchase and sales contracts with private generators is carried out through the Investment Strategies Process of the National Center for Electricity Planning (CENPE in its Spanish acronym), which is dependent on the ICE. As ICE is the price setter and the only purchaser of electricity, there is no spot market or free clients.

ICE’s tariffs and its Generation System are governed by Law No. 7,593, which establishes that the tariffs (established by the ARESEP) will be based on the principle of “service at cost”, which consists of calculating an average accounting cost, to which a "development revenue” profit is added. The ICE is required to submit at least one tariff study per year, including a detailed justification for each of the items mentioned above. 

Incentives for the generation of electricity with non-conventional, renewable sources

Costa Rican legislation only authorizes the private generation of electricity based on renewable energy sources, such as hydroelectric, wind, solar and biomass. The ICE is the largest generator in the country and has a very defined policy regarding the country’s electricity planning, which must seek the maximum use of renewable resources, especially hydroelectric, as stated in article No. 1 of its creation Law.

Transmission Segment

The electricity transmission system is a natural monopoly. The administration of this system is carried out by ICE, in accordance with the expansion programs of electricity generation and distribution companies. Electricity transmission is the responsibility of the Electricity Business and Production Strategic Unit (UENPE in its Spanish acronym), which is dependent on the ICE. The electricity transmission network operates at 2 main voltage levels. The most important is the 230 kV, due to its location, which allows the transportation of large amounts of energy from the north of the country and from the Atlantic. The other transmission level (138 kV), is located in the central zone of the country, in the shape of a ring.

Distribution Segment

The role of the distribution companies is to operate as the sole seller of energy in their assigned service area as intermediaries. The purchase cost of the energy that the distributors acquire from the Generation System is transferred to the tariffs charged by the Distribution System. Since 2013, a methodology has been applied to recognize the impact of fuels on tariffs on a quarterly basis. The generation rate is adjusted beforehand to avoid duplicating this impact. This transfer to tariffs does not trigger any economic losses or financial risks on distribution companies, as the cost of generating electricity is already included in the distribution tariffs, under the regulatory principle of “Service at Cost”.

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e)Guatemala

Structure and regulatory bodies of the Guatemalan Electricity System

The Guatemalan electricity market is operated by public and private institutions. At the public level, the Ministry of Energy and Mines (MEM) dictates the National Energy Policy, the Generation and Transmission Expansion Plans and applies the General Electricity Law (LGE in its Spanish acronym). This sector’s regulatory body is the National Electric Energy Commission (CNEE in its Spanish acronym), which enforces the law and imposes sanctions, ensures compliance by awardees and concessionaires, protects users, establishes regulated tariffs, settles disputes and issues technical standards, among other responsibilities.

The system operator and market administrator act as a private non-profit company called the Wholesale Market Administrator (AMM in its Spanish acronym), by means of their Rules and Regulations. The AMM consists of electricity generators, transmitters, distributors, traders, importers, exporters and large users.

The LGE states that the Guatemalan electricity market comprises a regulated market (distributors and users that do not meet the minimum electric power demands established by the MEM) and the wholesale market (MM). Transmission and distribution tariffs are subject to regulation by the CNEE. 

In 1996, the energy industries were divided. The General Electricity Law established a separation of activities in the electricity sector and determined that generation, transmission, and distribution should be carried out by different companies. Transmission and distribution are regulated activities, in which both private and public companies may participate. To that end, concessions are granted by public tender. On the other hand, generation and commercialization of electric power has been opened up to free competition.

The electric power system consists of the National Electric System (SEN), which comprises the National Interconnected System (SNI) and some isolated systems. The operation of the SNI and all its assets is one of the responsibilities of the Wholesale Market Administrator (AMM), which is governed by the Commercial Coordination Standards and the Operating Coordination Standards. These standards include a set of provisions and procedures aimed at guaranteeing the operational coordination of the National Interconnected System (SNI), to ensure the best supply at a minimal cost, seeking to maintain the continuity and quality of the service. These standards must be approved by the National Electric Power Commission (CNEE).

Generating Segment

Generators can make direct sales to traders or Large Users. Large Users are customers whose demands exceed 100 kW, who can become free customers by voluntarily agreeing on tariffs with the Company. Another source of revenue from the sale of electricity is the wholesale market, which is governed by the rules issued by the Wholesale Market Administrator (AMM).

NaN products are traded in the Wholesale Market: Power (monthly billing) and Energy (hourly billing). This is a cost market, therefore, the assessment of the products that are traded is made according to the Variable Cost of Generation (CVG) model declared by the generating companies that are connected to the SNI. The Wholesale Market has the following operating rules:

Firm Demand and Efficient Firm Offer: In the Wholesale Market, consumers must contract their demand for electric power for a one-year term. The AMM calculates the Firm Demand (FD) on an annual basis, which must be met with an Efficient Firm Offer (EFO). The EFO is assigned to generating companies who participate in the Wholesale Market as sellers who satisfy the consumers’ FD. The EFO is determined by the AMM. It is calculated over a period of two years and is based on the actual power contributed to the SNI by each generating plant, as well as the plant’s availability when the request was made during the previous Seasonal Year.

Economic Generation Dispatch: Power generation plants must submit information regularly regarding their CVG. This is used to create a list of merit to cover the SNI’s demand, together with reserves and international commitments

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(firm contracts). This market is optimized through an “economic dispatch”, which consists of using the available supply of energy and power to supply the anticipated demand for energy and power in a given period, thereby minimizing total operational costs. The generation dispatch is optimized once every hour. The Energy Opportunity Price (EOP) or spot price is determined by the last power generation plant’s CVG that was required to meet the SNI’s demand and reserves.

Transmission services: These services include the transmission tariff (set by the CNE), which is established in accordance with the Commercial Coordination Rules.

Complementary services: The main complementary services include operating reserves for frequency regulation (primary, secondary, and tertiary), reactive power and voltage control, as well as the Black Start capability.

Forced Generation: This corresponds to any power generation that has been programmed to meet security requirements, service quality, exports, etc. that are outside the “economic dispatch”. 

Other charges: These include authorization charges to carry out transactions in the Wholesale Market (AMM fee) and authorization charges for transactions in the REM, mainly corresponding to regional institutions such as EOR and CRIE.

Transmission Segment

The electricity transmission system comprises the main system and the secondary system. The main system includes the national interconnected trunk system, the Guatemala-El Salvador interconnection, the Guatemala-Mexico interconnection, and the interconnection with Central America (SIEPAC). The secondary system consists of the electrical infrastructure used by the generators to supply the main system and the infrastructure that goes from the main system to the distribution centers. Transmission lines essentially operate at 4 voltage levels: 400 kV, 230 kV, 138 kV and 69 kV.

Distribution Segment

The distribution system consists of distribution infrastructure (distribution lines, substations and networks) that operates at voltages of less than 34.5 kV. The main components of the distribution system are coordinated by the AMM and operated by the distribution companies. The Distribution Added Value (DAV) is the remuneration received by these companies. The DAV corresponds to the average cost of capital and operation of a reference efficient distribution network. The CNEE approves a Tariff Study on the Distribution Added Value (TSDAV) and the corresponding Tariff Sheets of the Non-Social Tariff and the Social Tariff, that will be charged to the end users.

f)Panamá

Structure and regulatory bodies in the Panamanian Electricity System

Law No. 6, dated February 1997, and its amendments, establishes the regulatory and institutional framework for the provision of the public electricity service. This Law states that the activities Transmission, Distribution, Marketing and Generation of electric power regulated. The National Authority of Public Services (ASEP in its Spanish acronym) is the entity in charge of regulating, supervising and ensuring the adequate provision of these public services, thereby guaranteeing that regulated companies and clients and/or end users comply with current legal regulations, as well as exercising their rights and fulfilling their obligations.

In Panama, the transmission of high voltage electricity is carried out by Empresa de Distribución Eléctrica, S.A. (ETESA), from the delivery point by the generators to the reception point by the distribution companies or Large Customers, as appropriate. ETESA coordinates operations and transactions that take place between participants of the Wholesale Electricity Market through the National Dispatch Center (CND in its Spanish acronym), which acts as an Operator of the National Interconnected System (SIN) and Administrator of the Wholesale Electricity Market. In addition, ETESA manages the power and energy purchases for the distribution companies’ end customers.

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Distribution companies must be fully contracted two years in advance. Minimum contracting percentages are established gradually.

In order for the Panamanian electricity market to function correctly, there are Commercial and Operational Rules that all market participants must comply with. 

Generating Segment

Producing participants include generators, self-generators and co-generators that are operating in the Republic of Panama. There are several options in order to participate in the Panamanian electricity market:

● Short-term or spot market

The “Occasional Market” is the place where short-term, hourly energy transactions are carried out. These transactions allow the trading of surpluses and shortages arising from differences between contractual commitments and actual consumption and generation. The Spot Price or Marginal Cost of the System (MCS) corresponds to the variable cost of the last energy unit to be dispatched in order to meet the system’s demand without transmission restrictions. The Marginal Cost of the System (MCS) includes:

a) The Variable Cost of operations for heat generation, as defined in the Operating Regulations and declared by each generating agent. Thermal variable costs depend on the prices of fuel, transportation, operations, and maintenance. This Variable Cost is audited by the CND.

b) The value of water for hydroelectric dams, calculated by the CND in accordance with the Commercial Rules and the technical and operational rules of the Operating Regulations, as well as detailed methodologies. The value of water depends on a stochastic analysis carried out by each operator. To this end, all the variables of the system are taken into account, such as flow projection, plant maintenance and transmission networks, etc.

c) The price offered for imports in interconnection. In the case of contracts, this will be declared by the National Participant to the CND. In the case of used imports, this will be reported by the Regional Operator Entity (ROE).

d) The price offered by auto-generators and co-generators that sell electric power surpluses.

● Contract Market

Power and/or energy contracts are regulated by the ASEP through the Purchase Rules approved by AN Resolution No. 991-Elec, dated July 11, 2007, and its amendments. Only power, energy, or power and energy commitments may be agreed upon through supply contracts.

● Generation market for free customers

In Panama, a “Significant Customer” is a private individual or legal entity whose demand exceeds 100 kW per site. Power and energy acquisitions by significant customers can be made in the wholesale electricity market (in the case of a significant qualified customer) or from distributors. As of July 2014, significant, qualified customers have the option of freely negotiating the supply of energy with a Generating Agent or buying energy in the Occasional Market, while power must be acquired from a distribution company at the approved tariff.

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Incentives for the generation of electricity with non-conventional, renewable source

Legal incentives have been established to encourage small electricity power plants that use unconventional, renewable and/or clean sources. These incentives include the exemption from distribution and transmission charges in the case of small hydroelectric plants, geo-thermoelectric plants and plants using other non-conventional, renewable energy sources with a capacity of less than 10 MW, selling energy directly or in the occasional market. In addition, plants that have a capacity of between 10 and 20 MW only pay half of the distribution and transmission charges and benefit from additional tax incentives such as the exemption or reduction of import tariffs and the Tax on the Transfer of Movable Property and Provision of Services, and the Income Tax.

Transmission Segment

The electricity transmission system mainly comprises 230kW and 115 kW transmission lines. According to Law No. 6 dated February 3, 1997, the provision of the high-voltage electric power transmission service in a non-discriminatory, continuous, regular, and efficient manner is the responsibility of ETESA. This company is governed by rules that are applicable to public limited companies under private law, but its stock capital is 100% owned by the State of Panama.

Distribution Segment

The electricity distribution service includes transporting electricity through the distribution networks, as well as delivering and marketing energy to end customers. Distribution is a monopolistic activity and therefore, it is regulated. Electricity sales to end customers are remunerated with regulated tariffs.

The added value of distribution consists of the following costs: distribution system administration, operation and maintenance, a reasonable rate of return on investments, and a compensation for distribution assets and their depreciation.

g)  Peru

Structure and regulatory bodies in the Peruvian Electricity System

The main laws that regulate the Peruvian electricity market are the Electricity Concession Law (Law No. 25,844), its regulations and the Law ensuring the Efficient Development of Electricity Generation (Law No. 28,832).

Law No. 25,844, the Electricity Concession Law, indicates that the Peruvian electricity sector is divided into three large segments: generation, transmission and distribution, such that no more than one activity can be developed by the same company. The Peruvian electricity system is known as the National Interconnected Electricity System (SEIN), in addition to some isolated electricity systems.

Electricity Generation

The generation companies’ operations is subject to the provisions and policies of the Economic Operations Committee for the National Interconnected System (COES SINAC) for the purpose of coordinating their operations at minimum cost, guaranteeing the secure, reliability and continuity supply of electricity and best use of energy resources.

The sale of energy by generators to distributors for the purpose of the public supply of electricity, shall be performed through bids or bilateral contracts (with a regulated maximum price set by the Peruvian electricity regulator, the OSINERGMIN - bar rate). The bid mechanism has the purpose of establishing a system that promotes investments in new generation capacity through long-term electricity supply contracts and firm rates with distribution companies. On the other hand, generators can contract directly with free customers, with whom they agree on energy sales prices. 

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Renewable Energy

Legislative Decree No. 1,002 created a promotional regime for non-conventional renewable energy sources (“RER”) through auctions to develop specific technologies that seek to cover up to 5% of the national energy demand with a guaranteed income mechanism paid by customers through a tariff charged in the connection fee.

Transmission Segment

Electricity transmission consists of transmission lines, substations, and equipment for the transportation of electricity from the generating plants to the consumption or distribution centers. In Peru, electricity transmission includes all lines and substations with a capacity that is greater than 60 kV.

The transmission activity is carried out in the Main Transmission System and the Secondary Transmission System regulated by the provisions of the Electricity Concession Law. It also includes the Guaranteed Transmission System and the Complementary Transmission System, as established in the Law Ensuring the Efficient Development of Electricity Generation. The Peruvian transmission system is overseen by the regulator "OSINERGMIN".

Distribution Segment

The electricity distribution activity is subject to a regulated tariff and a concession to operate within a geographic zone.

In Peru, the process for the determination of the distribution rate is carried out every 4 years, and is called “Value Added Distribution Fixation” (“VAD”). Exceptionally, the last process lasted 5 years, since one year was required to implement the last reforms approved by Legislative Decree No. 1,221.

It should be noted that the Peruvian regulation follows the regulatory scheme of an efficient model company, so that in each tariff period the efficient investment costs are established, as well as the standard operation and maintenance costs that will be recognized to each distribution company under the parameters and criteria defined by the OSINERGMIN (regulatory body). An “efficient business” model has been created to establish the distribution tariff. Based on this model, individual tariffs are determined for each distribution company that has more than 50,000 customers.

The current tariff chart corresponds to the 2018-2022 period.

h)Regional Electricity Market (REM) for Central American Companies

The Central American Electricity Market includes two essential elements:

The creation and implementation of the Regional Electricity Market (the REM), which is a supranational wholesale market that serves as the basis for investment in the integrated electricity transmission system; and

The development and construction of the first regional transmission system. This system delivers the physical assets for the operation of the REM. 

The regulation of the REM is contained in a series of legal and administrative instruments, including the Central American Electricity Market Framework Treaty and its Protocols; the Regulation of the Regional Electricity Market (“RREM”) and the Normative Resolutions of the Regional Electric Interconnection Commission (“REIC”). These instruments define the operating principles for the REM and establish: (i) the creation of the “REIC”, as the entity that is responsible for regulating commercial relations between public and private agents that are connected to the regional electricity system, and setting the remuneration and pricing mechanisms of the exchange and transportation of energy, among other functions; (ii) the creation of the Regional Operator Entity (“ROE”) which is in charge of coordinating the technical and commercial operation of energy exchanges between the agents of the Central American countries in its capacity as operator and administrator of the system and the regional electricity market; and (iii) the creation of the

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Regional Electricity Market Directive Council (“REMDC”), which is a political entity that is responsible for promoting the development of the REM and facilitating compliance with the objectives of the Central American Electricity Market Framework Treaty and its Protocols, as well as coordinating relations with the other regional stakeholders.

These regulations have defined the REM as a regional wholesale electricity market whose organization and operation are based on the following principles:

- Its commercial electricity transactions may arise from: i) occasional transactions resulting from a specific offer, and ii) contracts between market agents.

- With the exception of transmitters, Market agents can buy and sell electricity freely, thereby guaranteeing the free transit of electricity through the networks of the REM member countries.

- Market agents can install generation plants in any of the REM member countries for trade and access to regional transmission networks (except for Costa Rica, which only recognizes the Costa Rican Electricity Institute as agent).

- Although the REM is a market with its own rules (independent from those of the national markets in the member countries), its operations are carried out through the infrastructure of the Regional Transmission Network (“RTN”), which includes the national networks.

- REM electricity transactions are carried out in two types of market:

Regional Contracts Market: This market comprises all the contracts for the injection and withdrawal of electricity in the REM that agents have entered into. Depending on their supply priority, these contracts can be Firm Contracts or Non-Firm Physical-Flexible Contracts (“NFPFC”). Firm Contracts entail being a holder of Firm Transmission Rights (“FTR”). These FTR assign their holder the right (but not the obligation) to inject power into a node and to withdraw it in another node of the RTN during a valid period. These rights will essentially depend on the operational capacity of the regional transmission network, for which monthly and annual auctions are held where Agents registered in the Regional Electricity Market can bid to acquire them.

The Minimum Prices for the acquisition of FTR are set by the ROE, according to the current methodology. In cases where two or more FTR offers have the same RTN injection and withdrawal nodes, the rights will be assigned according to the established optimization model.

When FTR are not available, electricity transactions can still be made through Non-Firm Physical-Flexible Contracts (“NFPFC”), which are subject to Variable Transmission Costs resulting from network congestion.

The Regional Contract Market provides agents with instruments that allow them to manage energy supply and price risks in the REM and enables long-term investments in regional infrastructure. In addition, agents are free to set prices and other contractual conditions. 

Regional Opportunity Market: This is a short-term market based on daily offers of electricity injection and withdrawal in the enabled nodes of the RTN during a “Market Period” (which lasts one hour). The Regional Opportunity Market includes specific transactions that are scheduled one day in advance, as well as transactions that occur as a result of real-time deviations of scheduled electricity injections and withdrawals in each Market Period.

Electrical Interconnection System for Central American Countries (“EISCAC”): The Electrical Interconnection System for Central American countries consists of 230 kW infrastructure through 1,800-kilometer transmission lines that cross Guatemala, El Salvador, Honduras, Nicaragua, Costa Rica and Panama, with a total transmission capacity of 300 MW. The EISCAC has been developed by the Network Owner Company ("NOC"), a company whose main shareholders are the state electricity companies of each of the MEM countries and some minority private interests.

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ii.Limits on integration and concentration

In general, every country has legislation for the defense of free competition, which, together with the specific regulations on the electricity market, define criteria to avoid excessive levels of economic concentration and/or abusive market practices. However, this is not the case in Costa Rica, where electricity generation, transmission and distribution are concentrated in State-owned companies, with a very limited space for private companies in the generation sector. This is subject to restrictions such as the fact that they cannot exceed 15% of the total generation capacity and 35% of the property of these private companies must remain in Costa Rican hands.

In principle, the regulators allow the participation of companies in different activities (e.g. generation, distribution, and commercialization) as long as there is an adequate separation of each activity, for both accounting and company purposes. Nevertheless, most of the restrictions imposed involve the transmission sector mainly due to its nature and to the need to guarantee adequate access to all agents. In Argentina and Colombia, there are specific restrictions if generation or distribution companies want to become majority shareholders in transmission companies. In the case of centre america, to the strong estatal concentration of Costa Rica is added the also concentrated transmision activity in Panama.

Regarding concentration in a specific sector, in Argentina, there are no specific limits that affect the vertical or horizontal integration of a company. In Peru, integration is subject to the authorization of the Instituto Nacional de Defensa de la Competencia y Protección de la Propiedad Intelectual (“INDECOPI”), an antitrust authority that is able to establish commercial conduct. In Colombia, no company may have a direct or indirect market share of over 25% in electricity sale activities. In May 2019, Law No.1,955 of the National Development indicates that in order to ensure the sustainability of the provision of the service on the Caribbean Coast, the limits on the participation in the commercialization activity may be higher, than the current regulatory limit by possibly as much as 10 additional percentage points.

One of these relates to participation limits depending on market concentration (HHI) and the size of the players according to their Firm Energy, and the other relates to pivotally conditions in the market depending on the availability of resources to meet system demand. In addition, Colombian companies created after the Public Service Law was enacted in 1994 can only engage in activities that complement generation/sales and distribution/sales. Finally, in Brazil, with the changes taking place in the power industry under Law No. 10,848/2004 and Decree No. 5,163/2004, the ANEEL gradually perfected regulations, eliminating concentration limits as no longer compatible with the prevailing regulatory environment. However, regulatory approval is required for consolidations or mergers to take place between players operating within the same business segment. 

iii.Unregulated customers market

In all of the countries where the Group operates, distributing companies can supply their customers under regulated or freely-agreed conditions. The supply limitations imposed on the unregulated market are as follows:

Country	kW threshold
Argentina	>30 kW
Brazil	>2,000 kW or >500 kW (1)
Colombia	>100 kW or 55 MWh/month
Costa Rica	Not applicable (2)
Guatemala	>100 kW
Panamá	>100 kW
Peru	>200 kW (3)

(1) The > 500 kW limit is applied if energy from renewable sources is purchased, which is encouraged by the government through a toll discount.

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(2) In Costa Rica there is only one electricity purchaser, which is the ICE, therefore, there is no concept of a free customer.

(3) D.S. 018-2016-EM established that:

•The demand of customers that can opt between the regulated and free market (those with demand from 200 to 2,500 kW) is measured at each point of supply.

•Customers whose demand at each point of supply is greater than 2,500 kW are necessarily free customers.

5. BUSINESS COMBINATION UNDER COMMON CONTROL

Reorganization and corporate integration of non-conventional, renewable energy generating companies in Central and South America (except for Chile)

On September 21, 2020, the Board of Directors of Enel Américas unanimously decided to initiate the merger process for  the incorporation of EGP Américas SpA (“EGP Américas”) into Enel Américas (the “Merger”). By virtue of this Merger, Enel Américas would acquire all of EGP Américas’ assets and liabilities and succeed to all of EGP Américas’ rights and obligations, allowing the Company to control and consolidate the ownership of the business and the non-conventional renewable energy generation assets developed and held by Enel Green Power S.p.A. in Central and South America (except for Chile).

This Merger became effective on April 1, 2021 and is in line with the Group’s strategy and development plans, considering the high priority of the development of renewable energies in the region. The Merger also enables accelerating the positioning of Enel Américas in the energy transition scenario, making it the leading company in Central and South America in power generation and distribution. As a result, Enel Américas has strengthened its renewable energy generation and has also diversified it geographically through the incorporation of assets in Costa Rica, Guatemala and Panama, as well as including new assets in other South American countries where it was already operating. Consequently, Enel Américas has increased its capacity in the region by 5 GW (including operating capacity and under-construction). A pipeline will also be assessed during the course of operating activities.

i)Capital increase

At the extraordinary shareholders’ meeting held on December 18, 2020, the shareholders approved the following:

In order to complete the Merger, the Board approved a capital increase at Enel Américas of ThUS$ 6,036,421 through the issuance of 31,195,387,525 new common shares of a single-series as existing shares and with 0 par value. These will be fully subscribed and paid for in exchange for the incorporation of the EGP Américas equity, as the absorbed company, upon the Merger’s effectiveness. For this purpose, 0.41 Enel Américas shares will be delivered for each share of EGP Américas held by EGP Américas’ single shareholder, not considering fractions of shares (see Note 26.1).

The Merger was subject to compliance with certain suspensive and connected conditions precedent agreed at the Shareholders’ Meeting, which also established that it would become effective on the first day of the month following the date on which the Merger was declared, by means of a single public deed, to be granted by Enel Americas and EGP Américas, unless such deed was granted after March 31, 2021, in which case, the effective date of the Merger would be the day after the date of execution of the deed of merger.  

On March 5, 2021, compliance with all conditions precedent has been verified and Enel Américas and EGP Americas confirmed the deed of merger. As a result, the merger by absorption of EGP Americas into Enel Américas was completed on April 1, 2021 and the following companies were incorporated as new subsidiaries of Enel Américas:

• Enel Green Power Brasil Participacoes Ltda.

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• Enel Green Power Costa Rica S.A.

• Enel Green Power Colombia S.A.S ESP.

• Enel Green Power Guatemala S.A.

• Enel Green Power Panamá S.R.L.

• Enel Green Power Perú S.A.C.

• Enel Green Power Argentina S.A.

• Energía y Servicios South América SpA.

• ESSA2 SpA.

On the same date, all the amendments to Enel Américas’ bylaws approved by the aforementioned Shareholders’ Meeting became effective. These amendments include the capital increase, the elimination of the limitations and restrictions established in the bylaws by application of Title XII of Decree Law No. 3,500 of 1980 (except solely for the Investment and Financing Policy, which remains in force). These also included the amendment that establishes that a shareholder and their related persons cannot concentrate more than 65% of Enel Américas’ voting shares.

After the merger of Enel Américas S.A. and EGP Americas was completed, Enel SpA became the owner of 75.18% of Enel Américas’ share capital.

The accounting record of this Merger was recognized in accordance with the accounting criteria established in Note 2.7.5. This gave rise to a credit in “Other miscellaneous reserves”, in Enel Américas’ consolidated equity, of ThUS$1,259,422 (see Note 26.5.c).

From the date of the Merger, the companies that were part of the EGP Americas have contributed revenues of ThUS$832,030 and after-tax profits of ThUS$109,226 to Enel Américas’ consolidated results for the nine-month period ended on December 31, 2021. Management has estimated that had the Merger been performed on January 1, 2021, Enel Américas’ consolidated revenues would have increased by ThUS$1,013,717, and consolidated after-tax profits would have decreased by ThUS$96,153.

ii) The right to withdraw

In accordance with the provisions of Article 69 of Chilean Law No. 18,046 on Public Companies, shareholders who disagreed with the Merger had the right to withdraw from Enel Américas, receiving payment for the value of their shares. On January 17, 2021, the legal period available to dissenting shareholders expired and they exercised their right to withdraw a total of 1,809,031 shares issued by the Company, equivalent to 0.002% of the total share capital. In accordance with current legislation and the terms and conditions approved by the Shareholders’ Meeting, the price of these shares was paid by Enel Américas for ThUS$272 on March 8, 2021, including adjustments and interest. Consequently, one of the conditions precedent to which the effectiveness of the Merger was submitted was met, i.e., that the right to withdraw duly exercised by dissenting shareholders should not exceed 10% of the voting shares.

iii)Public Offer for Share Acquisition

In connection with the Merger, Enel SpA formally announced the start of the voluntary public tender offer for the acquisition of up to 7,608,631,104 shares issued by Enel Américas S.A. on March 15, 2021, (including shares represented by American Depositary Shares “ADS”) equivalent to 10% of the Company’s share capital as of such date (the “Offer”). This Offer began on March 15 and ended on April 13, 2021 and resulted in Enel SpA’s acquisition of 6,903,312,254 shares (including 705,246,850 shares represented by 14,104,937 ADS). 

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Following the purchase of the shares and ADS through the Offer, Enel SpA increased its interest in Enel Américas’ stock capital from 75.18% to approximately 82.3%.

iv)Assets acquired and liabilities assumed at the acquisition date

ASSETS	04-01-2021 ThUS$	LIABILITIES AND EQUITY	04-01-2021 ThUS$
CURRENT ASSETS		CURRENT LIABILITIES
Cash and cash equivalents	1,022,668	Other current financial liabilities	82,246
Other current financial assets	30,763	Current lease liabilities	3,330
Other current non-financial assets	214,326	Trade and other payables, current	229,345
Trade and other receivables, current	132,704	Current accounts payable to related parties	309,110
Current accounts receivable from related parties	203,814	Other current provisions	1,160
Inventories	12,846	Current tax liabilities	13,967
Current tax assets	16,804	Other current non-financial liabilities	23,802
Total current assets other than assets or groups of assets for disposal classified as held for sale	1,697	TOTAL CURRENT LIABILITIES	662,960
TOTAL CURRENT ASSETS	1,635,622
		NON-CURRENT LIABILITIES
		Other non-current financial liabilities	843,254
NON-CURRENT ASSETS		Non-current lease liabilities	27,762
Other non-current financial assets	164,550	Trade payables, non-current	21,315
Other non-current non-financial assets	47,805	Non-current accounts payable to related parties	134,333
Trade and other non-current receivables	23,081	Other long term provisions	28,990
Intangible assets other than goodwill	333,605	Deferred tax liabilities	91,753
Goodwill	587,357	Non-current provisions for employee benefits	1,237
Property, plant and equipment	3,952,409	Other non-current non-financial liabilities	8,590
Right-of-use assets	31,039	TOTAL NON-CURRENT LIABILITIES	1,157,234
Deferred tax assets	67,780	TOTAL LIABILITIES	1,820,194
TOTAL NON-CURRENT ASSETS	5,207,626
TOTAL ASSETS	6,843,248	TOTAL NET ASSETS ACQUIRED	5,023,054

6.  CASH AND CASH EQUIVALENTS

a) The details of cash and cash equivalents as of December 31, 2021 and 2020 are as follows:

	Balance as of
Cash and Cash Equivalents	12-31-2021 ThUS$	12-31-2020 ThUS$
Cash balances	290	308
Bank balances	518,572	641,870
Time deposits	841,039	749,671
Other fixed-income instruments	36,352	115,144
Total	1,396,253	1,506,993

Time deposits have a maturity of three months or less from their date of acquisition and accrue the market interest for this type of short-term investment. Other fixed-income investments are mainly comprised of resale agreements maturing in 90 days or less from the date of investment. There are no restrictions for significant amounts of cash availability.

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b) The detail of cash and cash equivalents by currency is as follows:

	Balance as of
Currency	12-31-2021 ThUS$	12-31-2020 ThUS$
Chilean peso	1,588	637
Argentine peso	8,025	65,480
Colombian peso	150,799	381,754
Brazilian real	757,659	741,282
Peruvian sol	129,607	147,458
U.S. dollar	348,413	170,335
Euros	162	47
Total	1,396,253	1,506,993

For more details on the Statement of Cash Flows, see below.

c) The following table records the components of “Other payments for operating activities” line item in the Statement of Cash Flows:

Other Payments from Operating Activities	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$
Payment for other taxes (VAT, ICMS, PIS/COFINS, Sales taxes, Custom taxes, taxes on bank transfers) (1)	(2,704,477)	(2,587,437)	(3,613,564)
Payments for collections made under Codensa Hogar contract (2)	(480,921)	(349,481)	(578,708)
Payments for the Energy Development Account (CDE) (3)	(839,175)	(736,116)	(1,148,756)
Other miscellaneous itemized payments for operating activities (4)	(455,381)	(340,754)	(382,405)
Total other payments from operating activities	(4,479,954)	(4,013,788)	(5,723,433)

(1) The main components of payments for other taxes are the following:

● ICMS: This is a state value added tax (VAT) in Brazil, applied on the sale of telecommunications and transportation goods and services. The ICMS payments were ThUS$ 2,254,373, ThUS$ 2,025,223 and ThUS$ 2,672,785 for the years ended December 31, 2021, 2020 and 2019, respectively.

● PIS/COFINS taxes. In Brazil, the “Programa de Integração Social” (PIS) is a social contribution tax, payable by corporations, targeted to finance the payment of unemployment insurance and allowance for low paid employees, while the “Contribuição para o Financiamento da Seguridade Social” (COFINS) is a federal contribution tax, based on gross revenues of business sales. The total amounts paid for PIS/COFINS were ThUS$ 327,634, ThUS$ 442,734 and ThUS$ 827,589 for the years ended December 31, 2021, 2020 and 2019, respectively.

● Payment for taxes on sales in Peru for ThUS$ 83,107, ThUS$ 86,768 and ThUS$ 85,089 for the years ended December 31, 2021, 2020 and 2019, respectively.

(2) Our Colombian subsidiary Codensa entered into an arrangement with a third party that develops a business with Codensa’s customers. By virtue of this arrangement, Codensa manages the collection of that third party’s receivables, since they are billed as part of the Codensa’s invoices issued monthly. The payments are related to the monthly collected amounts under the collection management contract, whereas the collections are presented in the line item “Other collections from operating activities”.

(3) In Brazil, Law No. 10,438/2002 created the “Conta de Desenvolvimento Energético” (“CDE”). The CDE is a government fund that aims to promote the development of alternative energy sources, promote globalization

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of energy services and subsidizes low-income residential customers. The fund is financed through charges included in consumers and generators tariffs and government contributions.

(4) Other miscellaneous payments for operating activities includes several types of individually non-significant payments related to operating activities

d) Other cash inflows (outflows) from (used in) investment activities are detailed as follows:

Other payments from investment activities	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$
Cash and Cash equivalents merger with EGP Americas (1)	1,022,668	—	—
Other payments used in investment activities	(13,043)	(4,369)	(7,263)
Total other payments from investment activities	1,009,625	(4,369)	(7,263)

(1) Beginning balance of cash and cash equivalents resulting from the merger by absorption of EGP Américas into Enel Américas (see Note 5).

e) Reconciliation of liabilities arising from financing activities as of December 31, 2021, 2020 and 2019:

		Cash flows from financing					Movements that do not represent cash flows
Liabilities from financing activities	1-1-2021	From	Used	Paid interest	Total	Acquisition of subsidiaries	Movements in fair value	Exchange differences	Financial costs (1)	New financial leases	Other movements	31-12-2021
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Short-term loans	1,975,028	1,306,898	(3,301,621)	(334,975)	(2,329,698)	219,817	7,455	(122,726)	457,536	—	1,357,742	1,565,154
Long-term loans	4,018,731	2,695,229	(12,711)	—	2,682,518	972,354	14,233	(334,779)	16,249	—	(1,359,537)	6,009,769
Lease liabilities	142,560	—	(65,009)	(4,003)	(69,012)	31,092	—	(12,934)	2,918	135,283	18,671	248,578
Assets held to cover liabilities arising from financing activities	(114,309)	114,230	—	—	114,230	(134,315)	(12,366)	(63,350)	24,942	—	(15,331)	(200,499)
Total	6,022,010	4,116,357	(3,379,341)	(338,978)	398,038	1,088,948	9,322	(533,789)	501,645	135,283	1,545	7,623,002

		Cash flows from financing					Movements that do not represent cash flows
Liabilities from financing activities	1-1-2020	From	Used	Paid interest	Total	Acquisition of subsidiaries	Movements in fair value	Exchange differences	Financial costs (1)	New financial leases	Other movements	31-12-2020
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Short-term loans	1,422,681	1,359,012	(1,689,240)	(320,948)	(651,176)	—	3,990	(80,673)	323,080	—	957,126	1,975,028
Long-term loans	4,818,468	582,583	(91,207)	—	491,376	—	9	(516,196)	9,757	—	(784,683)	4,018,731
Lease liabilities	190,269	—	(77,292)	(5,755)	(83,047)	—	—	(15,290)	9,286	45,639	(4,297)	142,560
Assets held to cover liabilities arising from financing activities	(67,937)	114,004	—	—	114,004	—	9,691	(152,874)	(15,286)	—	(1,907)	(114,309)
Total	6,363,481	2,055,599	(1,857,739)	(326,703)	(128,843)	—	13,690	(765,033)	326,837	45,639	166,239	6,022,010

		Cash flows from financing				Movements that do not represent cash flows
Liabilities from financing activities	1-1-2019	From	Used	Paid interest	Total	Acquisition of subsidiaries	Movements in fair value	Exchange differences	Financial costs (1)	New  leases	Other movements	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Short-term loans	4,264,806	3,401,133	(7,150,100)	(605,522)	(4,354,489)	—	4,812	8,608	571,136	—	927,808	1,422,681
Long-term loans	4,535,549	1,525,820	(297,385)	—	1,228,435	—	—	(50,138)	—	—	(895,378)	4,818,468
Lease liabilities	121,973	—	(59,177)	(9,077)	(68,254)	—	—	10,866	11,666	114,963	(945)	190,269
Assets held to cover liabilities arising from financing activities	(113,974)	95,512	—	—	95,512	—	(10,363)	(32,030)	—		(7,082)	(67,937)
Total	8,808,354	5,022,465	(7,506,662)	(614,599)	(3,098,796)	—	(5,551)	(62,694)	582,802	114,963	24,403	6,363,481

(1)This relates to accrual of interest.

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7.  OTHER FINANCIAL ASSETS

The detail of other financial assets as of December 31, 2021 and 2020 is as follows:

	Balance as of
	Current		Non-Current
Other Financial Assets	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$
Financial assets at fair value through profit or loss (1)	156,171	118,383	26,193	25,460
Financial assets measured at amortized cost (1)	50,941	13,827	—	—
Financial assets at fair value with changes in results IFRIC 12 (2)	—	—	2,978,228	2,468,149
Financial assets at fair value with changes in other comprehensive income	—	—	2,155	268
Financial assets measured at amortized cost IFRIC 12 (3)	72,226	10,283	294,695	267,351
Hedging derivatives (4)	32,689	86,465	171,905	29,635
Non-hedging derivatives (5)	3	1,321	—	—
Total	312,030	230,279	3,473,176	2,790,863

(1) The amounts included in financial assets measured at fair value with changes to profit and loss and financial assets at amortized cost mainly correspond to time deposits and other highly liquid investments that are easily convertible in cash and are subject to low risk of change in their value but that do not strictly meet the definition of cash equivalents as defined in Note 3.g.2 (for example with maturity date above 90 days at the time of investment).

(2) Corresponding to concession agreements that include Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Goias S.A, Enel Distribución Sao Paulo S.A. and PH Chucás S.A. with balances as of December  31, 2021 of ThUS$ 949,250 (ThUS$ 831,941, as of December 31, 2020), ThUS$ 702,439 (ThUS$ 582,649 as of December 31, 2020), ThUS$ 78,095 (ThUS$ 43,318 as of December 31, 2020), ThUS$ 1,134,209 (ThUS$ 1,010,241 as of December 31, 2020) and ThUS$ 114,235 (ThUS$ 0 as of December 31, 2020,) respectively. The current legislation in effect, among other aspects, establishes that the government in its capacity of grantor will use the New Replacement Value (VNR) in order to pay the applicable amounts to concession companies as compensation for those assets not amortized at the end of the concession term. On a monthly basis, distributors adjust the carrying amount of financial assets, once the present value of the estimated cash flows have been computed, using the rate of interest in effect for the payment corresponding to the end of concession; see Note 2.2.c and 3.d.1. For Chucás, financial assets relate to the rights receivable from Instituto Costarricense de Electricidad (ICE), generated under the context of the application of the concession agreement with such entity.

(3) Corresponding to the concession agreement in Enel Green Power Project I (Volta Grande) Fontibon ZE S.A.S., Luz de Angra Energía S.A., EGP Paranapanema, EGP Mourao and Usme ZE S.A.S; see Note 3.d.1.

(4) See Note 22.2.a)

(5) See Note 22.2.b)

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8. OTHER NON-FINANCIAL ASSETS AND LIABILITIES

a) The detail of other non-financial assets as of December 31, 2021 and 2020, is as follows:

	Balance as of
Other non-financial assets	Current		Non-Current
	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$	ThUS$	ThUS$	ThUS$
VAT Credit and Other Taxes	121,759	68,200	130,510	118,268
Contributions fund to Enel Distribución Goiás (1)	26,823	7,536	129,126	180,824
Ongoing services provided by third parties	15,891	9,993	—	—
Ongoing I & D and Energy Efficiency service	96,449	90,349	—	—
Judicial Deposits	—	—	267,838	267,266
Assets under construction IFRIC 12 (2)	—	—	585,715	314,825
Recoverable taxes - Pis/Cofins (3)	411,066	211,611	1,952,001	1,366,883
Prepaid expenses	31,310	53,783	—	—
Other	125,462	119,314	80,231	84,790
Total	828,760	560,786	3,145,421	2,332,856

(1) Through Law No. 17,555 of January 20, 2012, the state of Goiás in Brazil created the Contribution Fund for Enel Distribución Goiás (Fundo de Aporte à CELG D - FUNAC), regulated by Decree No. 7,732, dated September 28, 2012, with the purpose of collecting and allocating financial resources for reimbursement to Enel Distribución Goiás of the payments of contingencies of any nature which had taken place up until the transfer of equity control to Eletrobrás, which occurred during January 2015, according to the terms of the agreement between the shareholders and the management, as well as FUNAC’s cooperation terms. The resources of the aforementioned fund depend on the contributions made by the government of the State of Goiás and the credits received for lawsuits won by Enel Distribución Goiás, which occurred during January 2015, which are reimbursed to the respective fund.  

During 2019, the State of Goiás enacted a law, which limits the period of coverage of Law No. 17,555, from January 2015 to April 2012. The Group is taking all appropriate measures to maintain the rights acquired at the time of the purchase of Enel Distribución Goiás, which are guaranteed by the State of Goiás itself, as established in the purchase and sale agreement signed on February 14, 2017. The appeals presented by the Group argue that the right to the guarantee is legal and contractual, given that the actions of the State of Goiás are clearly illegal, and the possibility that the legal actions will not result in a favorable ruling for the Company are considered remote. (see Note 34.3.b.11).

In addition, since the resources are not final, as of year-end 2021 and 2020 an impairment loss was recognized in the amount of ThUS$ 16,786 and ThUS$ 14,479, respectively, corresponding to the amount of accounts receivable generated from April 2012 to January 2015. For this same reason, during 2019 an impairment loss of ThUS $ 110,774 was recognized.

(2) Corresponds to assets under construction referring to concessions of the subsidiaries Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Goiás S.A. and Enel Distribución Sao Paulo S.A.

(3) In March 2017, the Federal Supreme Court of Brazil (STF) resolved a matter of general applicability, related to the calculation of PIS and COFINS taxes. The STF confirmed the view that the ICMS tax should not be part of the base for calculation of PIS and COFINS taxes; however, the Brazilian federal government filed an appeal, in order to determine the temporary effects and make some clarifications. 

In May 2021, the Brazilian Federal Supreme Court (BFSC) ruled the appeal and confirmed that the ICMS tax that should be considered corresponds to invoiced ICMS and not paid-in ICMS. In addition, the Court established that the effects of this ruling will be backdated to the March 2017 ruling, except for taxpayers who filed an individual claim before such date. The BSFC is expected to publish this ruling in the Official Gazette in the coming months.

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Our subsidiaries in Brazil that were affected by the resolution of the STF, filed legal actions in this sense, in the related Federal Regional Courts. In 2019, Enel Distribución Sao Paulo and Enel Distribución Ceará were notified of the final decisions issued by those Courts, recognizing their right to deduct the ICMS applied to their own operations from the calculation bases of the PIS and COFINS, for the periods from December 2003 to December 2014 for Enel Distribución Sao Paulo, and from May 2001 and thereafter for Enel Distribución Ceará. In March 2020, Enel Distribución Sao Paulo received a similar notification for the period from January 2015 and thereafter. During March 2020, Enel Distribución Sao Paulo received a similar notification for the period January 2015 and thereafter. In March 2021, Enel Distribución Goiás received the same communication for the period between 2006 and 2021. Finally, during September 2021 Enel Distribución Río received the same notification, covering the rights arising for the period from December 2003 and thereafter.

Considering various analyses both internal and provided by legal advisors, as well as the best estimates available, Enel Distribución Sao Paulo, Enel Distribución Ceará, Enel Distribución Goiás and Enel Distribución Rio recognized assets in the amount of ThUS$ 1,064,948, ThUS$ 187,727, ThUS$ 533,824 and ThUS$ 576,566, respectively, as of December 31, 2021 (ThUS$ 1,326,297, ThUS$ 252,197, ThUS$ 0 and ThUS$ 0, respectively, as of December 31, 2020).

Since the excess payment of the PIS and COFINS taxes was passed down to the end customers at the time, simultaneous to recognizing these recoverable taxes, our subsidiaries have recognized a regulatory liability for the same amounts indicated above, net of any cost incurred or to be incurred by the Companies in these legal proceedings. These liabilities represent the obligation to reimburse the taxes recovered to the end customers.

The Group will adopt the tax credit recovery procedures in accordance with legal provisions. The transfer to consumers will depend on the effective use of the tax credit by the Companies and will take place in accordance with the regulations of the Agencia Nacional de Energía Eléctrica (ANEEL).

It is important to note that the PIS and the COFINS are federal contributions paid by companies in Brazil intended to finance programs for employees, public health, social assistance and social security and are applied to the gross income of the companies. The “tax on movement of goods and services” (ICMS) is a state value-added tax (VAT) in Brazil, applied to the sale of telecommunications and transportation goods and services. (See Notes 23 and 34.3.b.16).

b) The detail of other non-financial liabilities as of December 31, 2021 and 2020, is as follows:

	Balance as of
Other non-financial liabilities	Current		Non-Current
	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$	ThUS$	ThUS$	ThUS$
VAT Credit and Other Taxes	251,358	230,395	75,814	48,266
Other	34,914	36,209	58,758	68,695
Total	286,272	266,604	134,572	116,961

F-77

9. TRADE AND OTHER RECEIVABLES

a) The detail of trade and other receivables as of December 31, 2021 and 2020, is as follows:

	Balance as of
	Current		Non-Current
Trade and Other Receivables, Gross	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$
Trade and other receivables, gross	4,550,361	3,924,946	784,354	643,923
Trade receivables, gross	4,307,971	3,693,052	497,193	354,376
Accounts receivable from finance leases, gross	913	584	13,742	8,214
Other receivables, gross	241,477	231,310	273,419	281,333
	Balance as of
	Current		Non-Current
Trade and Other Receivables, Net	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$
Trade and other receivables, net	3,711,141	3,234,935	724,851	578,524
Trade receivables, net	3,469,608	3,008,544	464,855	289,361
Accounts receivable from finance leases, net	889	568	13,377	8,000
Other receivables, net	240,644	225,823	246,619	281,163

	Balance as of
	Current		Non-Current
Detail of other accounts receivable, net (1)	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$	ThUS$	ThUS$	ThUS$
Advances to suppliers	85,139	28,441	6,203	—
Accounts receivable "low income" (i)	17,971	27,593	—	—
Accounts receivables from employees	7,769	7,869	11,857	12,798
Receivables VOSA project (ii)	44,898	43,800	226,047	268,075
Subsidy and contribution mechanisms	5,358	33,545	—	—
Other	79,509	84,575	2,512	290
Total	240,644	225,823	246,619	281,163

(i) Accounts receivable from “low income” consumers to which a social discount is applied creating a “low income” final tariff, in which the Brazilian government replenishes such discount to our subsidiaries Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Goias and Enel Distribución Sao Paulo S.A. through a government subsidy.

(ii) Account receivables related to the Argentine Project.

Brazilian sector assets

Regulatory (or industry-wide) assets and liabilities are recorded as a result of the signing in December 2014 of significant amendments to the original concession agreements entered into by our electricity distribution subsidiaries in Brazil. These amendments established that, in addition to the compensation amounts derived from investments not amortized during the respective concession periods (see Note 8 (2)), the balances of regulatory assets and liabilities that had not been recovered or returned through the tariff cycles will also be subject to compensation or return by the Brazilian government. This implies that the realization of these assets or the settlement of liabilities does not depend on the invoicing made to customers during the concession period. 

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These regulatory assets and liabilities arise from the differences between the actual cost and the cost considered in the tariff adjustments and generate an asset to the extent that the actual cost is greater than the one considered in the tariff, or a liability when the actual costs are lower than those considered in the tariff. These differences are considered by ANEEL, which is the government entity that regulates electricity tariffs in Brazil, in the subsequent tariff adjustment process of each concessionaire company.

In general, as a result of the normal operation of the companies, these regulatory assets and liabilities are collected or settled through invoices to customers over a period that is on average between 10 and 24 months.

CONTA-COVID

On May 18, 2020, Decree No. 10,350 was issued in the Official Gazette of Brazil, which authorized the creation of CONTA-COVID, which establishes a cash-advance mechanism for electricity distribution companies in respect to accounts receivable already accrued, which under normal circumstances would be recovered through future customer billing, once the corresponding tariff update processes have been carried out. The CONTA-COVID is managed by the Electric Energy Commercialization Chamber – CCEE.

CONTA-COVID is regulated by Regulatory Resolution No. 885 issued by the Ministry of Mining and Energy, dated June 23, 2020, and its funds were obtained through a “sectorial loan”, entered into by a group of banks. The CCEE centralized the contracting of loan transactions and transferred the funds to the electricity distribution companies, in accordance with the limit established by ANEEL for each company.

CONTA-COVID guarantees the economic resources necessary to compensate for the loss of income due to the pandemic and to protect the rest of the electricity sector’s production chain, by allowing electricity distribution companies to continue complying with their contracts. Additionally, CONTA-COVID avoided significant adjustments in electricity tariffs, since without this mechanism, there would have been an impact for consumers in the next readjustments, with payment in 12 months. With this mechanism, the impact will be diluted over a total period of 60 months.

As of December 31, 2020, the amounts received by the electric distribution subsidiaries in Brazil totaled BRL$ 3,172,022 (equivalent to ThUS$ 569,483). This is presented in the Consolidated Statement of Cash Flows as of that date, under the item “Other cash inflows from operating activities” and was credited to the related sectorial assets and liabilities.

The tariff increases deferred in this period will be paid by customers in up to 5 years from 2021, through a sectorial tariff charged by distributors and transferred to the CCEE. The CCEE, in its turn, will amortize the loan entered into with the syndicate of the sectorial loan creditor banks.

There are no significant trade and other receivables balances held by the Group that are not available for its use.

The Group does not have customers to which it has sales representing 10% or more of its operating revenue for the years ended December 31, 2021 and 2020.

Refer to Note 10.1 for detailed information on amounts, terms and conditions associated with accounts receivable from related companies.

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b) As of December 2021 and 2020, the analysis of trade accounts receivables due and unpaid, but of which no impairment losses have been recorded, is as follows:

	Balance as of
Trade accounts receivables due and unpaid, but for which no impairment losses have been recorded	12-31-2021 ThUS$	12-31-2020 ThUS$
Less than three months	539,492	555,004
Between three and six months	124,013	92,337
Between six and twelve months	103,368	75,779
More than twelve months	132,349	169,477
Total	899,222	892,597

c) The reconciliation of changes in the allowance for credit losses of trade receivables is as follows:

	Current and
Trade accounts receivables due and unpaid, with impairment losses	Non-Current ThUS$
Balance as of January 1, 2020	768,217
Increases (decreases) for the year	211,536
Amounts written off	(112,591)
Foreign currency translation differences	(111,752)
Balance as of December 31, 2020	755,410
Increases (decreases) for the year (*)	316,004
Amounts written off	(113,198)
Foreign currency translation differences	(59,493)
Balance as of December 31, 2021	898,723

(*) Impairment losses on trade accounts receivable amounted to ThUS$ 316,004 as of December 31, 2021, which represented an increase of 49% in comparison to the loss of ThUS$ 211,536 recorded in the year-end 2020. This increase originated mainly from our Brazil distribution subsidiaries, in the amount of ThUS$ 112,133 offset by the effects of conversion of different foreign currencies in respect to the U.S. dollar in the amount of ThUS$ (14,983). See Note 30.b) Trade and Other Accounts Receivable Impairment Losses.

Write-offs for doubtful accounts

Past-due debt is written off once all collection measures and legal proceedings have been exhausted and the debtors’ insolvency has been demonstrated. In our power generation business, this process normally takes at least one year of procedures for the few cases that arise in each country. In our distribution business, considering the differences in each country, the process takes at least 6 months in Argentina and Brazil and 12 months in Colombia and Peru. Overall, the risk of bad debt, and therefore the risk of writing off our trade receivables, is limited (see Notes 3.g.3 and 21.5).

d)  Additional information:

● Additional statistical information required under Official Bulletin 715 of the CMF, of February 3, 2012 (XBRL Taxonomy). See Appendix 3.

● Complementary Trade Accounts Information. See Appendix 3.1.

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10. BALANCES AND TRANSACTIONS WITH RELATED PARTIES

Related party transactions are performed at current market conditions.

Transactions between the companies belonging to the Group have been eliminated on consolidation and are not itemized in this note

As of the date of these financial statements, no guarantees have been given or received nor has any allowance for bad or doubtful accounts been recorded with respect to receivable balances for related party transactions.

The controlling shareholder of the Company is the Italian corporation Enel S.p.A.

10.1 Balances and transactions with related parties

The balances of accounts receivable and payable as of December 31, 2021 and 2020 are as follows:

a) Receivables from related companies

						Balance as of
						Current		Non-Current
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of Transaction	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$
Foreign	Enel Global Infrastructure And Network	Italy	Common Immediate Parent	EUR	Other Services	416	543	—	—
Foreign	Enel Global Infrastructure And Network	Italy	Common Immediate Parent	COP	Other Services	302	—	—	—
Foreign	Enel S.P.A.	Italy	Parent	EUR	Other Services	725	1,003	—	—
Foreign	Enel S.P.A.	Italy	Parent	COP	Other Services	151	—	—	—
Foreign	Enel S.P.A.	Italy	Parent	BRL	Other Services	226	243	—	—
Foreign	E-Distribuzione S.P.A	Italy	Common Immediate Parent	EUR	Other Services	—	16	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	EUR	Other Services	1,330	265	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	EUR	Technical services	541	—	—	—
Foreign	Enel Global Trading S.P.A.	Italy	Common Immediate Parent	EUR	Other Services	—	1	—	—
Foreign	Endesa Spain	Spain	Common Immediate Parent	EUR	Other Services	18	18	—	—
Foreign	Enel Iberia S.R.L.	Spain	Common Immediate Parent	EUR	Other Services	3	1,289	—	—
Foreign	Enel Iberia S.R.L.	Spain	Common Immediate Parent	US$	Other Services	1,285	—	—	—
Foreign	Endesa Operaciones y Servicios Comerciales S.L.	Spain	Common Immediate Parent	EUR	Other Services	—	86	—	—
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	EUR	Other Services	30	46	—	—
Foreign	Endesa Operaciones y Servicios Comerciales S.L.	Spain	Common Immediate Parent	EUR	Other Services	22	—	—	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	EUR	Other Services	147	102	—	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	BRL	Other Services	148	105	—	—
Foreign	Proyectos Y Soluciones Renovables S.A.C.	Peru	Common Immediate Parent	PEN	Other Services	229	133	—	—
Foreign	Proyectos Y Soluciones Renovables S.A.C.	Peru	Common Immediate Parent	US$	Loan receivable	4,607	—	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	US$	Other Services	338	—	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	COP	Other Services	24	—	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	PEN	Other Services	—	33	—	—
Foreign	Enel North América Inc.	United States	Common Immediate Parent	US$	Other Services	531	93	—	—
Foreign	Enel North América Inc.	United States	Common Immediate Parent	PEN	Other Services	44	43	—	—
Foreign	Enel Green Power Peru	Peru	Common Immediate Parent	PEN	Other Services	—	2,271	—	—
Foreign	Enel Green Power Colombia S.A.S	Colombia	Common Immediate Parent	COP	Other Services	—	709	—	—
Foreign	SACME	Argentina	Associate	ARS	Other Services	6	7	26	32
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	US$	Other Services	410	430	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	COP	Other Services	26	7	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	2,250	2,377	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	BRL	Other Services	410	222	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	693	802	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	US$	Engineering services	1,544	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	US$	Other Services	22	22	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	407	92	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	341	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Common Immediate Parent	US$	Other Services	232	2	—	—
Foreign	Grupo Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	BRL	Other Services	—	3,208	—	—
Foreign	Grupo Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	BRL	Toll	—	17	—	—
Foreign	Grupo Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	BRL	Energy Sale	—	32,544	—	—
Foreign	Enel X Argentina S.A.U.	Argentina	Common Immediate Parent	ARS	Other Services	21	22	—	—
Foreign	E-Distributie Muntenia	Italy	Common Immediate Parent	US$	Other Services	—	58	—	—
Foreign	Electric Motor Werks, Inc.	United States	Common Immediate Parent	EUR	Other Services	206	141	—	—
Foreign	Yacylec S.A.	Argentina	Associate	US$	Other Services	1	—	—	—
Foreign	Enel Finance International NV	Netherlands	Common Immediate Parent	US$	Financial investments	54,935	—	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Other Services	172	—	—	—
Foreign	Enel Green Power RSA	South Africa	Common Immediate Parent	US$	Other Services	673	—	—	—
Foreign	Enel Green Power North America, Inc.	United States	Common Immediate Parent	US$	Other Services	210	—	—	—
Foreign	Enel Green Power Romania	Romania	Common Immediate Parent	EUR	Other Services	83	—	—	—
		Total				73,759	46,950	26	32

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b) Accounts payable to related companies

						Balance as of
						Current		Non-Current
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of Transaction	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	EUR	Technical services	10,902	3,685	—	—
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	EUR	Other Services	1,043	3,702	—	—
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	EUR	IT Services	3,368	252	—	—
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	US$	Other Services	91	67	—	—
Foreign	Enel Finance International NV (*)	Netherlands	Common Immediate Parent	BRL	Loan Payable	10,392	145	454,220	144,391
Foreign	Enel Finance International NV (*)	Netherlands	Common Immediate Parent	US$	Loan Payable	26,622	150,269	89,698	—
Foreign	Enel Finance International NV (*)	Netherlands	Common Immediate Parent	EUR	Loan Payable	184,012	—	503,831	—
Foreign	Enel Finance International NV	Netherlands	Common Immediate Parent	EUR	Financial Guarantee Service	203	745	—	—
Foreign	Endesa Generación S.A.	Spain	Common Immediate Parent	EUR	Other Services	248	217	—	—
Foreign	Endesa Generación S.A.	Spain	Common Immediate Parent	EUR	Engineering services	23	25	—	—
Foreign	Endesa Generación S.A.	Spain	Common Immediate Parent	US$	Other Services	12	8	—	—
Foreign	Enel Sole	Spain	Common Immediate Parent	EUR	Other Services	1,028	1,116	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	EUR	Technical services	26,768	31,107	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	EUR	Other Services	2,243	17,901	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	EUR	IT Services	37,418	482	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	BRL	Other Services	2,341	—	—	—
Foreign	Enel Italy S.R.L	Italy	Common Immediate Parent	US$	IT Services	392	—	—	—
Foreign	Enel Italy S.R.L	Italy	Common Immediate Parent	EUR	Purchase of materials	1,724	1,501	—	—
Foreign	Enel Italy S.R.L	Italy	Common Immediate Parent	EUR	Other Services	569	2,129	—	—
Foreign	Enel Italy S.R.L	Italy	Common Immediate Parent	EUR	Technical services	—	4	—	—
Foreign	Enel Italy S.R.L	Italy	Common Immediate Parent	EUR	IT Services	1,675	1,547	—	—
Foreign	Enel S.P.A.	Italy	Parent	US$	Other Services	423	—	—	—
Foreign	Enel S.P.A.	Italy	Parent	EUR	Other Services	14,252	9,063	—	—
Foreign	Enel S.P.A.	Italy	Parent	EUR	Technical services	58,868	51,334	—	—
Foreign	Enel S.P.A.	Italy	Parent	EUR	IT Services	18,465	3,417	—	—
Foreign	Enel S.P.A.	Italy	Parent	EUR	Hedging derivatives	2,148	—	7,804	—
Foreign	Enel S.P.A.	Italy	Parent	EUR	Financial Guarantee Service	119,181	—	—	—
Foreign	Enel S.P.A.	Italy	Parent	CLP	Dividends	182,853	160,914	—	—
Foreign	E-Distribuzione S.P.A	Italy	Common Immediate Parent	EUR	Other Services	39	54	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Other Services	457	1,321	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Technical services	960	7,113	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Engineering services	6,795	2,978	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	IT Services	899	—	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	US$	Other Services	647	—	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	EUR	Other Services	3,431	629	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	EUR	Technical services	21,072	8,196	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	EUR	IT Services	15,016	942	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	EUR	Engineering services	73,172	—	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	US$	Technical services	9,318	—	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	US$	IT Services	77	—	—	—
Foreign	Enel Green Power S.P.A.	Italy	Common Immediate Parent	CLP	Other Services	194	—	—	—
Foreign	Enel Global Trading S.P.A.	Italy	Common Immediate Parent	EUR	Technical services	5,158	3,967	—	—
Foreign	Enel Global Trading S.P.A.	Italy	Common Immediate Parent	EUR	Other Services	639	304	—	—
Foreign	Enel Global Trading S.P.A.	Italy	Common Immediate Parent	EUR	IT Services	1,386	785	—	—
Foreign	Endesa Spain	Spain	Common Immediate Parent	EUR	Other Services	2,512	2,586	—	—
Foreign	Enel Iberia S.R.L.	Spain	Common Immediate Parent	EUR	Other Services	263	1,394	—	—
Foreign	Enel Iberia S.R.L.	Spain	Common Immediate Parent	EUR	IT Services	749	—	—	—
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	EUR	Other Services	392	318	—	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	EUR	Technical services	17,731	15,279	—	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	EUR	IT Services	7,300	6,755	—	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	EUR	Engineering services	1,085	—	—	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	EUR	Other Services	632	892	—	—
Foreign	Proyectos y Soluciones Renovables S.A.C.	Peru	Common Immediate Parent	PEN	Other Services	2,001	220	—	—
Foreign	Edistribución Redes Digitales, S.L.	Spain	Common Immediate Parent	EUR	Other Services	623	704	—	—
Foreign	Edistribución Redes Digitales, S.L.	Spain	Common Immediate Parent	US$	Technical services	17	18	—	—
Foreign	Cesi S.P.A.	Italy	Common Immediate Parent	EUR	Engineering services	—	52	—	—
Foreign	Enel Green Power Peru	Peru	Common Immediate Parent	PEN	Purchase of Energy	—	1,328	—	—
Foreign	Enel Green Power Peru	Peru	Common Immediate Parent	PEN	Other Services	—	70	—	—
Foreign	Enel Green Power Colombia S.A.S	Colombia	Common Immediate Parent	COP	Purchase of Energy	—	2,637	—	—
Foreign	Enel Green Power Colombia S.A.S	Colombia	Common Immediate Parent	COP	Other Services	—	16	—	—
Foreign	Enel X North America	United States	Common Immediate Parent	US$	Other Services	475	1	—	—
Foreign	SACME	Argentina	Joint venture	ARS	Other Services	189	163	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	US$	Other Services	522	1,583	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	US$	IT Services	2,188	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	2,010	2,126	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	CLP	IT Services	1,185	631	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	BRL	Other Services	35	—	—	—
Foreign	Yacylec S.A.	Argentina	Associated	ARS	Other Services	15	11	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	US$	Other Services	679	766	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	266	345	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	US$	Other Services	97	240	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	US$	Engineering services	544	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	1,327	780	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	CLP	Engineering services	1,205	1,777	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Common Immediate Parent	US$	Other Services	863	4	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Common Immediate Parent	US$	IT Services	618	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Common Immediate Parent	US$	Engineering services	978	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Common Immediate Parent	CLP	Engineering services	276	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Common Immediate Parent	CLP	Other Services	105	430	—	—
Foreign	Grupo Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	BRL	Purchase of Energy	—	33,395	—	—
Foreign	Grupo Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	BRL	Other Services	—	2,005	—	—
Foreign	Energética Monzon S.A.C.	Peru	Common Immediate Parent	PEN	Other Services	—	24	—	—
Foreign	Enel Global Services S.r.L	Italy	Common Immediate Parent	US$	Other Services	431	—	—	—
Foreign	Enel Global Services S.r.L	Italy	Common Immediate Parent	US$	IT Services	852	—	—	—
Foreign	Enel Global Services S.r.L	Italy	Common Immediate Parent	EUR	IT Services	48,811	6,110	—	—
Foreign	Enel Global Services S.r.L	Italy	Common Immediate Parent	EUR	Other Services	50	34,999	—	—
Foreign	Enel Global Services S.r.L	Italy	Common Immediate Parent	EUR	Technical services	9,697	12,885	—	—
Foreign	Servizio Elettrico Nazionale SpA	Italy	Common Immediate Parent	EUR	Other Services	233	146	—	—
Foreign	Enel X Argentina S.A.U.	Argentina	Common Immediate Parent	ARS	Other Services	3	3	—	—
Foreign	Electric Motor Werks, Inc.	United States	Common Immediate Parent	EUR	Other Services	—	510	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	US$	Other Services	202	—	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	US$	Engineering services	894	—	—	—
Foreign	Enel Green Power Spain	Spain	Common Immediate Parent	EUR	Other Services	190	—	—	—
Foreign	Enel Green Power Romania	Romania	Common Immediate Parent	EUR	Other Services	233	—	—	—
Foreign	Enel Green Power El Salvador	El Salvador	Common Immediate Parent	US$	Other Services	—	—	6,945	—
Foreign	Gridspertise Srl	Italy	Common Immediate Parent	EUR	Other Services	655	—	—	—
Foreign	Enel Ingegneria e Innovazione	Italy	Common Immediate Parent	EUR	Engineering services	50	—	—	—
		Total				955,707	597,122	1,062,498	144,391

(*) See Note d) below.

F-82

c) Significant transactions and effects on profit or loss:

As of December 31, 2021, 2020 and 2019 the significant transactions with related companies that are not consolidated, are as follows:

					For the years ended,
Taxpayer ID N°	Company	Country	Relationship	Description of Transaction	12-31-2021 ThUS$	12-31-2021 ThUS$	12-31-2019 ThUS$
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	Administration and IT services	(3,547)	(7,158)	(7,707)
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	IT Services	(5,109)	—	—
Foreign	Enel Finance International NV	Netherlands	Common Immediate Parent	Financial expenses	(39,181)	(2,441)	(127,977)
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	IT Services	(8,405)	(7,418)	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	Expatriate Personal Services	(2,989)	(897)	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	Technical services	(28,228)	(30,448)	(16,685)
Foreign	Enel Global Services S.r.L	Italy	Common Immediate Parent	IT Services	(5,253)	(7,051)	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	IT Services	(2,008)	—	—
Foreign	Enel Global Thermal Generation S.R.L.	Italy	Common Immediate Parent	Technical services	(6,350)	(7,268)	(3,536)
Foreign	Enel Green Power Colombia S.A.S	Spain	Common Immediate Parent	Purchase of Energy	—	(8,483)	(7,156)
Foreign	Enel Green Power Peru	Peru	Common Immediate Parent	Other Services Provisions	—	1,993	—
Foreign	Enel Green Power S.P.A	Italy	Common Immediate Parent	Technical services	(11,011)	(3,757)	—
Foreign	Enel Italy S.R.L	Italy	Common Immediate Parent	IT Services	—	(758)	(12,278)
Foreign	Enel Italy S.R.L	Italy	Common Immediate Parent	Technical services	—	—	(6,778)
Foreign	Enel S.P.A.	Italy	Parent	Financial expenses	(24,913)	—	—
Foreign	Enel S.P.A.	Italy	Parent	IT Services	(7,239)	—	—
Foreign	Enel S.P.A.	Italy	Parent	Expatriate Personal Services	(3,778)	(4,045)	(2,827)
Foreign	Enel S.P.A.	Italy	Parent	Technical services	(15,187)	(11,542)	(11,554)
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	Technical services	(6,841)	(2,852)	—
Foreign	Grupo Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	Purchase of Energy	(81,395)	(147,841)	(93,299)
Foreign	Grupo Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	Energy Sale	6,707	54,158	1,134

The transactions detailed in the preceding table correspond to all those that exceed US$ 2,000,000 by counterparty and nature of the transactions.

d)  Significant transactions of Enel Américas:

> On May 20, 2020, Enel Américas S.A. formalized and completely used, a committed revolving credit facility with Enel Finance International N.V. for a total of US$ 150 million at a variable interest rate of LIBOR 1M, 3M or 6M plus a 1.35% margin, with monthly, quarterly or biannual interest payments with expiration date of May 20, 2021. This revolving credit facility had no guarantees. This facility was paid in full on its maturity date of May 20, 2021.

> On June 5, 2020, Enel Finance International NV formalized a committed credit line in Brazilian reals with Enel Brasil S.A. for BRL 800 million, maturing on June 12, 2021, at a variable interest rate. On August 5, 2021, this credit line was renewed at a rate of CDI + 0.85%, maturing in February 2023. As of December 31, 2021, this committed revolving credit facility has not been drawn upon.

> On December 21, 2020, Enel Finance International NV formalized an unsecured loan agreement with Enel Distribución Río, denominated in Brazilian reals, in the amount of BRL 750 million, at a fixed interest rate of 3.4%, with payments of interest made annually to be paid in full on the maturity date, January 22, 2024 , which is the date when its principal and interest amortize.

> On December 31, 2020, Enel Green Power Panama formalized a revolving credit facility with Enel Finance International N.V. for US$15 million, at a variable interest rate of LIBOR 3M + 0.40%, with a quarterly interest payment, maturing on December 31, 2021. This revolving credit facility has no guarantees. As of December 31, 2021, this facility is past due.

> On December 31, 2020, PH Chucás S.A. formalized a revolving credit facility with Enel Finance International N.V. for US$10 million, at a variable interest rate of LIBOR 3M + 1.1%, with a quarterly interest payment, maturing on December 31, 2021. This revolving credit facility has no guarantees. As of December 31, 2021, this facility is past due.

> On February 14, 2021, Enel Américas S.A. formalized a revolving credit facility with Enel Finance International N.V. for US $500 million, at a variable interest rate of LIBOR 1M, 3M or 6M + 1.08%, with monthly, quarterly or semi-annual interest payments, maturing on February 14, 2024. This revolving credit facility has no guarantees. As of December 31, 2021, this committed credit facility has not been drawn upon.

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> On March 2, 2021, Enel Finance International NV has formalized a loan agreement in Brazilian reals of BRL$500 million with Enel Distribución Ceará at a CDI rate + 1.1%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is March 2, 2025.

> On March 4, 2021, Enel Finance International NV formalized a loan agreement in Brazilian reals of BRL$600 million with Enel Distribución Goiás, at a CDI rate + 1.1%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is March 4, 2023.

> On April 6, 2021, Enel Finance International NV formalized a loan agreement in Brazilian reals of BRL$160 million with Enel Distribución Goiás, at a CDI rate + 1.1%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is April 6, 2023.

> On April 15, 2021, Enel Finance International NV formalized a loan agreement in Brazilian reals of BRL$230 million with Enel Distribución Rio, at a CDI rate + 0.9%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is April 15, 2023.

> On April 19, 2021, Enel Finance International NV formalized a loan agreement in Brazilian reals of BRL$290 million with Enel Distribución Goiás, at a CDI rate + 1.0%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is April 19, 2023.

> On July 1, 2021, Enel Finance International NV formalized a loan agreement in euros for € 50 million with Enel Distribución Rio, at a EUR rate + 1.29%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is July 3, 2023.

> On July 8, 2021, Enel Finance International NV formalized a loan agreement in euros for €50 million with Enel Distribución Rio, at a EUR rate + 1.29%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is July 8, 2024.

> On July 31, 2021, Enel Finance International NV formalized a loan agreement in euros for €36 million with Enel Distribución Goiás, at a EUR rate + 1.29%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is July 31, 2023.

> On August 5, 2021, Enel Finance International NV formalized a loan agreement in euros for €20 million with Enel Distribución Goiás, at a EUR rate + 1.53%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is August 5, 2024.

> On September 1, 2021, Enel Finance International NV formalized a loan agreement in euros for € 22 million with Enel Distribución Goiás, at a EUR rate + 1.53%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is September 2, 2024.

> On September 3, 2021, Enel Finance International NV formalized a loan agreement in euros for € 50 million with Enel Distribución Rio, at a EUR rate + 1.53%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is September 3, 2024.

> On September 20, 2021, Enel Finance International NV formalized a loan agreement in euros for € 45 million with Enel Distribución Goiás, at a EUR rate + 1.59%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is September 20, 2024.

> On October 1, 2021, Enel Finance International NV formalized a loan agreement with Enel Distribución Goias in euros for € 73 million, at a EUR all-in-rate of 1.81%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is October 1, 2024.

> On October 13, 2021, Enel Finance International NV formalized a loan agreement with Enel Distribución Río, denominated in euros, in the amount of € 40 million, at a EUR all-in rate of 1.59%, without guarantees. This

F-84

loan will be fully repaid in a single principal and interest payment due on the maturity date, which is October 13, 2024.

> On December 14, 2021, Enel Finance International NV formalized a loan agreement with Enel Distribución Rio, denominated in euros, in the amount of € 55 million, at a EUR all-in rate of 1.65%, without guarantees, and single principal and interest payment due on the maturity date, which is December 16, 2024.

> On December 28, 2021, Enel Finance International NV formalized a loan agreement with Enel Distribución Río, denominated in euros, in the amount of € 160 million, at a EUR all-in rate of 1.06%, without guarantees. This loan will be fully repaid in a single principal and interest payment due on the maturity date, which is December 28, 2024.

> On December 31, 2021, Enel Green Power Peru formalized a committed revolving credit facility with Enel Finance International NV totaling US$ 30 million, at a LIBOR 1M, 3M, or 6M variable interest plus a 0.9% margin, with monthly, quarterly, or biannual interest payments and maturity on December 31, 2022. This revolving credit facility has no guarantees. As of December 31, 2021, this facility has not been drawn upon.

> As of December 31, 2021, Enel SpA has guarantees granted to Enel Brasil for a total of US $135 million, at a variable interest rate ranging from 0.38% to 1.03% on the guaranteed amount and depending on the term granted. These guarantees mainly cover loan agreements, machinery and equipment, agreements for the use of transmission system and connection to transmission facilities.

10.2 Board of directors and key management personnel

The Company is managed by a Board of Directors which consists of 7 members. Each director serves for a three-year term after which they can be reelected.

The Board of Directors as of December 31, 2021 was elected at the General Shareholders Meeting held on April 29, 2021, and is composed of the following members:

> Mr. Francisco de Borja Acha Besga

> Mr. José Antonio Vargas Lleras

> Mrs. Giulia Genuardi

> Mrs. Francesca Gostinelli

> Mr. Hernán Somerville Senn

> Mr. Patricio Gómez Sabaini

> Mr. Domingo Cruzat Amunátegui

At the Board meeting held on April 29, 2021, Mr. Francisco de Borja Acha Besga was elected as Chairman of the Board and Mr. Domingo Valdés Prieto as Secretary of the Board.

The Directors’ Committee was also appointed during the same Board meeting, governed by Law No.18,046 (the Chilean Corporations Law) and the Sarbanes-Oxley Act. The Director’s Committee comprises the independent Directors Mr. Hernán Somerville Senn, Mr. Patricio Gómez Sabaini, and Mr. Domingo Cruzat Amunátegui. All of the members of the Directors’ Committee are independent Directors in accordance with the provisions of Circular No. 1,956 issued by the CMF. The Chairman and Secretary of the Directors’ Committee appointed by the Directors’ Committee are Mr. Hernán Somerville Senn and Mr. Domingo Valdés Prieto, respectively.

The Board of Directors appointed Mr. Hernán Somerville Senn as the financial expert of the Directors’ Committee of Enel Américas S.A.

F-85

a) Accounts receivable and payable and other transactions

● Accounts receivable and payable

There are 0 outstanding amounts receivable or payable between the Company and the members of the Board of Directors and key management personnel.

● Other transactions

NaN transactions other than the payment of compensation has taken place between the Company and the members of the Board of Directors and key management personnel.

b) Guarantees given by the Company in favor of the directors

No guarantees have been given to the directors.

c) Compensation for directors

In accordance with Article 33 of Law No. 18,046 (the Chilean Corporations Law) governing stock corporations, the compensation of Directors is established each year at the General Shareholders Meeting of the Company.

The compensation consists of paying each member of the Board of Directors monthly compensation, one part in a fixed monthly fee and another part dependent on meetings attended. The breakdown of this compensation is as follows:

> UF 216 as a fixed monthly fee, and

> UF 79.2 as a per diem for each Board meeting attended with a maximum of 16 sessions in total whether ordinary or extraordinary, within the corresponding exercise.

According to the provisions of the bylaws, the remuneration of the Chairman of the Board will be twice that of a Director.

In the event a Director of Enel Américas participates in more than one Board of Directors of domestic or foreign subsidiaries and / or affiliates or acts as director or consultant for other domestic or foreign companies or legal entities in which Enel Américas has a direct or indirect interest, he/she may receive remuneration only in one of said Boards of Directors or Management Boards.

The executive officers of Enel Américas S.A. and/or its domestic or foreign subsidiaries or affiliates will not receive remunerations or per diem allowances if acting as directors of any of the domestic or foreign Enel Américas’ subsidiaries, affiliates or investee in any way. Therefore, said remunerations or per diem allowances may be received by the executive officers as long as this is previously and expressly authorized as an advance of their variable portion of remuneration by the corresponding companies with which they are associated through an employment contract.

Directors’ Committee:

Each member will be paid monthly compensation, one part in a fixed monthly fee and another part dependent on meetings attended.

This compensation is broken down as follows:

> UF 72 as a fixed monthly fee, in any event, and

F-86

> UF 26.4 as a per diem for each Board meeting attended, all with a maximum of 16 meetings in total, whether ordinary or extraordinary, within the corresponding fiscal year.

The following tables show details of the compensation paid to the members of the Board of Directors of the Company for the years ended December 31, 2021, 2020 and 2019:

			December 31, 2021
Taxpayer ID				Enel Américas Board	Board of Subsidiaries	Directors’ Committee
No.	Name	Position	Period in position	ThUS$	ThUS$	ThUS$
Foreign	Francisco de Borja Acha Besga	Chairman	January - December 2021	—	—	—
Foreign	José Antonio Vargas Lleras	Vice Chairman	January - December 2021	—	—	—
Foreign	Enrico Viale	Director	January - March 2021	—	—	—
Foreign	Livio Gallo	Director	January - March 2021	—	—	—
Foreign	Giulia Genuardi	Director	April - December 2021	—	—	—
Foreign	Francesca Gostinelli	Director	April - December 2021	—	—	—
4.132.185-7	Hernán Somerville Senn	Director	January - December 2021	149	—	47
Foreign	Patricio Gómez Sabaini	Director	January - December 2021	149	—	47
6.989.304-K	Domingo Cruzat Amunátegui	Director	January - December 2021	149	—	47
	TOTAL			447	—	141

			December 31, 2020
Taxpayer ID				Enel Américas Board	Board of Subsidiaries	Directors’ Committee
No.	Name	Position	Period in position	ThUS$	ThUS$	ThUS$
Foreign	Francisco de Borja Acha Besga	Chairman	January - December 2020	—	—	—
Foreign	José Antonio Vargas Lleras	Vice Chairman	January - December 2020	—	—	—
Foreign	Enrico Viale	Director	January - December 2020	—	—	—
Foreign	Livio Gallo	Director	January - December 2020	—	—	—
4.132.185-7	Hernán Somerville Senn	Director	January - December 2020	143	—	47
Foreign	Patricio Gómez Sabaini	Director	January - December 2020	143	—	47
6.989.304-K	Domingo Cruzat Amunátegui	Director	January - December 2020	143	—	47
	TOTAL			429	—	141

			December 31, 2019
Taxpayer ID				Enel Américas Board	Board of Subsidiaries	Directors’ Committee
No.	Name	Position	Period in position	ThUS$	ThUS$	ThUS$
Foreign	Francisco de Borja Acha Besga	Chairman	January - December 2019	—	—	—
Foreign	José Antonio Vargas Lleras	Vice Chairman	January - December 2019	—	—	—
Foreign	Enrico Viale	Director	January - December 2019	—	—	—
Foreign	Livio Gallo	Director	January - December 2019	—	—	—
4.132.185-7	Hernán Somerville Senn	Director	January - December 2019	159	—	48
Foreign	Patricio Gómez Sabaini	Director	January - December 2019	159	—	48
6.989.304-K	Domingo Cruzat Amunátegui	Director	January - December 2019	159	—	48
	TOTAL			478	—	144

F-87

10.3 Compensation of key management personnel

a) Remunerations received by key management personnel

Key Management Personnel
Taxpayer ID No.	Name	Position
Foreign	Maurizio Bezzeccheri (1)	Chief Executive Officer
Foreign	Aurelio Ricardo Bustilho de Oliveira (2)	Administration, Finance and Control Manager
10.560.169-7	Francisco Miqueles Ruz (3)	Planning and Control Manager
25.067.660-3	Simone Tripepi (4)	Enel X South America Manager
Foreign	Raffaele Cutrignelli (5) (6)	Internal Audit Manager
6.973.465-0	Domingo Valdés Prieto (5)	Attorney and Secretary of the Board

(1)Mr. Maurizio Bezzeccheri assumed the position of Chief Executive Officer on August 1, 2018.

(2)Mr. Aurelio Ricardo Bustilho de Oliveira assumed the position of Administration, Finance and Control Manager on October 1, 2018.

(3)Mr. Francisco Miqueles Ruz assumed the position of Planning and Control Manager on February 26, 2020, replacing Mr. Paolo Pescarmona. Mr. Miqueles ceased his functions as of October 1, 2021.

(4)Mr. Simone Tripepi assumed the position of Enel X South America Manager on August 29, 2019.

(5)Messrs. Raffaele Cutrignelli and Domingo Valdés Prieto, executive officers of Enel Américas, are paid by Enel Américas who is their employer, but they provide services to the Company by virtue of an intercompany contract between those companies.

(6)Mr. Eugenio Belinchon Gueto assumed the position of Internal Audit Manager on February 1, 2022, replacing Mr. Raffaele Cutrignelli.

Incentive plans for key management personnel

Enel Américas has implemented an annual bonus plan for its executives based on meeting company-wide objectives and on the level of their individual contribution in achieving the overall goals of the Group. The plan provides for a range of bonus amounts according to seniority level. The bonuses paid to the executives consist of a certain number of monthly gross remunerations.

Compensation of key management personnel is the following:

	For the years ended December 31,
	2021	2020	2019
	ThUS$	ThUS$	ThUS$
Remuneration	3,869	3,495	2,407
Short-term benefits for employees	88	148	106
Other long-term benefits - IAS	7	7	—
Total	3,964	3,650	2,513

b) Guarantees established by the Company in favor of key management personnel

No guarantees have been given to key management personnel.

10.4 Compensation plans linked to share price

F-88

There are no payment plans granted to the Directors or key management personnel based on the share price of the Company’s common stock.

11. INVENTORIES

The detail of inventories as of December 31, 2021 and 2020 is as follows:

	Balance as of
	12-31-2021	12-31-2020
Classes of Inventories	ThUS$	ThUS$
Supplies for Production	21,639	26,685
Oil	14,898	16,686
Coal	6,741	9,999
Spare parts	72,256	53,013
Electrical materials	444,381	391,735
Total	538,276	471,433

There are 0 inventories acting as security for liabilities.

For the years ended December 31, 2021, 2020 and 2019, raw materials and inputs recognized as fuel cost amount to ThUS$ 116,666, ThUS$ 137,850 and ThUS$ 277,117, respectively (see Note 28).

For the years ended December 31, 2021, 2020 and 2019 there have been 0 impairments recognized in inventories.

12. CURRENT TAX ASSETS AND LIABILITIES

a) The detail of current tax receivables as of December 31, 2021 and 2020, is as follows:

	Balance as of
	12-31-2021	12-31-2020
Tax assets	ThUS$	ThUS$
Advance income tax payments	191,858	118,609
Other	9,882	9,271
Total	201,740	127,880

b) The detail of current tax payables as of December 31, 2021 and 2020, is as follows:

	Balance as of
	12-31-2021	12-31-2020
Tax liabilities	ThUS$	ThUS$
Income tax	183,060	222,870
Total	183,060	222,870

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13. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD

13.1 Investments accounted for using the equity method

a) The investments of the Group accounted for using the equity method and their changes during the years ended December 31, 2021 and 2020, are detailed as follows:

											Argentine
						Balance as of			Foreign Currency	Other	hyperinflationary	Balance as of
Taxpayer ID						1-1-2021	Share of Profit (Loss)	Dividends Declared	Translation	Increase (Decrease)	economy	12-31-2021
No,	Associates and Joint Ventures	Relationship	Country	Functional Currency	Company share percentage	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Yacylec S.A.	Associate	Argentina	Argentine peso	33.33%	995	168	(250)	(135)	—	298	1,076
Foreign	Sacme S.A.	Joint venture	Argentina	Argentine peso	50.00%	133	32	—	(24)	(61)	55	135
Foreign	Central Vuelta Obligado S.A.	Associate	Argentina	Argentine peso	40.90%	1,145	981	(954)	(208)	194	—	1,158
					TOTAL	2,273	1,181	(1,204)	(367)	133	353	2,369
											Argentine
						Balance as of			Foreign Currency	Other	hyperinflationary	Balance as of
Taxpayer ID						1-1-2020	Share of Profit (Loss)	Dividends Declared	Translation	Increase (Decrease)	economy	12-31-2020
No,	Associates and Joint Ventures	Relationship	Country	Functional Currency	Company share percentage	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Yacylec S.A.	Associate	Argentina	Argentine peso	33.33%	1,220	475	(345)	(252)	—	(103)	995
Foreign	Sacme S.A.	Joint venture	Argentina	Argentine peso	50.00%	186	28	—	(54)	(75)	48	133
Foreign	Central Térmica Manuel Belgrano (1)	Associate	Argentina	Argentine peso	—	32	687	(483)	(9)	(227)	—	—
Foreign	Central Térmica San Martin (1)	Associate	Argentina	Argentine peso	—	249	732	(548)	(72)	(361)	—	—
Foreign	Central Vuelta Obligado S.A.	Associate	Argentina	Argentine peso	40.90%	291	1,211	(481)	(84)	208	—	1,145
					TOTAL	1,978	3,133	(1,857)	(471)	(455)	(55)	2,273

(1) During November 2020, all conditions were met to allow the Argentine government to enter into the ownership of the Manuel Belgrano Thermal Power Plant and the San Martin Thermal Power Plant. This situation caused the Group to lose significant influence in those plants (see Note 34.6).

Based on the above, the Group reclassified these investments as financial assets at fair value through profit or loss, generating a finance income of ThUS$ 24,893 at year end of 2020 (see Note 32).

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b) Additional financial information on investments in associates:

- Investments with significant influence

The following tables set forth financial information as of December 31, 2021 and 2020, from the financial statements of the investments in associates where the Group has significant influence:

	December 31, 2021
	Company share percentage Direct /Indirect	Current Assets	Non-Current Assets	Current Liabilities	Non-Current Liabilities	Revenue	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	%	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Yacylec S.A.	33.33%	3,407	1,537	672	1,044	1,866	(1,362)	504	(405)	99
	December 31, 2020
	Company share percentage Direct /Indirect	Current Assets	Non-Current Assets	Current Liabilities	Non-Current Liabilities	Revenue	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	%	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Yacylec S.A.	33.33%	3,975	1,314	866	1,437	3,388	(1,963)	1,425	(755)	670

None of our associates have issued price quotations.

There are 0 significant commitments and contingencies, or restrictions to the availability of funds in associated companies and joint ventures.

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14. INTANGIBLE ASSETS OTHER THAN GOODWILL

The following table presents intangible assets other than Goodwill as of December 31, 2021 and 2020:

Classes of Intangible Assets, gross	12-31-2021 ThUS$	12-31-2020 ThUS$
Intangible Assets, Gross	9,116,265	8,525,990
Easements and water rights	42,351	50,415
Concessions	8,216,801	8,042,389
Development costs	21,807	14,544
Patents, registered trademarks and other rights	151,027	44,596
Computer software	594,329	372,455
Other identifiable intangible assets	89,950	1,591
Intangible Assets, Amortization and Impairment	12-31-2021 ThUS$	12-31-2020 ThUS$
Accumulated Amortization and Impairment, Total	(4,359,995)	(4,001,164)
Easements and water rights	(16,465)	(16,969)
Concessions	(4,095,665)	(3,807,526)
Development costs	(9,057)	(9,708)
Patents, registered trademarks and other rights	(24,495)	(23,499)
Computer software	(164,481)	(141,994)
Other identifiable intangible assets	(49,832)	(1,468)
Classes of Intangible Assets, Net	12-31-2021 ThUS$	12-31-2020 ThUS$
Intangible Assets, Net	4,756,270	4,524,826
Easements and water rights	25,886	33,446
Concessions, Net(1)	4,121,136	4,234,863
Development costs	12,750	4,836
Patents, registered trademarks and other rights	126,532	21,097
Computer software	429,848	230,461
Other identifiable intangible assets	40,118	123

(1) The detail of concessions is the following:

Concession Holder	12-31-2021 ThUS$	12-31-2020 ThUS$
Enel Distribución Río S.A. (*)	457,564	534,325
Enel Distribución Ceará S.A. (*)	403,268	434,656
Enel Distribución Goias S.A. (*)	1,332,237	1,240,641
Enel Distribución Sao Paulo S.A. (*)	1,785,849	1,965,083
EGP Cachoeira Dourada S.A.	50,483	60,158
Grupo EGP Brasil	6,719	—
PH Chucás S.A. (*)	52,587	—
Enel Fortuna S.A.	28,711	—
Enel Green Power Panamá, S.R.L.	2	—
Sociedad Portuaria Central Cartagena S.A.	1,940	—
Enel Green Power Volta Grande	1,776
TOTAL	4,121,136	4,234,863

(*) Public service concession agreements to a private operator are recorded in accordance with IFRIC 12 Service Concession Agreements (see Note 3.d.1).

F-92

The reconciliations of the carrying amounts of intangible assets as of December 31, 2021 and 2020 are as follows:

				Patents, Registered
	Development			Trademarks and	Computer	Other Identifiable	Intangible Assets,
	Costs	Easements	Concessions	Other Rights	Software	Intangible Assets	Net
Movements in Intangible Assets	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Opening balance as of January 1, 2021	4,836	33,446	4,234,863	21,097	230,461	123	4,524,826
Movements in identifiable intangible assets:							—
Increases other than from business combinations	—	—	365,893	106,470	63,272	—	535,635
Acquisitions made through business combinations	12,479	436	93,423	9,079	179,541	38,647	333,605
Increase (decrease) from foreign currency translation differences, net	(1,334)	(8,899)	(284,856)	(5,498)	(68,211)	810	(367,988)
Amortization	(180)	(1,159)	(388,806)	(2,862)	(35,851)	(1,922)	(430,780)
Impairment loss recognized in profit or loss for the period (1)	(750)	—	—	—	—	—	(750)
Increases (decreases) from transfers and other changes	(2,302)	1,995	(1,485)	1,951	(297)	138	—
Increases (decreases) from transfers	(2,302)	1,995	(1,485)	1,951	(297)	138	—
Dispositions and removal from service	—	—	(8,558)	(4,720)	(163)	—	(13,441)
Removals from service	—	—	(8,558)	(4,720)	(163)	—	(13,441)
Argentine hyperinflationary economy	—	—	31	—	25,496	—	25,527
Other increases (decreases)	1	67	110,631	1,015	35,600	2,322	149,636
Total movements in identifiable intangible assets	7,914	(7,560)	(113,727)	105,435	199,387	39,995	231,444
Closing balance as of December 31, 2021	12,750	25,886	4,121,136	126,532	429,848	40,118	4,756,270
				Patents, Registered
	Development			Trademarks and	Computer	Other Identifiable	Intangible Assets,
	Costs	Easements	Concessions	Other Rights	Software	Intangible Assets	Net
Movements in Intangible Assets	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Opening balance as of January 1, 2020	4,546	31,487	5,281,728	25,490	184,430	198	5,527,879
Movements in identifiable intangible assets:							—
Increases other than from business combinations	—	—	738,387	—	82,988	—	821,375
Increase (decrease) from foreign currency translation differences, net	(263)	(1,472)	(1,192,132)	(1,705)	(20,661)	(16)	(1,216,249)
Amortization	(146)	(1,257)	(357,855)	(3,149)	(29,963)	(59)	(392,429)
Increases (decreases) from transfers and other changes	488	4,688	(996)	461	(4,641)	—	—
Increases (decreases) from transfers	488	4,688	(996)	461	(4,641)	—	—
Dispositions and removal from service	—	—	(16,522)	—	—	—	(16,522)
Dispositions	—	—	(16,522)	—	—	—	(16,522)
Argentine hyperinflationary economy	—	—	37	—	9,991	—	10,028
Other increases (decreases)	211	—	(217,784)	—	8,317	—	(209,256)
Total movements in identifiable intangible assets	290	1,959	(1,046,865)	(4,393)	46,031	(75)	(1,003,053)
Closing balance as of December 31, 2020	4,836	33,446	4,234,863	21,097	230,461	123	4,524,826

(1) See Note 30.b)

As of December 31, 2021, the main additions to concession intangible assets in the amount of ThUS$ 365,893 (ThUS$ 738,387 as of December 31, 2020) arise mainly from Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Sao Paulo S.A. and Enel Distribución Goiás S.A. for investments in networks and extensions to optimize their operation, in order to improve the efficiency and quality of the level of service. These are recorded under concessions, in accordance with IFRIC 12 (See Note 3.d.1).

Additions to intangible assets for the year ended December 31, 2021 and 2020, amounted to ThUS$ 535,635 and ThUS$ 821,375, respectively.

The amortization of intangible assets are presented net of PIS and COFINS taxes in the Brazilian subsidiaries.

The financial expenses capitalized for the years ended December 31, 2021, 2020 and 2019 were ThUS$ 5,475 ThUS$ 1,185 and ThUS$ 7,611, respectively (see Note 32). The average financing rate by averaging the financing rates from different geographical areas as 3.9%, 4.98% and 9.27% for the years ended December 31, 2021, 2020 and 2019, respectively.

F-93

During the years ended December 31, 2021, 2020 and 2019 the expenses for personnel directly related to constructions in progress were activated for the item of concessions for the amount of ThUS$ 103,072, ThUS$ 76,470 and ThUS$ 89,154, respectively.

According to the estimates and projections of the Group management, the projections for the cash flows attributed to intangible assets allow recovering the net value of these assets recorded as of December 31, 2021 and 2020 (see Note 3.e).

As of December 31, 2021 and 2020, the Company has 0 intangible assets of indefinite useful life that can represent significant amounts.

15. GOODWILL

The following table sets forth goodwill by cash-generating unit or group of cash-generating units to which it belongs and changes for the years ended December 31, 2021 and 2020:

		Opening	Foreign	Argentine	Closing			Argentine		Closing
		balance	Currency	hyperinflationary	balance	Business Combination	Foreign Currency	hyperinflationary		balance
		1-1-2020	Translation	economy	12-31-2020		Translation	economy	Impairment (*)	12-31-2021
Company	Cash Generating Unit	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Enel Distribución Rio S.A. (1)	Enel Distribución Río S.A.	211,367	(47,672)	—	163,695	—	(11,043)	—	—	152,652
Compañía Distribuidora y Comercializadora de Energía S.A. (2)	Compañía Distribuidora y Comercializadora de Energía S.A.	13,191	(529)	—	12,662	—	(2,016)	—	—	10,646
Enel Generación El Chocón S.A. (3)	Enel Generación El Chocón S.A.	25,372	(7,299)	6,530	24,603	—	(4,461)	10,263	(9,963)	20,442
Enel Distribución Peru S.A. (4)	Enel Distribución Peru	69,647	(5,801)	—	63,846	—	(6,022)	—	—	57,824
EGP Cachoeira Dourada S.A. (5)	EGP Cachoeira Dourada S.A.	77,503	(17,480)	—	60,023	—	(4,049)	—	—	55,974
Enel Generación Peru S.A. (6)	Enel Generación Peru	131,090	(10,918)	—	120,172	—	(11,335)	—	—	108,837
Emgesa S.A. E.S.P. (7)	Emgesa S.A. E.S.P.	5,835	(234)	—	5,601	—	(892)	—		4,709
Enel Peru S.A.	Enel Distribución Peru	23	(3)	—	20	—	(2)	—	—	18
Enel Brasil S.A.	Enel Brazil S.A.	984	(222)	—	762	—	(51)	—	—	711
Enel Distribución Ceará S.A. (8)	Enel Distribución Ceará S.A.	106,396	(23,997)	—	82,399	—	(5,559)	—	—	76,840
Enel Distribución Sao Paulo S.A. (9)	Enel Distribución Sao Paulo	531,635	(119,906)	—	411,729	—	(27,776)	—	—	383,953
Enel Brasil S.A. (10) (11)	Enel Brazil S.A.	—	—	—	—	422,410	15,281	—	—	437,691
Enel Green Power Argentina S.A. (10)	Enel Green Power Argentina S.A.	—	—	—	—	2,252	(237)	—	—	2,015
Enel Green Power Colombia SAS E.S.P (10)	Enel Green Power Colombia SAS E.S.P.	—	—	—	—	55,335	(4,623)	—	—	50,712
Enel Green Power Peru S.A. (10)	Enel Green Power Peru S.A.	—	—	—	—	76,306	—	—	—	76,306
Enel Solar S.R.L. (10)	Enel Solar S.R.L.	—	—	—	—	2,094	—	—	—	2,094
Enel Green Power Panama S.A. (10)	Enel Green Power Panama S.A.	—	—	—	—	24,964	—	—	—	24,964
Empresa de Generación Eléctrica Los Pinos S.A. (10)	Empresa de Generación Eléctrica Los Pinos S.A.	—	—	—	—	2,838	(159)	—	—	2,679
Jaguito Solar 10MW S.A. (10)	Jaguito Solar 10MW S.A.	—	—	—	—	386	—	—	—	386
Progreso Solar 20MW S.A. (10)	Progreso Solar 20MW S.A.	—	—	—	—	772	—	—	—	772
Total		1,173,043	(234,061)	6,530	945,512	587,357	(62,944)	10,263	(9,963)	1,470,225

(*) See Note 30.b)

According to the Group management’s estimates and projections, the expected future cash flows projections attributable to the cash-generating units or groups of cash-generating units, to which the acquired goodwill has been allocated, allow the recovery of its carrying amount as of December 31, 2021 (see Note 3.e).

F-94

The origin of the goodwill is detailed below:

1.- Enel Distribución Rio S.A. (formerly Ampla Energia e Serviços S.A.)

On November 20, 1996, the Company and Enel Distribución Chile S.A. (formerly named Chilectra S.A.), together with Endesa, S.A. and Electricidad de Portugal, acquired a controlling equity interest in Cerj S.A. (now Enel Distribución Rio S.A.) of Rio de Janeiro in Brazil. The Company and Enel Distribución Chile S.A. together acquired 42% of the total shares in an international public bidding process held by the Brazilian government. The Company and Enel Distribución Chile S.A. also acquired an additional 18.5% on December 31, 2000, as such, holding, directly and indirectly, a total 60.5% ownership interest.

2.- Compañía Distribuidora y Comercializadora de Energía S.A. (Codensa S.A.)

On October 23, 1997, Enel Américas S.A. and its former subsidiary Enel Distribución Chile S.A., together with Endesa, S.A., acquired a 48.5% equity interest in Codensa, a company that distributes electricity in Santa Fé de Bogotá in Colombia. The acquisition took place through an international public bidding process held by the Colombian government.

3.- Enel Generación El Chocón S.A.

On August 31, 1993, Enel Generación Chile S.A. (formerly known as Endesa Chile) acquired a 59% equity interest of Enel Generación El Chocón S.A. in an international public bidding process held by the Argentine government.

4.- Enel Distribución Perú S.A.A.

On October 15, 2009, in a transaction on the Lima Stock Exchange, the Company acquired an additional 24% interest in Enel Distribución Perú S.A.A.

5.- EGP Cachoeira Dourada S.A.

On September 5, 1997, the Company’s former subsidiary Enel Generación Chile S.A. acquired 79% of EGP Cachoeira Dourada S.A. in the state of Goiás in a public bidding process held by the Brazilian government.

6.- Enel Generación Perú S.A.A (formerly Edegel S.A.A. )

On October 9, 2009, in a transaction on the Lima Stock Exchange in Peru, the Company’s former subsidiary Enel Generación Chile S.A. acquired an additional 29.3974% equity interest in Enel Generación Perú S.A.

7.- Emgesa S.A. E.S.P.

On October 23, 1997, the Company’s former subsidiary Enel Generación Chile S.A., together with Endesa, S.A., acquired a 48.5% equity interest in Emgesa S.A. E.S.P. in Colombia. The acquisition was made in an international public bidding process held by the Colombian government.

8.- Enel Distribución Ceará S.A. (formerly Compañía Energética Do Ceará S.A.)

Between 1998 and 1999, the Company and its former subsidiary Enel Distribución Chile S.A., together with Endesa, S.A., acquired Compañía de Distribución Eléctrica del Estado de Ceará (now named Enel Distribución Ceará S.A.) in northeast Brazil in an international public bidding process held by the Brazilian government.

F-95

9.- Enel Distribución Sao Paulo S.A.

On June 7, 2018, the Company’s subsidiary Enel Brasil acquired a 73.38% interest in Eletropaulo Metropolitana de Electricidade de Sao Paulo S.A. (currently Enel Distribución Sao Paulo S.A.). Subsequently, between June 22 and July 4, 2018, additional participation increases were effected, representing an increase from 73.38% to 95.05%.

10.- EGP Central and South America

Goodwill was recognized as a result of the merger of Enel Américas and EGP Americas effective on April 1, 2021 (see Note 5). Such goodwill were assigned to the following companies: Enel Green Power Brasil Participaçoes Ltda., Enel Green Power Argentina SA, Enel Green Power Colombia SAS Esp, Enel Green Power Peru SA, Empresa de Generación Eléctrica Los Pinos SA, Enel Solar SRL, Enel Green Power Panamá S.A, Jaguito Solar 10MW S.A. and Progreso Solar 20MW S.A. These companies arise from several business combinations completed in the past by Enel Green Power SpA.

11.- Enel Brasil S.A.

On November 4, 2021, Enel Green Power Brasil Participaçoes Ltda. was merged with and into Enel Brasil S.A. with the latter as the surviving corporation.

16. PROPERTY, PLANT AND EQUIPMENT

The following table sets forth the property, plant and equipment as of December 31, 2021 and 2020:

	12-31-2021	12-31-2020
Classes of Property, Plant and Equipment, Gross	ThUS$	ThUS$
Property, Plant and Equipment, Gross	21,570,734	15,691,168
Construction in progress	2,920,093	1,107,981
Land	153,913	158,894
Buildings	1,203,037	479,161
Plant and equipment	9,868,826	6,894,543
Network Infrastructure	6,846,721	6,647,840
Fixtures and fittings	578,144	402,749
	12-31-2021	12-31-2020
Classes of Accumulated Depreciation and Impairment in Property, Plant and Equipment	ThUS$	ThUS$
Accumulated Depreciation and Impairment of Property, Plant and Equipment	(8,573,206)	(7,336,496)
Buildings	(319,228)	(225,850)
Plant and equipment	(4,489,844)	(3,509,839)
Network Infrastructure	(3,455,646)	(3,379,182)
Fixtures and fittings	(308,488)	(221,625)
	12-31-2021	12-31-2020
Classes of Property, Plant and Equipment, Net	ThUS$	ThUS$
Property, Plant and Equipment, Net	12,997,528	8,354,672
Construction in progress	2,920,093	1,107,981
Land	153,913	158,894
Buildings	883,809	253,311
Plant and equipment	5,378,982	3,384,704
Network Infrastructure	3,391,075	3,268,658
Fixtures and fittings	269,656	181,124

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The composition and movements of the property, plant and equipment accounts for the year ended December 31, 2021 and 2020, are detailed as follows:

	Construction in Progress	Land	Buildings, Net	Plant and Equipment, Net	Network Infrastructure, Net	Fixtures and Fittings, Net	Property, Plant and Equipment, Net
Movements in 2021	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Opening balance as of January 1, 2021	1,107,981	158,894	253,311	3,384,704	3,268,658	181,124	8,354,672
Increases other than from business combinations	1,725,928	958	499	—	—	34,039	1,761,424
Acquisitions through business combinations	809,849	5,288	547,110	2,476,336	100,051	13,775	3,952,409
Increases (decreases) from foreign currency translation differences, net	(181,401)	(24,021)	(20,800)	(504,454)	(424,512)	(21,878)	(1,177,066)
Depreciation	(3,734)	—	(27,596)	(269,194)	(215,232)	(32,936)	(548,692)
Impairment (losses) reversals recognized in profit or loss (1)	(6,849)	—	(290)	(82,205)	—	—	(89,344)
Increases (decreases) from transfers and other changes	(761,588)	8,147	135,955	221,742	373,791	21,953	—
Increases (decreases) from transfers from construction in progress	(761,588)	8,147	135,955	221,742	373,791	21,953	—
Disposals and removal from service	—	(124)	(706)	(3,040)	(6,611)	(6,049)	(16,530)
Removals	—	(124)	(706)	(3,040)	(6,611)	(6,049)	(16,530)
Argentine hyperinflationary economy	207,559	6,350	5,694	124,084	362,337	19,911	725,935
Other increases (decreases)	22,348	(1,579)	(9,368)	31,009	(67,407)	59,717	34,720
Total movements	1,812,112	(4,981)	630,498	1,994,278	122,417	88,532	4,642,856
Closing balance as of December 31, 2021	2,920,093	153,913	883,809	5,378,982	3,391,075	269,656	12,997,528
	Construction in Progress	Land	Buildings, Net	Plant and Equipment, Net	Network Infrastructure, Net	Fixtures and Fittings, Net	Property, Plant and Equipment, Net
Movements in 2020	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Opening balance as of January 1, 2020	1,189,709	163,522	257,147	3,585,593	3,369,083	198,384	8,763,438
Increases other than from business combinations	583,727	—	744	246	—	21,846	606,563
Increases (decreases) from foreign currency translation differences, net	(214,324)	(11,335)	(25,179)	(282,132)	(412,848)	(38,472)	(984,290)
Depreciation	—	—	(11,198)	(207,624)	(203,165)	(23,264)	(445,251)
Increases (decreases) from transfers and other changes	(483,505)	2,076	23,769	159,526	276,955	21,179	—
Increases (decreases) from transfers from construction in progress	(483,505)	2,076	23,769	159,526	276,955	21,179	—
Disposals and removals from service	—	(79)	—	(2,961)	(5,035)	(3,916)	(11,991)
Disposals	—	(78)	—	(2,014)	(9)	(142)	(2,243)
Removals	—	(1)	—	(947)	(5,026)	(3,774)	(9,748)
Argentine hyperinflationary economy	115,905	3,815	7,330	98,418	247,568	(1,881)	471,155
Other increases (decreases)	(83,531)	895	698	33,638	(3,900)	7,248	(44,952)
Total movements	(81,728)	(4,628)	(3,836)	(200,889)	(100,425)	(17,260)	(408,766)
Closing balance as of December 31, 2020	1,107,981	158,894	253,311	3,384,704	3,268,658	181,124	8,354,672

(1) See clause iv) in section c) other information, contained in this Note and Note 30.b).

Additional information on property, plant and equipment, net

a) Main Investments

The main additions to property, plant and equipment correspond to investments in operating plants, distribution networks and new projects for ThUS$ 1,761,424 and ThUS$ 606,563 the years ended December 31, 2021 and 2020, respectively.

In the generation business, the investments in combined cycle and hydroelectric plants in the subsidiaries Enel Generación Perú SA, Emgesa and Enel Generación Costanera, which implied additions as of December 31, 2021 for ThUS$ 167,112 (ThUS$ 163,418 as of December 31, 2020), as well as investments in non-conventional renewable energy plants, mainly in Brazil, Colombia, Panamá and Perú for ThUS$ 1,037,325 (ThUS$ 0 as of December 31, 2020), while in distribution businesses the largest Investments that have been made correspond to network extensions and adaptation of facilities to optimize their operation, in order to improve the efficiency and quality of the service level, for ThUS$ 555,966 as of December 31, 2021 (ThUS$ 442,833 as of December 31, 2020).

The depreciation of property, plant and equipment are presented net of PIS and COFINS taxes in the Brazilian subsidiaries.

b) Capitalized cost

b.1) Capitalized financial expenses

The capitalized cost for financial expenses for the years ended December 31, 2021, 2020 and 2019 amounted to ThUS$ 14,153, ThUS$ 6,376 and ThUS$ 8,092, respectively (see Note 32). The average funding rate mainly

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depends on the geographic area and amounted to 3.6%, 5.91% and 7.49% as of December 31, 2021, 2020 and 2019, respectively.

b.2) Capitalized personnel expenses

The capitalized cost for personnel expenses directly related to construction in progress for the years ended December 31, 2021, 2020 and 2019 amounted to ThUS$ 107,480, ThUS$ 70,681 and ThUS$ 92,411, respectively.

c)  Other information

i) As of December 31, 2021, the Group had contractual commitments for the acquisition of property, plant and equipment amounting to ThUS$ 1,256,793 (ThUS$ 1,078,846 as of December 31, 2020) (including commitments to acquire intangibles from our Brazilian distribution subsidiaries).

ii) As of December 31, 2021, the Group had property, plant and equipment pledged as security for liabilities for ThUS$ 85,317 (ThUS$ 104,577 as of December 31, 2020 (see Note 34.1).

iii) The Company and its foreign subsidiaries have insurance policies for all risks, earthquake and machinery breakdown and damages for business interruption with a €1,000 million (ThUS$ 1,132,650) limit, including business interruption coverage. Additionally, the Company has Civil Liability insurance to meet claims from third parties with a €400 million (ThUS$ 453,060) limit. The premiums associated with these policies are presented proportionally for each company under the line item “other non-financial assets”.

iv) For Enel Generación Costanera, due to the application of IAS 29 - Financial Reporting in Hyperinflationary Economies, (see Note 2.9), the carrying amount of property, plant and equipment as of January 1, 2018 exceeded its recoverable value, which resulted in impairment of ThUS $ 162,274 (equivalent to ThARS 3,102,739 at the exchange rate prevailing on such date). At the end of fiscal year 2018, Enel Generación Costanera recorded a partial reversal of the aforementioned impairment of ThUS $ 70,513 (equivalent to ThARS 2,656,082 using the exchange rate prevailing as of December 31, 2018), which was recognized in profit or loss for the year, mainly as a result of the positive impact that the depreciation of the Argentine peso had on the company’s profit or loss, the revenues of which is denominated in U.S. dollars. Finally, at the end of fiscal year 2021, Enel Generación Costanera recognized an impairment loss of ThUS$ 81,902 (equivalent to MARS 8,410,221 at the closing exchange rate prevailing as of December 31, 2021), to adjust the carrying amount of Property, plant and equipment at their recoverable value.

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17.  RIGHT-OF-USE ASSETS

a)Right-of-use assets

Right-of-use assets for the years ended December 31, 2021 and 2020, are detailed as follows:

Movements 2021	Land	Buildings, Net	Other Plant and equipment, Net	Right-of-use assets, Net
	ThUS$	ThUS$	ThUS$	ThUS$
Opening balance as of January 1, 2021	16,433	45,578	160,409	222,420
New contracts of right-of-use assets	51,624	50,984	32,675	135,283
Increases (decreases) from foreign currency translation differences	(4,597)	(6,031)	(15,300)	(25,928)
Removals	—	(54)	(55)	(109)
Acquisitions through business combinations	30,317	511	211	31,039
Depreciation	(4,001)	(10,718)	(21,312)	(36,031)
Argentine hyperinflationary economy	—	52	—	52
Other increases (decreases)	468	383	376	1,227
Total movements	73,811	35,127	(3,405)	105,533
Closing balance as of December 31, 2021	90,244	80,705	157,004	327,953

Movements 2020	Land	Buildings, Net	Other Plant and equipment, Net	Right-of-use assets, Net
	ThUS$	ThUS$	ThUS$	ThUS$
Opening balance as of January 1, 2020	3,023	66,858	185,918	255,799
New contracts of right-of-use assets	14,080	551	4,546	19,177
Increases (decreases) from foreign currency translation differences	555	(10,472)	(21,080)	(30,997)
Removals	—	(75)	(159)	(234)
Depreciation	(1,357)	(11,366)	(23,768)	(36,491)
Other increases (decreases)	132	82	14,952	15,166
Total movements	13,410	(21,280)	(25,509)	(33,379)
Closing balance as of December 31, 2020	16,433	45,578	160,409	222,420

As of December 31, 2021 and 2020, the main right-of-use assets and lease liabilities are detailed as follows:

- On July 21, 2016, a lease contract was signed with Banco de Crédito del Perú. That lease is for a 5-year term at a fixed rate of 3.68% in U.S. dollars, with quarterly amortization that began the second half of 2018. This lease was signed to finance a compressor and a natural gas station for the “Cold Generation Reserve” Unit of the Malacas thermal power plant (TG5).

- Lease contract signed on December 16, 2015, with Scotiabank, which is for a six and a half-year term, at a fixed rate of 3.75% in U.S. dollars, with quarterly amortization that began in September 2017. This lease was signed to finance the new TG-6 turbine for the Malacas thermal power plant (TG6).

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The present value of future payments derived from those contracts is detailed as follows:

	12-31-2021			12-31-2020
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Less than one year	74,651	13,964	60,687	56,509	5,017	51,492
From one to two years	37,454	13,003	24,451	32,680	4,718	27,962
From two to three years	28,035	11,520	16,515	16,395	3,454	12,941
From three to four years	24,810	10,323	14,487	12,393	2,818	9,575
From one to five years	23,825	9,003	14,822	11,798	2,073	9,725
More than five years	149,473	31,857	117,616	36,747	5,882	30,865
Total	338,248	89,670	248,578	166,522	23,962	142,560

b)Short-term and low value leases

The consolidated statement of income for the years ended December 31, 2021, 2020 and 2019 includes expenses in the amount of ThUS$ 2,728, ThUS$ 10,641 and ThUS$ 10,341, respectively, that correspond to short-term rental payments for a total amount of ThUS$ 1,332 in 2021, ThUS$ 3,046 in 2020 and ThUS$ 4,040 in 2019, lease of low value underlying assets in the amount of ThUS$ 43 in 2021, ThUS$ 1,281 in 2020 and ThUS$ 226 in 2019 and amounts related to variable leases in the amount of ThUS$ 1,353 in 2021, ThUS$ 6,314 in 2020 and ThUS$ 6,075 in 2019, which are exempt from the application of IFRS 16 (See Note 3.f).

As of December 31, 2021, and 2020 future payments derived from those contracts are detailed as follows:

	12-31-2021	12-31-2020
	ThUS$	ThUS$
Less than one year	32	196
From one to two years	—	1,281
From two to three years	—	—
From three to four years	—	—
From four to five years	—	—
More than five years	—	—
Total	32	1,477

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18. INCOME TAX AND DEFERRED TAXES

a) Income taxes

The components of income tax for the years ended December 31, 2021, 2020 and 2019 are detailed as follows:

	For the years ended December 31,
	2021	2020	2019
Current Income Tax and Adjustments to Current Income Tax for Previous Periods	ThUS$	ThUS$	ThUS$
Income tax benefit (expense)	(663,161)	(559,077)	(676,112)
Tax benefit from tax losses, tax credits or temporary differences not previously recognized for the current period (current tax credits and/or benefits)	11,381	8,956	7,426
Adjustments to current tax from the previous period	7,081	4,250	23,419
(Expense) / Income from current taxes related to movements in tax rates or the imposition of new taxes	(1,913)	—	—
Current tax (expenses) / benefit (related to cash flow hedges)	6,440	18	845
Current tax expense, net	(640,172)	(545,853)	(644,422)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences	(48,477)	(20,707)	415,513
Benefit / (expense) from deferred taxes due to movements in tax rates or the introduction of new taxes	(117,643)	—	(7,437)
Total deferred tax benefit / (expense)	(166,120)	(20,707)	408,076
Income tax expense	(806,292)	(566,560)	(236,346)

The following table reconciles income taxes resulting from applying the local current tax rate to “Net income before taxes” and the actual income tax expense recognized in the consolidated statement of comprehensive income for the years ended December 31, 2021, 2020 and 2019:

		2021		2020		2019
Reconciliation of Tax Expense	Tax Rate	ThUS$	Tax Rate	ThUS$	Tax Rate	ThUS$
ACCOUNTING INCOME BEFORE TAX		1,940,803		1,747,812		2,406,109
Total tax income (expense) using statutory rate	(27.00)%	(524,017)	(27.00)%	(471,909)	(27.00)%	(649,649)
Tax effect of rates applied in other countries	(4.15)%	(80,532)	(4.67)%	(81,699)	(5.23)%	(125,912)
Tax effect of tax-exempt revenue and other positive effects impacting the effective rate	4.04%	78,335	5.41%	94,578	26.31%	633,125
Tax effect of non-deductible expenses for determining taxable profit (loss)	(8.73)%	(169,516)	(6.40)%	(111,780)	(4.57)%	(109,892)
Tax effect of changes in income tax rates	(6.06)%	(117,643)	—	—	(0.31)%	(7,437)
Tax effect of adjustments to income taxes in previous periods	0.36%	7,081	0.24%	4,250	0.97%	23,419
Total adjustments to tax expense using statutory rate	(14.54)%	(282,275)	(5.42)%	(94,651)	17.17%	413,303
Income tax benefit (expense)	(41.54)%	(806,292)	(32.42)%	(566,560)	(9.83)%	(236,346)

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The main temporary differences are described below:

b) Deferred taxes

The table below shows the balances of the deferred tax assets and liabilities presented in the consolidated statement of financial position at December 31, 2021 and 2020:

	December 31, 2021		December 31, 2020
Assets/(Liabilities) for Deferred Taxes	Assets	Liabilities	Assets	Liabilities
	ThUS$	ThUS$	ThUS$	ThUS$
Depreciation	14,577	(655,097)	17,717	(448,711)
Amortization	3,540	(26,501)	4,161	(16,505)
Obligations for post-employment benefits	445,962	(172)	498,424	—
Revaluations of financial instruments	19,328	(16,378)	2,274	(31,883)
Tax loss	401,677	-	209,339	—
Provisions	658,884	(317,525)	630,331	(205,151)
Provision for Civil Contingencies	51,734	—	247,400	—
Provision Contingencies Workers	56,349	—	28,467	—
Provision for doubtful trade accounts	284,991	—	121,764	—
Provision of Human Resources accounts	19,674	—	18,724	—
Financial assets IFRIC 12	—	(273,855)	—	(194,045)
Other Provisions	246,136	(43,670)	213,976	(11,106)
Other Deferred Taxes	284,405	(699,732)	197,727	(476,294)
Amortization PPA - (Enel Distribución Goiás)	—	(67,579)	—	(75,497)
Price – Level Adjustment - Argentina	—	(277,507)	—	(289,158)
Other Deferred Taxes	284,405	(354,646)	197,727	(111,639)
Deferred taxes Assets/(Liabilities) before compensation	1,828,373	(1,715,405)	1,559,973	(1,178,544)
Compensation deferred taxes Assets/Liabilities	(836,005)	836,005	(565,591)	565,591
Deferred taxes Assets/(Liabilities) after compensation	992,368	(879,400)	994,382	(612,953)

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The origin and changes in deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows:

		Movements
Deferred Taxes Assets/(Liabilities)	Net balance as of January 1, 2021	Recognized in profit or loss	Recognized in comprehensive income	Acquisitions Through Business Combinations	Foreign currency translation difference	Other increases (decreases)	Net balance as of December 31, 2021
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Depreciation	(430,994)	(145,375)	—	(42,981)	88,696	(109,866)	(640,520)
Amortization	(12,344)	(468)	—	—	(10,149)	—	(22,961)
Obligations for post-employment benefits	498,424	(19,807)	(2,751)	—	(30,411)	335	445,790
Revaluations of financial instruments	(29,609)	25,499	(2,386)	8,513	(1,480)	2,413	2,950
Tax loss	209,339	191,222	—	32,799	(31,442)	(241)	401,677
Provisions	425,180	(22,332)	—	(34,689)	(16,209)	(10,591)	341,359
Decommissioning Provision	—	(244)	—	225	19		—
Provision for Civil Contingencies	247,400	(193,342)	—	—	(2,324)	—	51,734
Provision Contingencies Workers	28,467	30,735	—	—	(2,853)	—	56,349
Provision for doubtful trade accounts	121,764	186,050	—	—	(26,337)	3,514	284,991
Provision of Human Resources accounts	18,724	2,510	—	277	(1,777)	(60)	19,674
Financial assets IFRIC 12	(194,045)	(83,865)	—	—	22,991	(18,936)	(273,855)
Other Provisions	202,870	35,824	—	(35,191)	(5,928)	4,891	202,466
Other Deferred Taxes	(278,567)	(194,859)	—	12,385	31,376	14,338	(415,327)
Amortization PPA - (Enel Distribución Goiás)	(75,497)	2,923	—	—	4,995	—	(67,579)
Price – Level Adjustment - Argentina	(289,158)	16,618	—	—	87	(5,054)	(277,507)
Other Deferred Taxes	86,088	(214,400)	—	12,385	26,294	19,392	(70,241)
Deferred Taxes Assets/(Liabilities)	381,429	(166,120)	(5,137)	(23,973)	30,381	(103,612)	112,968

		Movements
Deferred Taxes Assets/(Liabilities)	Net balance as of January 1, 2020	Recognized in profit or loss	Recognized in comprehensive income	Acquisitions Through Business Combinations	Foreign currency translation difference	Other increases (decreases)	Net balance as of December 31, 2020
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Depreciation	(482,513)	(8,120)	—	—	94,913	(35,274)	(430,994)
Amortization	(16,055)	91	—	—	3,620	—	(12,344)
Obligations for post-employment benefits	552,606	(93,757)	161,330	—	(122,045)	290	498,424
Revaluations of financial instruments	(10,415)	(26,693)	5,056	—	2,446	(3)	(29,609)
Tax loss	281,080	(10,184)	—	—	(63,849)	2,292	209,339
Provisions	399,613	83,431	—	—	(88,945)	31,081	425,180
Provision for Civil Contingencies	241,520	(1,643)	—	—	(26,933)	34,456	247,400
Provision Contingencies Workers	36,878	3,618	—	—	(7,150)	(4,879)	28,467
Provision for doubtful trade accounts	122,104	53,041	—	—	(44,237)	(9,144)	121,764
Provision of Human Resources accounts	16,339	3,395	—	—	(1,010)	—	18,724
Financial assets IFRIC 12	(207,425)	(34,068)	—	—	46,864	584	(194,045)
Other Provisions	190,197	59,088	—	—	(56,479)	10,064	202,870
Other Deferred Taxes	(279,936)	34,525	—	—	12,380	(45,536)	(278,567)
Amortization PPA - (Enel Distribución Goiás)	(105,236)	3,054	—	—	22,828	3,857	(75,497)
Price – Level Adjustment - Argentina	(285,210)	(4,001)	—	—	290	(237)	(289,158)
Other Deferred Taxes	110,510	35,472	—	—	(10,738)	(49,156)	86,088
Deferred Taxes Assets/(Liabilities)	444,380	(20,707)	166,386	—	(161,480)	(47,150)	381,429

Recovery of deferred tax assets will depend on whether sufficient taxable profits are obtained in the future. The Company’s management believes that the future profit projections for its subsidiaries will allow these assets to be recovered.

c)As of December 31, 2021, the Group has not recognized deferred tax assets related to tax losses carried forward for ThUS$ 76,652 (ThUS$ 44,296 as of December 31, 2020) (see Note 3.p).

Regarding temporary differences related to investments in subsidiaries, the Group has not recognized deferred tax liabilities associated with undistributed profits, considering that control exercised by the Group over these entities allows it to manage the timing of their reversal. In addition, it is likely that these temporary differences will not be reversed in the near future. As of December 31, 2021, no deferred tax liabilities have been recognized for these taxable

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temporary differences, which amount to ThUS$ 3,288,121 (ThUS$ 2,839,057 as of December 31, 2020). In addition, no deferred tax assets have been recognized for temporary deductible differences related to investments in subsidiaries that are not expected to be reversed in the near future, or for which there are no taxable profits available for their use. As of December 31, 2021, these temporary deductible differences amount to ThUS$ 6,479,551 (ThUS$ 4,213,400 as of December 31, 2020).

The Group companies are potentially subject to income tax audits by the tax authorities of each country in which the Group operates. Such tax audits are limited to a number of annual tax periods and once these have expired, audits of these periods can no longer be performed. Tax audits by nature are often complex and can require several years to complete. The following table presents a summary of tax years potentially subject to examination:

Country	Period
Argentina	2015 - 2021
Brazil	2017 - 2021
Chile	2018 - 2021
Colombia	2016 - 2021
Costa Rica	2017 - 2021
Guatemala	2018 - 2021
Panama	2018 - 2021
Peru	2017 - 2021

Given the range of possible interpretations of tax standards, the results of any future inspections carried out by tax authorities for the years subject to audit can give rise to tax liabilities that cannot currently be quantified objectively. Nevertheless, the Company’s management estimates that the liabilities, if any, that may arise from such audits, would not significantly impact the Group companies’ future results.

The effects of deferred taxes on the components of other comprehensive income attributable to both controlling and non-controlling interests for the years ended December 31, 2021, 2020 and 2019, are as follows:

	December 31, 2021			December 31, 2020			December 31, 2019
Effects of Income Tax on the Components of Other Comprehensive Income	Amount before Tax	Income Tax Expense (Benefit)	Amount After Tax	Amount before Tax	Income Tax Expense (Benefit)	Amount After Tax	Amount before Tax	Income Tax Expense (Benefit)	Amount After Tax
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Financial assets at fair value with changes in other comprehensive income	(9)	—	(9)	(10)	—	(10)	(598)	—	(598)
Cash flow hedges	20,775	(8,826)	11,949	(12,976)	5,038	(7,938)	5,906	(2,165)	3,741
Exchange differences due to conversion	(1,193,451)	—	(1,193,451)	(2,249,915)	—	(2,249,915)	(765,005)	—	(765,005)
Gains (Losses) from new measurements in Defined Benefit Plans	9,312	(3,023)	6,289	(476,805)	161,766	(315,039)	(576,143)	195,098	(381,045)
Income tax related to components of other income and expenses with a charge or credit in equity	(1,163,373)	(11,849)	(1,175,222)	(2,739,706)	166,804	(2,572,902)	(1,335,840)	192,933	(1,142,907)

The effects of deferred taxes on the components of other comprehensive income interests for the years ended December 31, 2021, 2020 and 2019, are as follows:

	For the years ended December 31,
	2021	2020	2019
Reconciliation of deferred tax movements between Balance Sheet and income taxes in Comprehensive income	ThUS$	ThUS$	ThUS$
Total increases (decreases) for deferred taxes of other comprehensive income	(5,137)	166,386	193,778
Income tax of changes in cash flow hedge transactions	(6,440)	(18)	(845)
Deferred taxes of changes from defined benefit pension plans	(272)	436	—
Total income tax relating to components of other comprehensive income	(11,849)	166,804	192,933

d)In Colombia, Law No. 2,155, dated September 14, 2021, increased the income tax rate to 35%, from 2022 and thereafter  (32% is the current income tax rate applied to years 2021 and 2020). The effect of temporary differences that imply the payment of a lower or higher income tax in the current year is recognized as a deferred tax credit or debit, respectively, at the tax rates that are in force when the temporary differences are reversed (35% in 2022),

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provided that there is a reasonable expectation that such differences will be reversed in the future and, for deferred tax assets, that sufficient taxable profits will be available.

As a result of this increase in rates, the Colombian subsidiaries recognized as of December 31, 2021 variations in their deferred tax assets and liabilities. The increase in deferred tax expense recognized in income was ThUS$ 12,668 (see Note 18.a).

e)On June 16, 2021, the Argentine government enacted and published Law No. 27,630, which amended the income tax rates for legal entities, introducing a progressive tax regime. This new tax regime is effective for fiscal years beginning on January 1, 2021:

Net profit accumulated amount
From	Up to	Will pay	Plus the %	Over the surplus of
ARS	ARS	ARS		ARS
-	5,000,000	-	25%	-
5,000,001	50,000,000	1,250,000	20%	5,000,000
50,000,001	No maximum	14,750,000	35%	50,000,000

From January 1, 2022 and thereafter, taxable income amounts in this table will be adjusted in accordance with the annual variation of the CPI (provided by the National Institute of Statistics and Census of Argentina (“INDEC”) between October of the year prior to that of the adjustment whit respect to the same month of the prior year. The amounts thus determined will be applicable for the fiscal years beginning after each update.

Likewise, under Law No. 27,630, the tax rate applicable to dividends on profits earned in fiscal years beginning on January 1, 2018, was established at 7%.

Law No. 27,430, with the amendments to the Public Emergency Law, established the obligation to deduct or incorporate into the tax profit or loss an inflation adjustment calculated based on the procedure described in the Income Tax Law from the fiscal years beginning on January 1, 2018. However, this only occurs to the extent that the accumulated CPI variation in the 36 months prior to the end of the taxable fiscal year exceeds 100%.

As a result of the amendments introduced by the aforementioned Law, as of September 30, 2021, the current tax was calculated by applying the progressive tax rates on the taxable profits determined on that date, whereas the deferred tax balances were calculated by applying the progressive tax rate that is expected to be applicable to the estimated taxable profit for the year when the temporary differences are reversed.

As a result of the increase in tax rates, our subsidiaries in Argentina recognized an increased tax expense of ThUS$106,888 as of December 31, 2021, of which ThUS$104,975 corresponds to deferred taxes and ThUS$1,913 to current taxes (See Note 18.a).

f) On November 6, 2019 and after its approval at an Extraordinary Shareholder’s Meeting, Enel Distribución Sao Paulo merged the assets and liabilities of its parent, Enel Brasil Investimentos Sudeste S.A. (“Enel Sudeste”). The merged assets include amounts related to the concessionaire’s intangibles, as well as the recognition of the deferred tax liability on the concessionaire’s intangibles mentioned above (see Note 6.2). Once the merger was carried out, the deferred tax obligations were reversed, since the differences between the tax and accounting base at the time of the acquisition of Enel Distribución Sao Paulo were equal and will be written off in the concessionaire’s future payments. As mentioned above, the company recognized a deferred tax benefit in earnings amounting to ThUS$ 553,225 for the 2019 fiscal year.

F-105

19. OTHER FINANCIAL LIABILITIES

The balance of other financial liabilities as of December 31, 2021 and 2020, is as follows:

	December 31, 2021		December 31, 2020
	Current	Non-Current	Current	Non-Current
Other Financial Liabilities	ThUS$	ThUS$	ThUS$	ThUS$
Interest-bearing borrowings	1,181,392	4,905,270	1,815,160	3,837,697
Hedging derivatives (*)	49,245	12,313	6,730	9
Non-hedging derivatives (**)	2,197	—	3,240	—
Total	1,232,834	4,917,583	1,825,130	3,837,706

(*) See Note 22.2.a

(**) See Note 22.2.b

a) Interest-bearing borrowings.

The detail of current and non-current interest-bearing borrowings as of December 31, 2021 and 2020 is as follows:

	December 31, 2021		December 31, 2020
	Current	Non-Current	Current	Non-Current
Classes of Interest-Bearing Borrowings	ThUS$	ThUS$	ThUS$	ThUS$
Secured bank loans	251,510	1,039,303	235,404	247,150
Unsecured bank loans	415,140	1,197,748	927,075	149,057
Unsecured bonds	342,772	2,380,871	409,087	2,864,794
Secured bonds	148,881	243,725	154,955	395,289
Other obligations	23,089	43,623	88,639	181,407
Total	1,181,392	4,905,270	1,815,160	3,837,697

Bank loans by currency and contractual maturity as of December 31, 2021 and 2020 are as follows:

- Summary of bank loans by currency and maturity

					Current			Non-Current
					Maturity			Maturity
		Effective Interest	Nominal Interest	Secured /	One to three months	Three to twelve months	Total Current 12-31-2021	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12-31-2021
Country	Currency	Rate	Rate	Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	0.38%	0.38%	Unsecured	5	—	5	—	—	—	—	—	—
Chile	CLP	6.00%	6.00%	Unsecured	1	—	1	—	—	—	—	—	—
Peru	US$	1.01%	1.01%	Secured	2,025	10,188	12,213	12,000	12,000	12,000	12,000	76,000	124,000
Peru	US$	1.61%	1.60%	Unsecured	2	—	2	—	38,032	—	—	—	38,032
Peru	PEN	2.31%	2.28%	Unsecured	91	243,805	243,896	35,047	57,578	—	—	—	92,625
Brazil	US$	2.18%	2.10%	Secured	12,776	99,498	112,274	54,715	95,122	82,529	23,377	152,318	408,061
Brazil	BRL	9.27%	9.13%	Secured	86,135	32,150	118,285	37,906	32,799	32,183	32,566	283,737	419,191
Brazil	EUR	2.39%	2.28%	Unsecured	—	7,414	7,414	11,879	11,879	9,647	7,414	46,183	87,002
Brazil	US$	1.93%	1.92%	Unsecured	26,738	—	26,738	118,319	240,246	116,725	55,790	—	531,080
Brazil	BRL	5.29%	5.20%	Unsecured	17	—	17	55,824	49,901	17	17	52	105,811
Colombia	COP	0.00%	0.00%	Secured	331	993	1,324	1,049	—	—	—	—	1,049
Colombia	COP	3.55%	3.53%	Unsecured	1,968	142,513	144,481	33,760	32,096	23,770	230,009	110,565	430,200
		Total			130,089	536,561	666,650	360,499	569,653	276,871	361,173	668,855	2,237,051
					Current			Non-Current
					Maturity			Maturity
		Effective Interest	Nominal Interest	Secured /	One to three months	Three to twelve months	Total Current 12-31-2020	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12-31-2020
Country	Currency	Rate	Rate	Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	2.65%	0.94%	Unsecured	175,040	150,196	325,236	—	—	—	—	—	—
Chile	CLP	6.00%	6.00%	Unsecured	1	—	1	—	—	—	—	—	—
Peru	US$	2.62%	2.59%	Unsecured	—	25,043	25,043	—	—	—	—	—	—
Peru	PEN	2.75%	2.71%	Unsecured	157	168,609	168,766	46,989	38,697	—	—	—	85,686
Brazil	US$	3.98%	3.63%	Secured	134,692	75,656	210,348	164,746	—	2,778	—	—	167,524
Brazil	BRL	5.52%	5.41%	Secured	7,747	15,847	23,594	21,268	15,779	9,881	8,953	20,922	76,803
Brazil	US$	2.21%	2.20%	Unsecured	127,016	86,730	213,746	—	—	—	—	—	—
Brazil	BRL	2.20%	2.19%	Unsecured	37,377	30,014	67,391	—	—	—	—	—	—
Colombia	COP	0.01%	0.01%	Secured	281	1,181	1,462	1,575	1,248	—	—	—	2,823
Colombia	COP	3.68%	3.62%	Unsecured	153	126,739	126,892	11,346	20,478	20,478	10,737	332	63,371
		Total			482,464	680,015	1,162,479	245,924	76,202	33,137	19,690	21,254	396,207

- Fair value measurement and hierarchy

F-106

The fair value of current and non-current bank borrowings as of December 31, 2021 was ThUS$ 2,670,119 (ThUS$ 1,552,781 as of December 31, 2020). The borrowings have been classified as Level 2 fair value measurement based on the entry data used in the valuation techniques (see Note 3.h).

● Identification of bank borrowings by company:

F-107

											December 31, 2021
											Current			Non-Current
Taxpayer			Taxpayer				Effective Interest	Nominal Interest			Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current
ID No.	Company	Country	ID No.	Financial Institution	Country	Currency	Rate	Rate	Type of Amortization	Secured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	BNP PARIBAS 4131	Brazil	BRL	8.77%	8.40%	At Maturity	Yes	74,277	—	74,277	—	—	—	—	—	—
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	BNDES CAPEX 2012 FINAME	Brazil	BRL	3.40%	3.00%	Monthly	Yes	373	1,112	1,485	618	—	—	—	—	618
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	BNP PARIBAS 4131 II	France	US$	1.70%	1.69%	At Maturity	Yes	14	39,290	39,304	—	—	—	—	—	—
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	SCOTIABANK 4131 III	Canada	US$	1.40%	1.39%	At Maturity	Yes	215	—	215	—	—	36,970	—	—	36,970
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	SCOTIABANK 4131 IV	Canada	US$	1.18%	1.17%	At Maturity	Yes	109	—	109	—	—	22,182	—	—	22,182
Foreign	Codensa	Colombia	Foreign	Banco BBVA COLOMBIA S.A.	Colombia	COP	4.73%	4.67%	Biannual	No	—	2,055	2,055	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Banco de Bogotá S.A.	Colombia	COP	3.99%	3.95%	Monthly	No	209	638	847	837	838	838	279	—	2,792
Foreign	Codensa	Colombia	Foreign	Banco BBVA COLOMBIA S.A.	Colombia	COP	3.28%	3.26%	Biannual	No	—	7,391	7,391	16,380	16,380	8,190	—	—	40,950
Foreign	Codensa	Colombia	Foreign	Financiera de Desarrollo Territorial S.A.	Colombia	COP	0.00%	0.00%	Monthly	Yes	114	342	456	304	—	—	—	—	304
Foreign	Codensa	Colombia	Foreign	Financiera de Desarrollo Territorial S.A.	Colombia	COP	0.00%	0.00%	Monthly	Yes	150	451	601	501	—	—	—	—	501
Foreign	Codensa	Colombia	Foreign	Financiera de Desarrollo Territorial S.A.	Colombia	COP	0.00%	0.00%	Monthly	Yes	66	199	265	244	—	—	—	—	244
Foreign	Codensa	Colombia	Foreign	Banco Itaú CorpBanca Colombia SA	Colombia	COP	2.74%	2.72%	Monthly	No	280	845	1,125	1,121	93	—	—	—	1,214
Foreign	Codensa	Colombia	Foreign	Banco Itaú CorpBanca Colombia SA	Colombia	COP	2.59%	2.57%	Monthly	No	842	2,532	3,374	281	—	—	—	—	281
Foreign	Codensa	Colombia	Foreign	Banco Itaú CorpBanca Colombia SA	Colombia	COP	2.65%	2.63%	Monthly	No	215	648	863	144	—	—	—	—	144
Foreign	Codensa	Colombia	Foreign	Banco Itaú CorpBanca Colombia SA	Colombia	COP	2.80%	2.78%	Monthly	No	64	193	257	257	43	—	—	—	300
Foreign	Codensa	Colombia	Foreign	Bancolombia	Colombia	COP	2.82%	2.80%	Quarterly	No	—	50,218	50,218	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bancolombia	Colombia	COP	2.82%	2.80%	Quarterly	No	—	61,103	61,103	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Scotiabank Colpatria S.A.	Colombia	COP	3.64%	3.61%	Quarterly	No	—	457	457	—	—	—	98,280	—	98,280
Foreign	Codensa	Colombia	Foreign	Bancolombia	Colombia	COP	2.74%	2.72%	Annual	No	—	15,690	15,690	14,742	14,742	14,742	14,742	—	58,968
Foreign	Codensa	Colombia	Foreign	Banco BBVA COLOMBIA S.A.	Colombia	COP	5.80%	5.72%	Quarterly	No	—	495	495	—	—	—	52,826	—	52,826
Foreign	Codensa	Colombia	Foreign	Bancolombia	Colombia	COP	4.42%	4.37%	Quarterly	No	—	248	248	—	—	—	63,882	—	63,882
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNDES CAPEX 12 FINAME	Brazil	BRL	3.39%	3.00%	Monthly	Yes	186	555	741	370	—	—	—	—	370
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BANCO DO Brasil (BOND D)	USA.	US$	1.31%	1.17%	At Maturity	Yes	3	—	3	—	1,143	—	—	—	1,143
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BANCO DO Brasil (BOND P)	USA.	US$	6.37%	6.36%	At Maturity	Yes	21	—	21	—	1,638	—	—	—	1,638
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNB Contrato Nº 16.2018.204.23875 - SEMIÁRIDO	Brazil	BRL	12.78%	12.77%	Monthly	Yes	1,175	3,432	4,607	4,576	4,576	4,576	4,576	6,102	24,406
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNB Contrato Nº 16.2018.204.23875 - OUTRAS REGIÕES	Brazil	BRL	12.78%	12.77%	Monthly	Yes	1,043	3,093	4,136	4,123	4,123	4,123	4,123	5,498	21,990
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	FINEP - COELCE	Brazil	BRL	5.93%	5.75%	Monthly	No	—	—	—	17	17	17	17	52	120
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	SCOTIABANK 4131 III - COELCE	Canada	US$	1.23%	1.22%	At Maturity	No	473	—	473	78,112	—	—	—	—	78,112
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNP 4131 II - COELCE	France	US$	2.15%	2.14%	At Maturity	No	131	—	131	—	23,523	—	—	—	23,523
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNP 4131 III - COELCE	France	US$	1.56%	1.55%	At Maturity	No	23,619	—	23,619	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	SCOTIABANK 4131 - COELCE IV	Canada	US$	1.46%	1.45%	At Maturity	No	283	—	283	40,207	—	—	—	—	40,207
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Sumitomo 4131 - COELCE	Japan	US$	2.10%	2.09%	At Maturity	No	228	—	228	—	50,094	—	—	—	50,094
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	BANCO SCOTIABANK	Peru	PEN	2.35%	2.33%	At Maturity	No	10	—	10	—	25,034	—	—	—	25,034
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	BANCO INTERNACIONAL DEL PERU S.A	Peru	PEN	3.75%	3.70%	At Maturity	No	76	42,557	42,633	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Banco de Credito del Perú S.A.	Peru	PEN	2.61%	2.58%	At Maturity	No	—	—	—	35,047	—	—	—	—	35,047
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	SCOTIABANK PERU S.A.A	Peru	PEN	3.70%	3.65%	At Maturity	No	3	—	3	—	32,544	—	—	—	32,544
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	BNDES CG 2018	Brazil	BRL	16.91%	16.90%	Monthly	Yes	1,817	5,226	7,043	2,903	—	—	—	—	2,903
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	SCOTIABANK 4131 CELG	USA.	US$	2.39%	2.38%	At Maturity	Yes	391	48,762	49,153	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	97036000-k	Linea sobregiro (banco santander)	Chile	CLP	6.00%	6.00%	At Maturity	No	1	—	1	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Comitment Fee (BBVA NY)	USA.	US$	0.38%	0.38%	Quarterly	No	5	—	5	—	—	—	—	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	FINEP - 2º Protocolo	Brazil	BRL	4.08%	3.75%	Monthly	Yes	576	1,817	2,393	2,474	865	—	—	—	3,339
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	BNP 4131 II - ELETROPAULO	France	US$	1.71%	1.70%	At Maturity	No	237	—	237	—	44,097	—	—	—	44,097
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	BNP 4131 III - ELETROPAULO	France	US$	1.96%	1.95%	At Maturity	No	335	—	335	—	83,785	—	—	—	83,785
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	SCOTIABANK 4131 II – ELETROPAULO	Canada	US$	2.30%	2.29%	At Maturity	No	111	—	111	—	—	39,508	—	—	39,508
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	BNP 4131 IV - ELETROPAULO	France	BRL	8.56%	8.41%	At Maturity	No	12	—	12	—	49,885	—	—	—	49,885
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	SCOTIABANK 4131 III – ELETROPAULO	Canada	US$	2.57%	2.56%	At Maturity	No	509	—	509	—	—	—	55,790	—	55,790
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	MUFG 4131 – ELETROPAULO	Brazil	US$	1.89%	1.88%	At Maturity	No	238	—	238	—	38,747	—	—	—	38,747
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	SCOTIABANK 4131 IV	Canada	US$	2.31%	2.30%	At Maturity	No	573	—	573	—	—	77,217	—	—	77,217
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	7ª emissão de Notas Promissórias - 3ª série	Brazil	BRL	6.30%	6.29%	At Maturity	No	—	—	—	55,807	—	—	—	—	55,807
Foreign	Enel Generación Piura S.A.	Peru	Foreign	BBVA CONTINENTAL	Peru	US$	1.61%	1.60%	At Maturity	No	2	—	2	—	38,032	—	—	—	38,032
Foreign	Enel Perú S.A.C.	Peru	Foreign	SCOTIABANK	Peru	PEN	0.55%	0.55%	At Maturity	No	2	155,209	155,211	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA	Colombia	COP	3.50%	3.50%	At Maturity	No	175	—	175	—	—	—	—	24,570	24,570
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BANCOLOMBIA	Colombia	COP	4.02%	4.02%	At Maturity	No	130	—	130	—	—	—	—	36,855	36,855
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BANCOLOMBIA	Colombia	COP	4.34%	4.34%	At Maturity	No	53	—	53	—	—	—	—	49,140	49,140
Foreign	EGP Cachoeira Dourada S.A.	Brazil	Foreign	SCOTIABANK 4131	Canada	US$	1.47%	1.46%	At Maturity	Yes	84	—	84	31,338	—	—	—	—	31,338
Foreign	EGP Perú S.A.	Peru	Foreign	EUROPEAN INVESTMENT BANK	Peru	US$	1.01%	1.01%	Biannual	Yes	2,025	10,188	12,213	12,000	12,000	12,000	12,000	76,000	124,000
Foreign	Enel Generación Perú S.A.	Peru	Foreign	BANCO CONTINENTAL	Peru	PEN	0.88%	0.88%	At Maturity	No	—	46,039	46,039	—	—	—	—	—	—
Foreign	Enel Trading Brazil S.A.	Brazil	Foreign	Banco Itaú S.A.	Brazil	BRL	0.35%	0.35%	At Maturity	No	4	—	4	—	—	—	—	—	—
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	10.15%	10.14%	Monthly	Yes	71	245	316	391	429	468	507	10,803	12,598
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	12.00%	11.99%	Monthly	Yes	216	472	688	646	626	649	652	8,577	11,150
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	11.96%	11.95%	Monthly	Yes	226	486	712	735	754	760	778	9,226	12,253
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	12.07%	12.06%	Monthly	Yes	220	481	701	658	637	661	664	8,735	11,355
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	11.94%	11.93%	Monthly	Yes	214	450	664	617	690	680	678	9,574	12,239
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	12.03%	12.02%	Monthly	Yes	650	1,416	2,066	1,890	1,926	1,866	1,936	26,062	33,680
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	12.01%	12.00%	Monthly	Yes	214	456	670	615	623	623	620	9,381	11,862
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	15.57%	15.56%	Monthly	Yes	91	110	201	170	196	220	251	10,294	11,131
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco do Nordeste	Brazil	BRL	15.66%	15.65%	Monthly	Yes	638	274	912	435	516	599	695	31,886	34,131
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Santander (Brazil) S.A.	Brazil	US$	2.20%	1.98%	Biannual	Yes	1,910	1,774	3,684	3,684	3,684	3,684	3,684	20,396	35,132
Foreign	Grupo EGP Brasil	Brazil	Foreign	Bank of China LTD- Milan Branch	China	US$	2.20%	1.98%	Biannual	Yes	2,058	2,058	4,116	4,116	4,116	4,116	4,116	22,640	39,104
Foreign	Grupo EGP Brasil	Brazil	Foreign	SOCIÉTÉ DE PROMOTION ET DE PARTICIPATION POUR LA COOPÉRATION ECONOMIQUE S.A.	France	EUR	2.39%	2.28%	Biannual	Yes	—	7,414	7,414	11,879	11,879	9,647	7,414	46,183	87,002
Foreign	Grupo EGP Brasil	Brazil	Foreign	SCOTIABANK 4131	Canada	US$	1.87%	1.86%	Biannual	Yes	—	—	—	—	68,964	—	—	—	68,964
Foreign	Grupo EGP Brasil	Brazil	Foreign	SAN 4131 EGP- 1	Spain	US$	2.12%	1.98%	Biannual	Yes	2,110	2,108	4,218	4,217	4,216	4,218	4,218	29,522	46,391
Foreign	Grupo EGP Brasil	Brazil	Foreign	CHINA 4131 EGP- 1	Italy	US$	2.12%	1.98%	Biannual	Yes	2,196	2,195	4,391	4,389	4,388	4,390	4,389	30,726	48,282
Foreign	Grupo EGP Brasil	Brazil	Foreign	SAN 4131 EGP- 2	Spain	US$	2.12%	1.98%	Biannual	Yes	1,705	1,348	3,053	3,044	3,044	3,044	3,044	21,551	33,727
Foreign	Grupo EGP Brasil	Brazil	Foreign	CHINA 4131 EGP- 2	England	US$	2.12%	1.98%	Biannual	Yes	1,964	1,963	3,927	3,926	3,926	3,926	3,926	27,484	43,188
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	6.59%	6.45%	Monthly	Yes	513	1,540	2,053	2,053	2,053	2,053	2,053	16,425	24,637
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	6.59%	6.45%	Monthly	Yes	272	816	1,088	1,088	1,088	1,088	1,088	8,432	12,784
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	7.17%	6.93%	Monthly	Yes	313	939	1,252	1,253	1,253	1,253	1,253	13,152	18,164
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	6.60%	6.45%	Monthly	Yes	608	1,825	2,433	2,434	2,434	2,434	2,434	18,861	28,597
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	6.91%	6.77%	Monthly	Yes	261	865	1,126	1,136	1,291	1,408	1,536	12,079	17,450
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	7.01%	6.77%	Monthly	Yes	478	1,435	1,913	1,914	1,914	1,914	1,914	20,092	27,748
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	4.88%	4.75%	Monthly	Yes	2	6	8	7	8	8	9	64	96
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	6.50%	6.27%	Monthly	Yes	460	1,380	1,840	1,840	1,840	1,840	1,840	16,563	23,923
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	6.32%	6.09%	Monthly	Yes	429	1,286	1,715	1,714	1,714	1,714	1,714	15,428	22,284
Foreign	Grupo EGP Brasil	Brazil	Foreign	Banco Nacional de Desenvol. Econômico Social	Brazil	BRL	6.85%	6.61%	Monthly	Yes	811	2,434	3,245	3,245	3,245	3,245	3,245	26,502	39,482
Total											130,089	536,561	666,650	360,499	569,653	276,871	361,173	668,855	2,237,051

F-108

											December 31, 2020
											Current			Non-Current
Taxpayer			Taxpayer				Effective Interest	Nominal Interest			Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- current
ID No.	Company	Country	ID No.	Financial Institution	Country	Currency	Rate	Rate	Type of Amortization	Secured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	BNP PARIBAS 4131	U.S.A	US$	8.73%	8.40%	Upon expiration	Yes	2,641	—	2,641	77,010	—	—	—	—	77,010
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	BNDES CAPEX 2012 FINAME	Brazil	BRL	3.01%	3.00%	Monthly	Yes	402	1,192	1,594	1,590	662	—	—	—	2,252
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	BNP PARIBAS 4131 II	Brazil	US$	2.72%	2.71%	Upon expiration	Yes	14	—	14	39,235	—	—	—	—	39,235
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	ITAÚ 4131	Brazil	US$	4.35%	4.34%	Monthly	Yes	1,575	75,656	77,231	—	—	—	—	—	—
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	CITIBANK 4131 II	Brazil	US$	1.76%	1.46%	Monthly	Yes	96,923	—	96,923	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	FINDETER	Colombia	COP	0.01%	0.01%	Upon expiration	Yes	26	237	263	316	290	—	—	—	606
Foreign	Codensa	Colombia	Foreign	FINDETER	Colombia	COP	0.01%	0.01%	Upon expiration	Yes	119	537	656	715	596	—	—	—	1,311
Foreign	Codensa	Colombia	Foreign	FINDETER	Colombia	COP	0.01%	0.01%	Upon expiration	Yes	136	407	543	543	362	—	—	—	905
Foreign	Codensa	Colombia	Foreign	BANCO BBVA COLOMBIA S.A.	Colombia	COP	2.63%	2.60%	Biannual	No	—	4,880	4,880	2,435	—	—	—	—	2,435
Foreign	Codensa	Colombia	Foreign	BANCO DE BOGOTÁ	Colombia	COP	3.00%	2.97%	Monthly	No	11	664	675	996	996	996	996	332	4,316
Foreign	Codensa	Colombia	Foreign	BANCO BBVA COLOMBIA S.A.	Colombia	COP	3.16%	3.12%	Biannual	No	142	—	142	7,914	19,482	19,482	9,741	—	56,619
Foreign	Codensa	Colombia	Foreign	MUFG BANK LTD	Japan	COP	5.93%	5.80%	Upon expiration	No	—	121,194	121,194	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNDES CAPEX 12 FINAME	Brazil	COP	3.01%	3.00%	Monthly	Yes	201	595	796	793	397	—	—	—	1,190
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BANCO DO BRASIL (BOND D)	Brazil	BRL	2.33%	1.67%	Upon expiration	Yes	3	—	3	—	—	1,143	—	—	1,143
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BANCO DO BRASIL (BOND P)	Brazil	BRL	6.31%	6.30%	Upon expiration	Yes	21	—	21	—	—	1,636	—	—	1,636
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNB Nº 16.2018.204.23875	Brazil	BRL	6.27%	6.26%	Monthly	Yes	2,404	3,525	5,929	4,700	4,700	4,700	4,700	10,967	29,767
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	BNB Nº 16.2018.204.23875	Brazil	BRL	6.27%	6.26%	Monthly	Yes	2,166	3,176	5,342	4,235	4,235	4,235	4,235	9,881	26,821
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	SCOTIABANK 4131 - COELCE	Brazil	BRL	2.22%	2.21%	Upon expiration	No	37,251	—	37,251	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	TOKIO 4131	Brazil	BRL	1.69%	1.68%	Upon expiration	No	31,769	—	31,769	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	TOKIO 4131 II	Brazil	BRL	1.79%	1.78%	Upon expiration	No	10,637	—	10,637	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	SCOTIABANK 4131 II - COELCE	Brazil	BRL	2.18%	2.17%	Upon expiration	No	127	30,014	30,141	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	FINEP - COELCE	Brazil	BRL	6.48%	5.80%	Upon expiration	Yes	—	—	—	—	18	18	18	74	128
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	BANCO DE CREDITO DEL PERÚ S.A.	Peru	PEN	4.16%	4.10%	Upon expiration	No	38	20,731	20,769	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	BANCO INTERCIONAL DEL PERÚ S.A.A.	Peru	PEN	3.75%	3.70%	Upon expiration	No	58	—	58	46,989	—	—	—	—	46,989
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	BANCO DE CREDITO DEL PERÚ S.A.	Peru	PEN	2.61%	2.58%	Upon expiration	No	62	—	62	—	38,698	—	—	—	38,698
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	BNDES CG 2018	Brazil	BRL	9.61%	9.60%	Monthly	Yes	1,990	5,604	7,594	7,471	3,113	—	—	—	10,584
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	SCOTIABANK 4131 CELG	U.S.A	US$	2.98%	2.30%	Upon expiration	Yes	390	—	390	—	—	—	—	—	—
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	BNP 4131 II	U.S.A	US$	2.64%	1.84%	Upon expiration	Yes	33,124	—	33,124	48,504	—	—	—	—	48,504
94.271.000-3	Enel Américas S.A.	Chile	Foreign	BNP PARIBAS NY	U.S.A	US$	4.99%	0.85%	Upon expiration	No	45,000	—	45,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	CITIBANK N.A	U.S.A	US$	4.99%	0.85%	Upon expiration	No	15,000	—	15,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	CREDIT AGRICOLE CIB	U.S.A	US$	4.99%	0.85%	Upon expiration	No	15,035	—	15,035	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	JPMORGAN CHASE BANK	U.S.A	US$	4.99%	0.85%	Upon expiration	No	15,000	—	15,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	SUMITOMO MITSUI BANKING	U.S.A	US$	4.99%	0.85%	Upon expiration	No	30,000	—	30,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	SOCIETE GENERALE	U.S.A	US$	4.99%	0.85%	Upon expiration	No	15,000	—	15,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	BBVA NEW YORK BRANCH	U.S.A	US$	4.99%	0.85%	Upon expiration	No	15,000	—	15,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	BBVA S.A NEW YORK BRANCH	U.S.A	US$	1.38%	1.38%	Upon expiration	No	—	50,196	50,196	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	CREDIT AGRICOLE CIB	U.S.A	US$	1.38%	1.38%	Upon expiration	No	—	50,000	50,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	THE BANK OF NOVA SCOTIA	U.S.A	US$	1.38%	1.38%	Upon expiration	No	—	50,000	50,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	BNP PARIBAS NY	U.S.A	US$	0.84%	0.84%	Upon expiration	No	7,500	—	7,500	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	CITIBANK N.A	U.S.A	US$	0.84%	0.84%	Upon expiration	No	2,500	—	2,500	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	CREDIT AGRICOLE CIB	U.S.A	US$	0.84%	0.84%	Upon expiration	No	2,504	—	2,504	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	JPMORGAN CHASE BANK	U.S.A	US$	0.84%	0.84%	Upon expiration	No	2,500	—	2,500	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	SUMITOMO MITSUI BANKING	U.S.A	US$	0.84%	0.84%	Upon expiration	No	5,000	—	5,000	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	SOCIETE GENERALE	U.S.A	US$	0.84%	0.84%	Upon expiration	No	2,500	—	2,500	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	BBVA NEW YORK BRANCH	U.S.A	US$	0.84%	0.84%	Upon expiration	No	2,500	—	2,500	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	97.036.000-k	LINEA SOBREGIRO (BANCO SANTANDER)	Chile	CLP	6.00%	6.00%	Upon expiration	No	1	—	1	—	—	—	—	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	FINEP - 2º PROTOCOLO	Brazil	BRL	3.96%	3.95%	Monthly	Yes	584	1,755	2,339	2,478	2,653	927	—	—	6,058
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	TOKIO 4131	Brazil	BRL	1.79%	1.78%	Upon expiration	No	32,668	—	32,668	—	—	—	—	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	SCOTIABANK 4131 ELETROPAULO	Brazil	BRL	2.15%	2.14%	Upon expiration	No	51,421	—	51,421	—	—	—	—	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	BNP 4131 - ELETROPAULO	Brazil	US$	3.61%	3.60%	Upon expiration	No	521	86,730	87,251	—	—	—	—	—	—
Foreign	Enel Generación Piura S.A	Peru	Foreign	SCOTIABANK	Peru	US$	2.62%	2.59%	Upon expiration	No	—	25,043	25,043	—	—	—	—	—	—
Foreign	Enel Perú S.A.C	Peru	Foreign	BBVA	Peru	PEN	0.48%	0.48%	Biannual	No	—	147,879	147,879	—	—	—	—	—	—
Total											482,464	680,015	1,162,479	245,924	76,202	33,137	19,690	21,254	396,207

F-109

b)  Unsecured bonds

The detail of unsecured bonds by currency and maturity as of December 31, 2021 and 2020 is as follows:

● Summary of Unsecured bonds by currency and maturity

				Current			Non-Current
				Maturity			Maturity
		Nominal Interest	Secured /	One to three months	Three to twelve months	Total Current 12-31-2021	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12-31-2021
Country	Currency	Rate	Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	5.30%	Unsecured	—	4,405	4,405	—	—	—	590,081	—	590,081
Chile	UF	5.75%	Unsecured	—	3,305	3,305	—	—	—	—	—	—
Peru	US$	6.34%	Unsecured	—	275	275	—	—	—	—	10,008	10,008
Peru	PEN	6.02%	Unsecured	3,198	30,223	33,421	40,054	38,153	35,047	25,034	148,575	286,863
Brazil	BRL	10.39%	Unsecured	41,089	34,877	75,966	58,317	174,791	85,741	159,548	232,860	711,257
Colombia	COP	8.24%	Unsecured	11,659	213,741	225,400	187,978	169,988	185,806	—	238,890	782,662
Total				55,946	286,826	342,772	286,349	382,932	306,594	774,663	630,333	2,380,871
				Current			Non-Current
				Maturity			Maturity
		Nominal Interest	Secured /	One to three months	Three to twelve months	Total Current 12-31-2020	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12-31-2020
Country	Currency	Rate	Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	5.30%	Unsecured	—	4,405	4,405	—	—	—	—	588,112	588,112
Chile	UF	5.75%	Unsecured	—	7,103	7,103	3,611	—	—	—	—	3,611
Peru	US$	6.34%	Unsecured	—	275	275	—	—	—	—	10,017	10,017
Peru	PEN	6.24%	Unsecured	3,531	29,344	32,875	31,787	44,225	42,126	38,697	161,837	318,672
Brazil	BRL	6.24%	Unsecured	5,425	33,691	39,116	67,383	62,493	361,796	92,308	175,405	759,385
Colombia	COP	5.74%	Unsecured	245,073	80,240	325,313	254,173	223,554	202,170	220,981	284,119	1,184,997
Total				254,029	155,058	409,087	356,954	330,272	606,092	351,986	1,219,490	2,864,794

F-110

●Unsecured bonds by company

										December 31, 2021
										Current			Non0Current
Taxpayer			Taxpayer				Effective Interest	Nominal Interest		Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non0 Current
ID No.	Company	Country	ID No.	Name	Country	Currency	Rate	Rate	Maturity	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Codensa	Colombia	Foreign	Bonds B12-13	Colombia	COP	10.31%	9.94%	At Maturity	604	—	604	—	—	47,504	—	—	47,504
Foreign	Codensa	Colombia	Foreign	Bonds E5-17	Colombia	COP	7.39%	7.39%	At Maturity	3,976	66,339	70,315	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bonds E7-17	Colombia	COP	6.46%	6.31%	At Maturity	203	—	203	—	49,140	—	—	—	49,140
Foreign	Codensa	Colombia	Foreign	Bonds E7-18	Colombia	COP	6.74%	6.58%	At Maturity	725	—	725	—	—	49,140	—	—	49,140
Foreign	Codensa	Colombia	Foreign	Bonds B12-18	Colombia	COP	9.04%	8.75%	At Maturity	772	—	772	—	—	—	—	39,312	39,312
Foreign	Codensa	Colombia	Foreign	Bonds B5-18	Colombia	COP	8.23%	7.99%	At Maturity	732	—	732	47,912	—	—	—	—	47,912
Foreign	Codensa	Colombia	Foreign	Bonds E4-19	Colombia	COP	6.30%	6.16%	At Maturity	288	—	288	68,796	—	—	—	—	68,796
Foreign	Codensa	Colombia	Foreign	Bonds B10-19	Colombia	COP	9.01%	8.72%	At Maturity	291	—	291	—	—	—	—	49,140	49,140
Foreign	Codensa	Colombia	Foreign	Bonds E4-2020	Colombia	COP	4.70%	4.62%	At Maturity	286	—	286	—	61,425	—	—	—	61,425
Foreign	Codensa	Colombia	Foreign	Bonds B7-2020	Colombia	COP	7.84%	7.62%	At Maturity	472	—	472	—	—	—	—	61,425	61,425
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 5ª EMISSÃO - 1 SÉRIE (CEAR15)	Brazil	BRL	5.29%	5.28%	Annual	—	31,448	31,448	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 5ª EMISSÃO - 2 SÉRIE (CEAR25)	Brazil	BRL	17.44%	17.43%	Annual	93	—	93	19,967	13,352	—	—	—	33,319
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 6ª EMISSÃO - 1 SÉRIE (CEAR16)	Brazil	BRL	5.44%	5.43%	At Maturity	33	—	33	7,181	—	—	—	—	7,181
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 6ª EMISSÃO - 2 SÉRIE (CEAR26)	Brazil	BRL	17.65%	17.64%	Annual	170	—	170	—	34,609	24,096	—	—	58,705
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 7ª EMISSÃO - 1 SÉRIE (COCE17)	Brazil	BRL	4.97%	4.96%	Annual	32,623	—	32,623	31,169	—	—	—	—	31,169
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 7ª EMISSÃO - 1 SÉRIE (COCE27)	Brazil	BRL	15.79%	15.78%	At Maturity	2,298	—	2,298	—	63,993	—	—	—	63,993
Foreign	Enel Generación Perú S.A.	Peru	Foreign	BBVA Terc Prog 8va Emision Serie A	Peru	US$	6.44%	6.34%	At Maturity	—	275	275	—	—	—	—	10,008	10,008
Foreign	Enel Generación Perú S.A.	Peru	Foreign	BBVA Terc Prog 1ra Emision Serie A	Peru	PEN	6.41%	6.31%	At Maturity	11	6,258	6,269	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Interseguro Cia de Seguros	Peru	PEN	6.38%	6.28%	At Maturity	—	10,150	10,150	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	6.15%	6.06%	At Maturity	—	108	108	—	—	—	—	12,517	12,517
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	FCR - Macrofondo	Peru	PEN	5.64%	5.56%	At Maturity	248	12,517	12,765	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	5.06%	5.00%	At Maturity	—	75	75	—	—	10,013	—	—	10,013
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	5.19%	5.13%	At Maturity	278	—	278	—	—	—	—	12,517	12,517
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	7.41%	7.28%	At Maturity	230	—	230	—	—	—	—	8,887	8,887
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	7.51%	7.38%	At Maturity	—	126	126	—	—	—	—	15,020	15,020
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	6.44%	6.34%	At Maturity	—	50	50	15,020	—	—	—	—	15,020
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	6.44%	6.34%	At Maturity	363	—	363	—	20,027	—	—	—	20,027
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	8.29%	8.13%	At Maturity	411	—	411	—	—	—	—	17,524	17,524
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	6.19%	6.09%	At Maturity	742	—	742	25,034	—	—	—	—	25,034
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	6.09%	6.00%	At Maturity	—	239	239	—	18,126	—	—	—	18,126
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	5.80%	5.72%	At Maturity	—	191	191	—	—	25,034	—	—	25,034
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Rimac Internacional Cia de Seguros	Peru	PEN	5.45%	5.38%	At Maturity	374	—	374	—	—	—	25,034	—	25,034
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Fondos de Gobierno	Peru	PEN	5.99%	5.91%	At Maturity	—	240	240	—	—	—	—	32,544	32,544
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	AFP	Peru	PEN	5.13%	5.06%	At Maturity	542	—	542	—	—	—	—	22,530	22,530
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	AFP, Fondos Gobierno, Seguros	Peru	PEN	4.36%	4.31%	At Maturity	—	269	269	—	—	—	—	27,036	27,036
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B15-09	Colombia	COP	11.67%	11.19%	At Maturity	212	—	212	—	13,636	—	—	—	13,636
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B10	Colombia	COP	8.97%	8.68%	At Maturity	330	73,699	74,029	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B15	Colombia	COP	9.09%	8.80%	At Maturity	223	—	223	—	—	—	—	49,113	49,113
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B12-13	Colombia	COP	10.52%	10.13%	At Maturity	515	—	515	—	—	89,161	—	—	89,161
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B16-14	Colombia	COP	9.63%	9.30%	At Maturity	465	—	465	—	—	—	—	39,900	39,900
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B10-14	Colombia	COP	9.29%	8.99%	At Maturity	516	—	516	—	45,787	—	—	—	45,787
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B7-16	Colombia	COP	10.20%	9.83%	At Maturity	975	—	975	71,270	—	—	—	—	71,270
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds E6-16	Colombia	COP	7.59%	7.38%	At Maturity	75	73,703	73,778	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Yankee bonos 2026	USA.	US$	7.76%	6.60%	At Maturity	—	5	5	—	—	—	858	—	858
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Bonds UF 269	Chile	UF	7.02%	5.75%	Biannual	—	3,305	3,305	—	—	—	—	—	—
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Yankee bonos Serie Única U.S. $ 600 millones	USA.	US$	4.21%	4.00%	At Maturity	—	4,400	4,400	—	—	—	589,223	—	589,223
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 24ª EMISSÃO 1ª SÉRIE	Brazil	BRL	5.29%	5.28%	Annual	1,463	—	1,463	—	62,837	61,646	—	—	124,483
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 24ª EMISSÃO 2ª SÉRIE	Brazil	BRL	15.24%	15.23%	At Maturity	869	—	869	—	—	—	159,548	—	159,548
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 25ª EMISSÃO	Brazil	BRL	15.77%	15.76%	Annual	1,224	—	1,224	—	—	—	—	129,755	129,755
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 26ª EMISSÃO	Brazil	BRL	9.31%	9.30%	Annual	2,244	—	2,244	—	—	—	—	103,105	103,105
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	7ª emissão de Notas Promissórias - 1ª série	Brazil	BRL	6.30%	6.29%	At Maturity	35	1,679	1,714	—	—	—	—	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	7ª emissão de Notas Promissórias - 2ª série	Brazil	BRL	6.30%	6.29%	At Maturity	35	1,750	1,785	—	—	—	—	—	—
										55,946	286,826	342,772	286,349	382,932	306,594	774,663	630,333	2,380,871

F-111

										December 31, 2020
										Current			Non Current
Taxpayer			Taxpayer				Effective Interest	Nominal Interest		Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non0 Current
ID No.	Company	Country	ID No.	Name	Country	Currency	Rate	Rate	Maturity	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Codensa	Colombia	Foreign	Bonds B12 13	Colombia	COP	6.36%	6.22%	Upon expiration	450	—	450	—	—	—	56,499	—	56,499
Foreign	Codensa	Colombia	Foreign	Bonds B7 14	Colombia	COP	5.07%	4.98%	Upon expiration	51	54,062	54,113	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bonds E5 17	Colombia	COP	7.60%	7.39%	Upon expiration	4,729	—	4,729	78,901	—	—	—	—	78,901
Foreign	Codensa	Colombia	Foreign	Bonds E7 17	Colombia	COP	6.46%	6.31%	Upon expiration	241	—	241	—	—	58,445	—	—	58,445
Foreign	Codensa	Colombia	Foreign	Bonds E7 18	Colombia	COP	6.74%	6.58%	Upon expiration	863	—	863	—	—	—	58,445	—	58,445
Foreign	Codensa	Colombia	Foreign	Bonds B12 18	Colombia	COP	5.14%	5.04%	Upon expiration	529	—	529	—	—	—	—	46,756	46,756
Foreign	Codensa	Colombia	Foreign	Bonds B5 18	Colombia	COP	4.35%	4.28%	Upon expiration	467	—	467	—	56,984	—	—	—	56,984
Foreign	Codensa	Colombia	Foreign	Bonds E4 19	Colombia	COP	6.29%	6.15%	Upon expiration	343	—	343	—	81,823	—	—	—	81,823
Foreign	Codensa	Colombia	Foreign	Bonds B10 19	Colombia	COP	5.10%	5.01%	Upon expiration	204	—	204	—	—	—	—	58,445	58,445
Foreign	Codensa	Colombia	Foreign	Bonds E4 2020	Colombia	COP	4.69%	4.61%	Upon expiration	341	—	341	—	—	73,057	—	—	73,057
Foreign	Codensa	Colombia	Foreign	Bonds B7 2020	Colombia	COP	3.98%	3.92%	Upon expiration	289	—	289	—	—	—	—	73,057	73,057
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 5ª EMISSÃO - 1 SÉRIE (CEAR15)	Brazil	BRL	3.60%	3.59%	Annual	79	33,691	33,770	33,691	—	—	—	—	33,691
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 5ª EMISSÃO - 2 SÉRIE (CEAR25)	Brazil	BRL	10.41%	10.40%	Annual	83	—	83	—	17,550	14,439	—	—	31,989
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 6ª EMISSÃO - 1 SÉRIE (CEAR16)	Brazil	BRL	3.76%	3.75%	Upon expiration	10	—	10	—	7,701	—	—	—	7,701
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 6ª EMISSÃO - 2 SÉRIE (CEAR26)	Brazil	BRL	10.61%	10.60%	Annual	151	—	151	—	—	31,524	25,017	—	56,541
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 7ª EMISSÃO - 1 SÉRIE (COCE17)	Brazil	BRL	3.29%	3.28%	Annual	473	—	473	33,691	33,050	—	—	—	66,741
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	DEBÊNTURES 7ª EMISSÃO - 1 SÉRIE (COCE27)	Brazil	BRL	9.27%	9.26%	Upon expiration	2,202	—	2,202	—	4,193	57,703	—	—	61,896
Foreign	Enel Generación Perú S.A.	Peru	Foreign	Banco Continental Terc Prog 8va Emision Series A	Peru	US$	6.44%	6.34%	Upon expiration	—	275	275	—	—	—	—	10,017	10,017
Foreign	Enel Generación Perú S.A.	Peru	Foreign	Banco Continental Terc Prog 1ra Emision Series A	Peru	PEN	6.41%	6.31%	Upon expiration	12	—	12	6,910	—	—	—	—	6,910
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 4to Programa - 9na emision Series A	Peru	PEN	6.48%	6.38%	Upon expiration	—	150	150	11,056	—	—	—	—	11,056
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 4ta Programa 11ra emision Series A	Peru	PEN	6.25%	6.15%	Upon expiration	—	119	119	—	—	—	—	13,820	13,820
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 4ta Programa 13ra emision Series A	Peru	PEN	5.72%	5.64%	Upon expiration	273	—	273	13,820	—	—	—	—	13,820
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 4ta Programa 15ta emision Series A	Peru	PEN	5.13%	5.06%	Upon expiration	—	83	83	—	—	—	11,056	—	11,056
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 4ta Programa 12va emision Series A	Peru	PEN	5.26%	5.19%	Upon expiration	307	—	307	—	—	—	—	13,820	13,820
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 5ta emision Series A	Peru	PEN	7.55%	7.41%	Upon expiration	254	—	254	—	—	—	—	9,813	9,813
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 8va emision Series A	Peru	PEN	7.65%	7.51%	Upon expiration	—	139	139	—	—	—	—	16,585	16,585
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 9na emision Series A	Peru	PEN	7.02%	6.90%	Upon expiration	—	28,057	28,057	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 10ma emision Series B	Peru	PEN	6.55%	6.44%	Upon expiration	—	56	56	—	16,585	—	—	—	16,585
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 2da emision Series A	Peru	PEN	6.55%	6.44%	Upon expiration	401	—	401	—	—	22,113	—	—	22,113
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 19na emision Series A	Peru	PEN	8.46%	8.29%	Upon expiration	454	—	454	—	—	—	—	19,349	19,349
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 20ma emision Serie A	Peru	PEN	6.28%	6.19%	Upon expiration	819	—	819	—	27,641	—	—	—	27,641
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 5to Programa 21ma emision Serie A	Peru	PEN	6.18%	6.09%	Upon expiration	—	264	264	—	—	20,013	—	—	20,013
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 6to Programa 1era emision Serie A	Peru	PEN	5.88%	5.80%	Upon expiration	—	211	211	—	—	—	27,641	—	27,641
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 6to Programa 2da emision Serie A	Peru	PEN	5.52%	5.45%	Upon expiration	413	—	413	—	—	—	—	27,641	27,641
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 6to Programa 3 emision Serie A	Peru	PEN	6.08%	5.99%	Upon expiration	—	265	265	—	—	—	—	35,933	35,933
Foreign	Enel Distribución Perú S.A.	Peru	Foreign	Bonds 6to Programa 4 emision Serie A	Peru	PEN	5.19%	5.13%	Upon expiration	598	—	598	—	—	—	—	24,877	24,877
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B15-09	Colombia	COP	7.67%	7.46%	Upon expiration	168	—	168	—	—	16,219	—	—	16,219
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B12-09	Colombia	COP	6.10%	0.00%	Upon expiration	487	26,178	26,665	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds exterior	Colombia	COP	9.11%	8.75%	Upon expiration	28,540	—	28,540	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo	Colombia	COP	9.11%	8.75%	Upon expiration	205,098	—	205,098	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B10	Colombia	COP	5.06%	4.97%	Upon expiration	226	—	226	87,644	—	—	—	—	87,644
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B15	Colombia	COP	5.18%	5.09%	Upon expiration	154	—	154	—	—	—	—	58,408	58,408
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B12-13	Colombia	COP	6.56%	6.41%	Upon expiration	389	—	389	—	—	—	106,036	—	106,036
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B16-14	Colombia	COP	5.70%	5.58%	Upon expiration	333	—	333	—	—	—	—	47,453	47,453
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B10-14	Colombia	COP	5.38%	5.27%	Upon expiration	361	—	361	—	—	54,450	—	—	54,450
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B7-16	Colombia	COP	6.25%	6.11%	Upon expiration	721	—	721	—	84,745	—	—	—	84,745
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds E6-16	Colombia	COP	7.59%	7.38%	Upon expiration	88	—	88	87,630	—	—	—	—	87,630
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Yankee bonos 2026	U.S.A	US$	7.76%	6.60%	Upon expiration	—	5	5	—	—	—	—	858	858
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Bonds UF 269	Chile	UF	7.02%	5.75%	Biannual	—	7,103	7,103	3,611	—	—	—	—	3,611
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Yankee bonds Single Series $ 600 million	U.S.A	US$	4.21%	4.00%	Upon expiration	—	4,400	4,400	—	—	—	—	587,253	587,253
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	DEBENTURES 10 EMISSION (AMPL10)	Brazil	BRL	3.01%	2.99%	Biannual	1,153	—	1,153	—	—	192,318	—	—	192,318
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 24ª EMISSÃO 1ª SÉRIE	Brazil	BRL	3.61%	3.60%	Annual	459	—	459	—	—	65,811	67,292	—	133,103
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 24ª EMISSÃO 2ª SÉRIE	Brazil	BRL	8.73%	8.72%	Upon expiration	816	—	816	—	—	—	—	175,405	175,405
Total										254,029	155,058	409,087	356,954	330,272	606,092	351,986	1,219,490	2,864,794

F-112

c)  Secured bonds

The detail of secured bonds by currency and maturity as for December 31, 2021 and 2020, is as follows.

● Summary of secured bonds by currency and maturity

Current

Non-Current

Nominal

Secured /

Maturity

Total current

Maturity

Total Non- Current

Country

Currency

Interest Rate

Unsecured

One to three months

Three to twelve months

12-31-2021

One to two years

Two to three years

Three to four years

Four to five years

More than five years

12-31-2021

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

Brazil

BRL

14.40%

Secured

6,800

142,081

148,881

142,194

16,963

17,637

17,650

49,281

243,725

Total

6,800

142,081

148,881

142,194

16,963

17,637

17,650

49,281

243,725

Current

Non-Current

Nominal

Secured /

Maturity

Total current

Maturity

Total Non- Current

Country

Currency

Interest Rate

Unsecured

One to three months

Three to twelve months

12-31-2020

One to two years

Two to three years

Three to four years

Four to five years

More than five years

12-31-2020

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

Brazil

BRL

7.31%

Secured

3,478

151,477

154,955

149,733

150,272

16,027

16,027

63,230

395,289

Total

3,478

151,477

154,955

149,733

150,272

16,027

16,027

63,230

395,289

- Secured liabilities by company

										December 31, 2021
										Current			Non-Current
Taxpayer ID No.	Company	Country	Taxpayer ID No.	Name	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Maturity	Less than 90 days	More than 90 days	Total current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current
										ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Green Power Volta Grande	Brazil	Foreign	DEBÊNTURES 1ª EMISSÃO (EGVG11) - 1ª Série	Brazil	BRL	14.92%	14.91%	Annual	596	10,663	11,259	10,814	10,814	10,814	10,814	30,931	74,187
Foreign	Enel Green Power Volta Grande	Brazil	Foreign	DEBÊNTURES 1ª EMISSÃO (EGVG21) - 2ª Série	Brazil	BRL	14.91%	14.90%	Annual	361	5,888	6,249	6,009	6,009	6,009	6,009	17,183	41,219
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 23ª EMISSÃO 2ª SÉRIE	Brazil	BRL	4.94%	4.93%	Annual	5,831	125,080	130,911	125,176	-	-	-	-	125,176
Foreign	Grupo EGP Brazil	Brazil	Foreign	Itaú Unibanco S.A.	Brazil	BRL	18.64%	18.63%	Biannual	6	200	206	108	49	350	407	716	1,630
Foreign	Grupo EGP Brazil	Brazil	Foreign	Itaú Unibanco S.A.	Brazil	BRL	18.63%	18.62%	Biannual	6	250	256	87	91	464	420	451	1,513
Total										6,800	142,081	148,881	142,194	16,963	17,637	17,650	49,281	243,725
										December 31, 2020
										Current			Non-Current
Taxpayer ID No.	Company	Country	Taxpayer ID No.	Name	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Maturity	Less than 90 days	More than 90 days	Total current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current
										ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Green Power Volta Grande	Brazil	Foreign	DEBÊNTURES 1ª EMISSÃO (EGVG11) - 1ª Série	Brazil	BRL	8.24%	8.23%	Annual	727	10,570	11,297	10,620	10,595	10,595	10,595	41,778	84,183
Foreign	Enel Green Power Volta Grande	Brazil	Foreign	DEBÊNTURES 1ª EMISSÃO (EGVG21) - 2ª Série	Brazil	BRL	8.22%	8.21%	Annual	317	5,495	5,812	5,432	5,446	5,432	5,432	21,452	43,194
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 23ª EMISSÃO 1ª SÉRIE	Brazil	BRL	3.02%	3.01%	Upon Expiration	758	135,412	136,170	-	-	-	-	-	-
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	DEBÊNTURES - 23ª EMISSÃO 2ª SÉRIE	Brazil	BRL	3.10%	3.08%	Annual	1,676	-	1,676	133,681	134,231	-	-	-	267,912
Total										3,478	151,477	154,955	149,733	150,272	16,027	16,027	63,230	395,289

F-113

● Fair value measurement and hierarchy

The fair value of current and non-current secured and unsecured liabilities as of December 31, 2021 totaled ThUS$ 3,146,336 (ThUS$ 4,017,861 as of December 31, 2020). These liabilities have been classified as Level 2 fair value measurement based on the entry data used in the valuation techniques used (see Note 3.h). It is important to note that these financial liabilities are measured at amortized cost (see Note 3 g.4.)

● Detail of other obligations

									December 31, 2021
									Current			Non-Current
Taxpayer			Taxpayer				Nominal Interest		Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current
ID No.	Company	Country	ID No.	Financial Institution	Country	Currency	Rate	Maturity	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	ECFS 0292/2010 (LUZ PARA TODOS VI)	Brazil	BRL	6.00%	Monthly	64	85	149	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	ECFS 0310/2010 (LUZ PARA TODOS VII)	Brazil	BRL	6.00%	Monthly	73	218	291	242	—	—	—	—	242
Foreign	Enel Generación Costanera S.A.	Argentina	Foreign	Mitsubishi (deuda garantizada)	Argentina	US$	0.25%	Quarterly	1,434	4,314	5,748	8,235	4,741	4,787	7,394	11,053	36,210
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	FIDC Série A	Brazil	BRL	7.57%	Monthly	975	7,304	8,279	—	—	—	—	—	—
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	FIDC Série B	Brazil	BRL	21.68%	Monthly	816	5,020	5,836	—	—	—	—	—	—
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	Mútuo CelgPar 41211376/2014	Brazil	BRL	6.80%	Monthly	604	1,729	2,333	761	398	1,860	2,050	1,862	6,931
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	Eletrobras	Brazil	BRL	6.00%	Monthly	105	316	421	160	80	—	—	—	240
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bank of Nova Scotia	Canada	US$	0.30%	Annual	13	—	13	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bank of Nova Scotia	Canada	US$	0.02%	Annual	—	19	19	—	—	—	—	—	—
Total									4,084	19,005	23,089	9,398	5,219	6,647	9,444	12,915	43,623

									December 31, 2020
									Current			Non-Current
Taxpayer			Taxpayer				Nominal Interest		Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current
ID No.	Company	Country	ID No.	Financial Institution	Country	Currency	Rate	Maturity	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	ELETROBRAS 0244/2009	Brazil	BRL	6.00%	Monthly	21	—	21	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	ELETROBRAS 0265/2009	Brazil	BRL	6.00%	Monthly	82	165	247	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	ELETROBRAS 292/2010	Brazil	BRL	6.00%	Monthly	69	206	275	160	—	—	—	—	160
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	ELETROBRAS 310/2010	Brazil	BRL	6.00%	Monthly	78	233	311	311	259	—	—	—	570
Foreign	Enel Generación Costanera S.A.	Argentina	Foreign	MITSUBISHI (DEUDA GARANTIZADA)	Argentina	US$	0.25%	Biannual	—	6,088	6,088	6,494	7,594	7,494	7,494	11,709	40,785
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	FIDC SÉRIE A	Brazil	BRL	6.15%	Monthly	1,670	7,240	8,910	7,493	3,141	—	—	—	10,634
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	FIDC SÉRIE B	Brazil	BRL	12.32%	Monthly	1,033	4,245	5,278	3,563	777	—	—	—	4,340
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	MÚTUO CELGPAR 41211376/2014	Brazil	BRL	6.80%	Monthly	613	1,736	2,349	1,630	1,797	1,975	2,165	4,506	12,073
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	ELETROBRAS	Brazil	BRL	6.00%	Monthly	113	339	452	318	318	159	—	—	795
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BANK OF NOVA SCOTIA	Colombia	COP	0.30%	Quarterly	49	—	49	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	BANK OF NOVA SCOTIA	Colombia	COP	0.02%	Monthly	45	—	45	—	—	—	—	—	—
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	FUNDAÇÃO CESP (*)	Brazil	BRL	9.47%	Quarterly	51,685	12,929	64,614	34,477	34,477	34,477	8,619	—	112,050
Total									55,458	33,181	88,639	54,446	48,363	44,105	18,278	16,215	181,407

(*) See Note 25.2.c)

d) Hedged debt

The debt denominated in U.S. dollars for ThUS$ 74,313 held by the Group as of December 31, 2021, is related to future cash flow hedges for the Group’s U.S. dollar-linked operating revenues (ThUS$ 35,064 and ThUS$ 29,474 as of December 31, 2020 and 2019, respectively) (see Note 3.n).

F-114

The following table details changes in “Reserve for cash flow hedges” for the years ended December 31, 2021, 2020 and 2019, due to exchange differences from this debt:

	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$
Balance in hedging reserves (hedging revenues) at the beginning of the year, net	(8,683)	(9,453)	(9,882)
Foreign currency exchange differences recorded in equity, net	(980)	(1,299)	424
Recognition of foreign currency exchange differences revenue, net	1,601	1,268	189
Foreign currency translation differences	790	801	(184)
Balance in hedging reserves (hedging revenues) at the end of the year, net	(7,272)	(8,683)	(9,453)

e)  Other information

As of December 31, 2021, the Group has unconditionally available long-term credit lines for an amount of ThUS $ 1,119,278. As of December 31, 2020, the Group did not have any unconditional long-term credit facilities available to it.

f) Future undiscounted debt flows

The following table shows the estimates of undiscounted cash flows by type of financial debt:

- Summary of bank loans by currencies and maturities

			Current			Non-Current
			Maturity		Total Current 12-31-2021	Maturity					Total Non-Current 12-31-2021
		Nominal Interest	One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
Country	Currency	Rate	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	0.38%	5	—	5	—	—	—	—	—	—
Peru	PEN	2.28%	1,293	200,052	201,345	37,653	58,427	—	—	—	96,080
Peru	US$	1.30%	2,611	57,665	60,276	13,877	51,341	13,009	12,882	78,632	169,741
Colombia	COP	2.97%	7,075	156,036	163,111	51,808	48,058	38,699	246,968	117,657	503,190
Brazil	US$	2.02%	41,603	77,727	119,330	246,664	304,125	206,988	84,277	168,004	1,010,058
Brazil	BRL	8.61%	96,750	106,540	203,290	80,745	163,539	63,860	61,281	477,728	847,153
Brazil	EUR	2.28%	550	9,009	9,559	13,817	13,539	11,035	8,607	49,641	96,639
Total			149,887	607,029	756,916	444,564	639,029	333,591	414,015	891,662	2,722,861

			Current			Non-Current
			Maturity		Total Current 12-31-2020	Maturity					Total Non-Current 12-31-2020
		Nominal Interest	One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
Country	Currency	Rate	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	0.94%	175,940	150,366	326,306	—	—	—	—	—	—
Peru	PEN	2.71%	1,102	171,132	172,234	48,505	39,557	—	—	—	88,062
Peru	US$	2.59%	151	25,050	25,201	—	—	—	—	—	—
Colombia	COP	3.62%	2,746	125,276	128,022	15,435	23,344	21,204	10,775	334	71,092
Brazil	US$	2.91%	294,873	107,696	402,569	49,366	127	2,819	—	—	52,312
Brazil	BRL	3.80%	10,496	112,467	122,963	143,573	18,697	11,953	10,476	22,414	207,113
Total			485,308	691,987	1,177,295	256,879	81,725	35,976	21,251	22,748	418,579

F-115

- Summary of secured and unsecured bonds by currency and maturity

				Current			Non-Current
				Maturity		Total Current 12-31-2021	Maturity					Total Non-Current 12-31-2021
		Nominal Interest		One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
Country	Currency	Rate	c	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	5.30%		51	3,361	3,412	—	—	—	—	—	—
Chile	UF	5.75%		6,265	18,794	25,059	25,059	25,059	25,059	621,750	—	696,927
Peru	US$	6.34%		158	474	632	632	632	632	632	10,684	13,212
Peru	PEN	6.02%		4,666	41,905	46,571	55,837	52,073	46,951	34,166	185,393	374,420
Colombia	COP	8.24%		85,917	199,861	285,778	239,807	211,135	217,630	16,894	278,596	964,062
Brazil	BRL	11.57%		61,728	264,363	326,091	306,033	275,037	172,368	227,997	377,920	1,359,355
Total				158,785	528,758	687,543	627,368	563,936	462,640	901,439	852,593	3,407,976

			Current			Non-Current
			Maturity		Total Current 12-31-2020	Maturity					Total Non-Current 12-31-2020
		Nominal Interest	One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
Country	Currency	Rate	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	5.30%	6,248	18,743	24,991	24,991	24,991	24,991	24,991	621,693	721,657
Chile	UF	5.75%	172	7,482	7,654	3,807	—	—	—	—	3,807
Peru	US$	6.34%	157	471	628	628	628	628	628	11,309	13,821
Peru	PEN	6.24%	5,292	42,218	47,510	50,087	60,314	56,162	50,510	209,399	426,472
Colombia	COP	5.74%	236,187	138,040	374,227	321,820	270,759	238,759	247,208	332,765	1,411,311
Brazil	BRL	5.94%	17,348	236,255	253,603	278,779	393,232	312,535	106,090	261,456	1,352,092
Total			265,404	443,209	708,613	680,112	749,924	633,075	429,427	1,436,622	3,929,160

- Summary of lease obligations by currency and maturity

			Current			Non-Current
			Maturity			Maturity
Country	Currency	Nominal Interest Rate	One to three months	Three to twelve months	Total Current 12-31-2021	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current 12-31-2021
			ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Argentina	US$	0.25%	1,435	4,483	5,918	8,235	4,741	4,787	7,394	11,881	37,038
Colombia	COP	0.16%	13	19	32	-	-	-	-	-	-
Brazil	BRL	9.01%	5,842	16,657	22,499	12,406	2,203	2,182	2,243	1,915	20,949
Total			7,290	21,159	28,449	20,641	6,944	6,969	9,637	13,796	57,987
			Current			Non-Current
			Maturity			Maturity
Country	Currency	Nominal Interest Rate	One to three months	Three to twelve months	Total Current 12-31-2020	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current 12-31-2020
			ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Argentina	US$	0.25%	1,946	4,296	6,242	3,781	4,374	7,494	7,494	18,590	41,733
Colombia	COP	0.32%	94	-	94	-	-	-	-	-	-
Brazil	BRL	7.19%	58,113	34,017	92,130	56,158	44,720	37,124	11,104	4,796	153,902
Total			60,153	38,313	98,466	59,939	49,094	44,618	18,598	23,386	195,635

●

F-116

20. LEASE LIABILITIES

As of December 31, 2021, and 2020, the balance of lease liabilities is as follows:

	12-31-2021		12-31-2020
	Current	Non-Current	Current	Non-Current
	ThUS$	ThUS$	ThUS$	ThUS$
Lease liability	60,687	187,891	51,495	91,070
Total	60,687	187,891	51,495	91,070

F-117

20.1 Individualization of Lease Liabilities

Individualized lease liabilities are detailed as follows:

									December 31, 2021
									Current			Non-Current
Taxpayer			Taxpayer				Nominal Interest	Maturity	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current
ID No.	Company	Country	ID No.	Company	Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Codensa	Colombia	Foreign	C.I. ALLIANCE S.A.	Colombia	COP	7.50%	Monthly	83	164	247	233	251	270	290	3,813	4,857
Foreign	Codensa	Colombia	Foreign	TERRAPUERTO SAS	Colombia	COP	7.50%	Monthly	60	107	167	167	179	193	207	2,722	3,468
Foreign	Codensa	Colombia	Foreign	COMPAÑIA GENERAL	Colombia	COP	7.50%	Monthly	50	98	148	140	150	161	173	2,325	2,949
Foreign	Codensa	Colombia	Foreign	TRANSPORTES ESPECIALES ALIADOS	Colombia	COP	4.14%	Monthly	504	1,490	1,994	2,056	351	—	—	—	2,407
Foreign	Codensa	Colombia	Foreign	Various creditors	Colombia	COP	8.16%	Monthly	320	404	724	382	213	92	88	1,116	1,891
Foreign	Enel Distribución Peru S.A.	Peru	Foreign	BANCO INTERBANK DEL PERU	Peru	PEN	5.89%	Quarterly	680	1,982	2,662	96	—	—	—	—	96
Foreign	Enel Distribución Peru S.A.	Peru	Foreign	BBVA Banco Continental	Peru	PEN	2.99%	Quarterly	2,823	8,505	11,328	1,715	—	—	—	—	1,715
Foreign	Enel Distribución Peru S.A.	Peru	Foreign	CORP MG	Peru	US$	2.27%	Monthly	300	939	1,239	1,308	1,380	1,455	1,532	7,441	13,116
Foreign	Enel Distribución Peru S.A.	Peru	Foreign	BuildingInmuebles Panamericana S.A.	Peru	PEN	5.19%	Monthly	56	172	228	240	253	87	—	—	580
Foreign	Enel Distribución Peru S.A.	Peru	Foreign	MAREAUTO PERU S.A	Peru	PEN	7.77%	Monthly	86	266	352	377	233	—	—	—	610
Foreign	Enel Distribución Peru S.A.	Peru	Foreign	Various creditors	Peru	US$	2.61%	Monthly	79	235	314	264	217	131	56	—	668
Foreign	Enel Generación Piura S.A.	Peru	Foreign	SCOTIABANK PERU	Peru	US$	3.70%	Quarterly	2,399	—	2,399	—	—	—	—	—	—
Foreign	Enel Generación Piura S.A.	Peru	Foreign	BBVA CONTINENTAL	Peru	US$	2.84%	Quarterly	1,910	3,858	5,768	—	—	—	—	—	—
Foreign	Enel Generación Piura S.A.	Peru	Foreign	Various creditors	Peru	PEN	7.37%	Monthly	2	6	8	8	5	—	—	—	13
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BANCOLOMBIA	Colombia	COP	7.89%	Monthly	2,231	1,861	4,092	1,573	1,573	1,573	1,573	9,443	15,735
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Various creditors	Colombia	COP	8.52%	Monthly	171	186	357	121	40	4	—	—	165
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	CASTELLO BRANCO OFFICE PARK - FUNDO DE INVESTIMENTO IMOBILIÁRIO (50%) / CSHG REAL ESTATE - FUNDO DE INVESTIMENTO IMOBILIÁRIO (50%)	Brazil	BRL	14.20%	Monthly	16	47	63	1,111	1,268	1,449	1,654	148	5,630
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	JSL	Brazil	BRL	9.45%	Monthly	576	1,675	2,251	2,417	2,645	2,895	2,975	16	10,948
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	VAMOS	Peru	BRL	7.28%	Monthly	202	629	831	290	—	—	—	—	290
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	BR PROPERTIES S/A	Peru	BRL	8.97%	Monthly	—	178	178	2,138	2,138	2,138	2,138	12,826	21,378
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	LM TRANSPORTES INTERESTADUAIS SERVICOS E COMERCIO S A	Peru	BRL	8.97%	Monthly	715	1,606	2,321	819	85	—	—	—	904
Foreign	Enel Distribución Sao Paulo	Brazil	Foreign	Various creditors	Brazil	BRL	8.34%	Monthly	1,724	1,666	3,390	1,515	332	231	22	—	2,100
Foreign	EGP Cachoeira Dourada S.A.	Brazil	Foreign	Various creditors	Brazil	BRL	12.42%	Monthly	21	44	65	39	—	—	—	—	39
Foreign	Enel Generación Peru S.A.	Peru	Foreign	BBVA	Peru	PEN	1.59%	Quarterly	715	1,637	2,352	—	—	—	—	—	—
Foreign	Enel Generación Peru S.A.	Peru	Foreign	CORP MG	Peru	US$	2.23%	Monthly	142	444	586	618	652	687	724	3,515	6,196
Foreign	Enel Generación Peru S.A.	Peru	Foreign	Various creditors	Peru	PEN	7.26%	Monthly	6	17	23	24	15	—	—	—	39
Foreign	Enel Generación Peru S.A.	Peru	Foreign	Various creditors	Peru	US$	2.82%	Monthly	15	43	58	41	41	14	—	—	96
Foreign	ENEL X Brazil	Brazil	Foreign	Various creditors	Brazil	BRL	9.01%	Monthly	123	185	308	179	100	4	4	469	756
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	LM TRANSPORTES INTERESTADUAIS SERVICOS E COMERCIO S A	Brazil	BRL	11.61%	Monthly	494	1,526	2,020	780	82	—	—	—	862
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Various creditors	Brazil	BRL	7.14%	Monthly	306	223	529	222	16	13	12	22	285
Foreign	Enel Cien S.A.	Brazil	Foreign	Various creditors	Brazil	BRL	9.33%	Monthly	32	27	59	19	12	—	—	—	31
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	FUNDO DE INVESTIMENTO IMOBILIÁRIO PATRIMONIAL III	Brazil	BRL	8.54%	Monthly	1,731	—	1,731	725	787	857	953	—	3,322
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	LM TRANSPORTES INTERESTADUAIS SERVICOS E COMERCIO S A	Brazil	BRL	11.61%	Monthly	226	696	922	399	97	—	—	—	496
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	Various creditors	Brazil	BRL	8.86%	Monthly	365	277	642	69	68	72	79	51	339
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	ITA EMPRESA DE TRANSPORTES LTDA FROTA NOVA	Brazil	BRL	11.49%	Monthly	529	1,554	2,083	2,203	992	—	—	—	3,195
Foreign	Enel Distribución Goias S.A.	Brazil	Foreign	Various creditors	Brazil	BRL	8.75%	Monthly	345	72	417	54	40	3	—	—	97
Foreign	Enel Generación Fortaleza	Brazil	Foreign	Various creditors	Brazil	BRL	11.73%	Monthly	16	29	45	6	—	—	—	—	6
Foreign	EDESUR	Argentina	Foreign	Various creditors	Argentina	ARS	0.62%	Monthly	—	14	14	24	—	—	—	—	24
Foreign	Enel Green Power Volta Grande	Brazil	Foreign	Various creditors	Brazil	BRL	9.39%	Monthly	10	29	39	40	—	—	—	—	40
Foreign	USME ZE S.A.S	Colombia	Foreign	TRAMI INVERSIONES S.A.S.	Colombia	COP	8.58%	Monthly	732	—	732	—	—	—	—	4,349	4,349
Foreign	FONTIBON ZE S.A.S	Colombia	Foreign	Trami Inversiones S.A.S.	Colombia	COP	8.58%	Monthly	260	—	260	—	—	—	—	7,333	7,333
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	Various creditors	Colombia	COP	9.25%	Monthly	3	8	11	14	11	—	—	—	25
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	Various creditors	Colombia	COP	13.41%	Quarterly	4	—	4	—	1	1	1	113	116
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	Various creditors	Colombia	COP	11.98%	Annual	138	6	144	9	4	6	6	3,026	3,051
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	Carlos Enrique Giovanetti	Colombia	COP	15.28%	Annual	122	5	127	5	7	7	8	1,635	1,662
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	Inversiones Macondal	Colombia	COP	11.27%	Annual	41	—	41	—	—	—	—	1,226	1,226
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	Luz Charris de Manjares - Sucesion	Colombia	COP	11.31%	Annual	85	—	85	—	—	—	—	1,655	1,655
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	FBM  SAS	Colombia	COP	11.31%	Annual	64	—	64	—	—	—	—	1,159	1,159
Foreign	EGP Colombia SAS ESP	Colombia	Foreign	Rolando Manjarres Charris	Colombia	COP	11.23%	Annual	46	—	46	—	—	—	—	1,531	1,531
Foreign	Enel Fortuna S.A.	Panama	Foreign	Inversiones Hayat	Panama	US$	4.95%	Monthly	60	180	240	192	192	192	192	1,153	1,921
Foreign	Enel Fortuna S.A.	Panama	Foreign	Various creditors	Panama	US$	4.04%	Monthly	12	36	48	—	—	—	—	—	—
Foreign	EGP Guatemala S.A.	Guatemala	Foreign	Various creditors	Guatemala	US$	7.20%	Monthly	—	—	—	96	157	—	—	—	253
Foreign	Enel Solar SRL	Panama	Foreign	Various creditors	Panama	US$	8.89%	Monthly	32	99	131	85	85	85	85	1,132	1,472
Foreign	Generadora de Occidente Ltda.	Guatemala	Foreign	Various creditors	Guatemala	US$	7.20%	Annual	10	—	10	—	—	—	—	561	561
Foreign	Generadora de Occidente Ltda.	Guatemala	Foreign	Agricola Mamusa S.A.	Guatemala	US$	7.20%	Monthly	43	—	43	—	—	—	—	2,495	2,495
Foreign	Generadora Montecristo S.A.	Guatemala	Foreign	Various creditors	Guatemala	US$	9.68%	Monthly	22	—	22	—	—	—	—	628	628
Foreign	Generadora Montecristo S.A.	Guatemala	Foreign	Agroindustria California, S.A. (Pedro Rojas)	Guatemala	US$	9.68%	Monthly	31	—	31	—	—	—	—	878	878
Foreign	Generadora Montecristo S.A.	Guatemala	Foreign	Agropecuaria San Antonio Quenené	Guatemala	US$	9.68%	Annual	29	—	29	—	—	—	—	835	835
Foreign	EGP Peru S.A.	Peru	Foreign	Various creditors	Peru	PEN	9.14%	Monthly	11	35	46	50	31	—	—	—	81
Foreign	EGP Peru S.A.	Peru	Foreign	Various creditors	Peru	US$	10.10%	Monthly	1	3	4	—	—	—	—	—	—
Foreign	Progreso Solar S.A.	Panama	Foreign	VALENTIN LEZCANO CASTILLO	Panama	US$	6.33%	Monthly	49	9	58	30	30	30	30	712	832
Foreign	Generadora Solar Austral	Panama	Foreign	Ganadera Paldiva	Panama	US$	6.75%	Monthly	49	—	49	29	29	29	29	734	850
Foreign	Jaguito Solar 10MW, S.A.	Panama	Foreign	Various creditors	Panama	US$	6.75%	Monthly	14	—	14	14	14	14	14	339	395
Foreign	Grupo EGP Brazil	Brazil	Foreign	TS-19 PARTICIPAÇÕES LTDA	Brazil	BRL	15.92%	Monthly	119	469	588	746	874	1,024	1,199	4,634	8,477
Foreign	Grupo EGP Brazil	Brazil	Foreign	CAMPO ALEGRE EMPREENDIMENTOS RURAIS LTDA.	Brazil	BRL	11.66%	Monthly	81	9	90	12	13	15	12	1,988	2,040
Foreign	Grupo EGP Brazil	Brazil	Foreign	CALCARIO IMAP AGRO MINERAÇÃO LTDA.	Brazil	BRL	13.18%	Monthly	21	7	28	9	10	12	13	1,224	1,268
Foreign	Grupo EGP Brazil	Brazil	Foreign	ESPÓLIO DE CIRILO BENVINDO DE SOUZA	Brazil	BRL	14.49%	Monthly	58	2	60	3	4	4	5	1,315	1,331
Foreign	Grupo EGP Brazil	Brazil	Foreign	MAGALHÃES E ELOY GESTÃO DE RECEBÍVE	Brazil	BRL	13.25%	Monthly	32	11	43	16	19	21	24	1,281	1,361
Foreign	Grupo EGP Brazil	Brazil	Foreign	JOÃO CARLOS RATAJCZYK	Brazil	BRL	12.48%	Monthly	461	54	515	46	55	64	73	363	601
Foreign	Grupo EGP Brazil	Brazil	Foreign	Various creditors	Brazil	BRL	12.47%	Monthly	3,577	593	4,170	683	764	654	651	31,410	34,162
Total									26,270	34,417	60,687	24,451	16,515	14,487	14,822	117,616	187,891

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20.1 Individualization of Lease Liabilities, continued

										December 31, 2020
										Current			Non-Current
Taxpayer			Taxpayer					Nominal Interest		Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current
ID No.	Company	Country	ID No.		Company	Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
foreign	Codensa	Colombia	foreign		C.I. ALLIANCE S.A.	Colombia	COP	7.50%	Monthly	95	224	319	254	273	294	316	4,802	5,939
foreign	Codensa	Colombia	foreign		TERRAPUERTO SAS	Colombia	COP	7.50%	Monthly	67	113	180	178	192	206	221	3,368	4,165
foreign	Codensa	Colombia	foreign		COMPAÑIA GENERAL DE	Colombia	COP	7.50%	Monthly	57	107	164	152	163	176	189	2,904	3,584
foreign	Codensa	Colombia	foreign		Various creditors	Colombia	COP	8.08%	Monthly	975	1,362	2,337	201	154	102	33	942	1,432
foreign	Enel Distribución Peru S.A.	Peru	foreign		BANCO INTERBANK DEL PERU	Peru	PEN	5.89%	Quarterly	716	2,161	2,877	2,931	106	—	—	—	3,037
foreign	Enel Distribución Peru S.A.	Peru	foreign		BANCO CONTINENTAL	Peru	PEN	2.99%	Quarterly	1,758	5,423	7,181	7,756	1,988	—	—	—	9,744
foreign	Enel Distribución Peru S.A.	Peru	foreign		CORP MG	Peru	US$	2.27%	Monthly	1	766	767	1,697	1,697	1,697	1,697	7,778	14,566
foreign	Enel Distribución Peru S.A.	Peru	foreign		Various creditors	Peru	PEN	4.92%	Monthly	65	164	229	229	240	253	87	—	809
foreign	Enel Distribución Peru S.A.	Peru	foreign	���	Various creditors	Peru	US$	3.94%	Monthly	48	177	225	200	93	46	—	—	339
foreign	Enel Generación Piura S.A.	Peru	foreign		SCOTIABANK PERU	Peru	US$	3.70%	Quarterly	2,418	7,268	9,686	2,397	—	—	—	—	2,397
foreign	Enel Generación Piura S.A.	Peru	foreign		Various creditors	Peru	US$	3.23%	Quarterly	627	2,060	2,687	1,463	—	—	—	—	1,463
foreign	Enel Generación Piura S.A.	Peru	foreign		Various creditors	Peru	PEN	7.57%	Monthly	8	11	19	—	—	—	—	—	—
foreign	Emgesa S.A. E.S.P.	Colombia	foreign		Various creditors	Colombia	COP	7.87%	Monthly	528	1,263	1,791	364	122	28	—	—	514
foreign	Enel Distribución Sao Paulo	Brazil	foreign		CASTELLO BRANCO OFFICE PARK - FUNDO DE INVESTIMENTO IMOBILIÁRIO (50%) / CSHG REAL ESTATE - FUNDO DE INVESTIMENTO IMOBILIÁRIO (50%)	Brazil	BRL	10.55%	Monthly	622	1,040	1,662	1,515	1,674	1,851	2,046	2,461	9,547
foreign	Enel Distribución Sao Paulo	Brazil	foreign		JSL	Brazil	BRL	9.45%	Monthly	1,228	1,641	2,869	2,368	2,592	2,836	3,104	3,207	14,107
foreign	Enel Distribución Sao Paulo	Brazil	foreign		Various creditors	Brazil	BRL	6.96%	Monthly	2,886	3,370	6,256	3,582	1,858	310	214	20	5,984
foreign	EGP Cachoeira Dourada S.A.	Brazil	foreign		Various creditors	Brazil	BRL	12.42%	Monthly	12	36	48	31	—	—	—	—	31
foreign	Enel Generación Peru S.A.	Peru	foreign		BBVA	Peru	US$	2.81%	Quarterly	2,233	4,529	6,762	—	—	—	—	—	—
foreign	Enel Generación Peru S.A.	Peru	foreign		RENTAEQUIPOS LEASING PERU S.A.	Peru	US$	3.37%	Monthly	7	383	390	828	802	802	802	3,674	6,908
foreign	Enel Generación Peru S.A.	Peru	foreign		Various creditors	Peru	PEN	1.59%	Quarterly	—	45	45	181	45	—	—	—	226
foreign	Enel Generación Peru S.A.	Peru	foreign		Various creditors	Peru	US$	4.12%	Monthly	3	3	6	—	—	—	—	—	—
foreign	Enel Generación Peru S.A.	Peru	foreign		Various creditors	Peru	US$	2.23%	Quarterly	6	14	20	—	—	—	—	—	—
foreign	Enel Generación Peru S.A.	Peru	foreign		Various creditors	Peru	PEN	5.45%	Monthly	2	3	5	—	—	—	—	—	—
foreign	ENEL Brazil S.A.	Brazil	foreign		Various creditors	Brazil	BRL	10.93%	Monthly	9	27	36	22	—	—	—	—	22
foreign	ENEL X Brazil	Brazil	foreign		Various creditors	Brazil	EUR	9.31%	Monthly	15	2	17	3	4	4	4	371	386
foreign	ENEL X Brazil	Brazil	foreign		Various creditors	Brazil	BRL	9.02%	Monthly	63	51	114	41	3	—	—	146	190
foreign	Enel Distribución Ceará S.A.	Brazil	foreign		Various creditors	Brazil	BRL	7.05%	Monthly	315	251	566	154	32	18	14	36	254
foreign	Enel Cien S.A.	Brazil	foreign		Various creditors	Brazil	BRL	7.86%	Monthly	27	13	40	11	—	—	—	—	11
foreign	Enel Distribución Río S.A.	Brazil	foreign		FUNDO DE INVESTIMENTO IMOBILIÁRIO PATRIMONIAL III	Brazil	BRL	8.54%	Monthly	1,851	—	1,851	717	778	844	919	1,023	4,281
foreign	Enel Distribución Río S.A.	Brazil	foreign		Various creditors	Brazil	BRL	8.75%	Monthly	416	626	1,042	501	74	73	77	137	862
foreign	Enel Distribución Goias S.A.	Brazil	foreign		Various creditors	Brazil	BRL	7.93%	Monthly	879	278	1,157	106	44	33	3	—	186
foreign	Enel Generación Fortaleza	Brazil	foreign		Various creditors	Brazil	BRL	12.42%	Monthly	11	34	45	29	—	—	—	—	29
foreign	EDESUR	Argentina	foreign		Various creditors	Argentina	ARS	0.62%	Monthly	—	78	78	45	—	—	—	—	45
foreign	Enel Green Power Volta Grande	Brazil	foreign		Various creditors	Brazil	BRL	7.09%	Monthly	2	3	5	11	1	—	—	—	12
94.271.000-3	Enel Américas S.A.	Chile	96.565.580-8		Various creditors	Chile	UF	0.01%	Monthly	11	8	19	—	—	—	—	—	—
Total										17,961	33,534	51,495	27,967	12,935	9,573	9,726	30,869	91,070

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20.2 Undiscounted debt cash flows

Undiscounted debt cash flows are detailed as follows:

			Current			Non-Current
			Maturity			Maturity
Country	Currency	Nominal Interest Rate	One to three months	Three to twelve months	Total Current 12-31-2021	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current 12-31-2021
			ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Argentina	ARS	0.62%	2	6	8	22	11	-	-	-	33
Peru	US$	3.38%	5,608	7,608	13,216	2,715	2,719	2,659	2,625	11,581	22,299
Peru	PEN	5.25%	3,824	11,237	15,061	2,603	556	88	-	-	3,247
Colombia	COP	8.47%	5,627	7,949	13,576	10,888	8,466	7,589	7,254	59,773	93,970
Brazil	BRL	11.84%	11,414	22,589	34,003	22,917	17,467	15,434	14,662	150,720	221,200
Panama	US$	7.78%	80	764	844	674	658	638	618	8,806	11,394
Guatemala	US$	8.26%	120	362	482	1,710	925	877	827	4,578	8,917
Total			26,675	50,515	77,190	41,529	30,802	27,285	25,986	235,458	361,060
			Current			Non-Current
			Maturity			Maturity
Country	Currency	Nominal Interest Rate	One to three months	Three to twelve months	Total Current 12-31-2020	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current 12-31-2020
			ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Argentina	ARS	0.62%	25	75	100	22	29	14	-	-	65
Peru	US$	3.29%	7,031	13,852	20,883	6,804	2,634	2,541	2,494	11,431	25,904
Peru	PEN	4.69%	2,787	8,399	11,186	11,328	2,383	264	88	-	14,063
Colombia	COP	8.00%	1,836	3,984	5,820	2,644	2,254	2,016	1,836	14,460	23,210
Brazil	BRL	7.75%	7,332	15,333	22,665	14,310	11,040	8,874	8,194	7,278	49,696
Brazil	BRL	9.31%	29	86	115	56	56	56	56	1,794	2,018
Chile	UF	0.01%	10	10	20	-	-	-	-	-	-
Total			19,050	41,739	60,789	35,164	18,396	13,765	12,668	34,963	114,956

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21. RISK MANAGEMENT POLICY

The Group companies follow the guidelines of the Risk Management Control System (SCGR) defined at the Holding level (Enel S.p.A.), which establishes rules for managing risks through the respective standards, procedures, systems, etc., applicable to the different levels of the Group companies in the ongoing business risk identification, analysis, evaluation, treatment, and communication processes. These are approved by the Enel S.p.A. Board of Directors, which includes a Risk and Controls Committee responsible for supporting the Enel Américas Board’s evaluation and decisions regarding internal control and risk management system, as well as those related to the approval of periodic financial statements.

To comply with this, each Company has its own specific Control Management and Risk Management policy, which is reviewed and approved at the beginning of each year by the Enel Américas Board of Directors, observing and applying all local requirements in terms of the risk culture.

The Company seeks protection against all risks that could affect the achievement of the business objectives. In January 2020, a new risk taxonomy has been approved for the Enel Group, which considers 6 macro-categories and 37 sub-categories.

The Enel Group risk management system considers three lines of action (defense) to obtain effective and efficient risk management and controls. Each of these three “lines” plays a different role within the organization’s broader governance structure (Business and Internal Control areas acting as the first line, Risk Control as the second line, and Internal Audit as the third line of defense). Each line of defense has the obligation to report to and keep senior management and the Directors up-to-date on risk management. In this sense, the first and second lines of defense report to the senior management, and the second and third lines report to the Enel Américas Board of Directors.

Within each of the Group’s companies, the risk management is decentralized. Each manager responsible for the operating process in which the risk arises is also responsible for treating the risk and adopting risk control and mitigating measures.

21.1 Interest rate risk

Changes in interest rates affect the fair value of assets and liabilities bearing fixed interest rates, as well as the expected future cash flows of assets and liabilities subject to floating interest rates.

The objective of managing interest rate risk exposure is to achieve a balance in the debt structure to minimize the cost of debt with reduced volatility in profit or loss.

Depending on the Group’s estimates and the objectives of the debt structure, hedging transactions are performed by entering into derivatives contracts that mitigate interest rate risk. Derivative instruments currently used to comply with the risk management policy are interest rate swaps to set floating rate to a fixed rate.

The Group’s financial debt structure per fixed and/or hedged interest rate on gross debt, net of hedging derivative instruments engaged, is as follows:

Gross position:

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	12-31-2021	12-31-2020
	%	%
Fixed interest rate	31%	38%

Risk control through specific processes and indicators allows companies to limit possible adverse financial impacts and at the same time, optimize the debt structure with an adequate degree of flexibility. In this sense, the volatility that characterized the financial markets during the first phase of the pandemic, in many cases went back to pre-COVID-19 levels and was offset by effective risk mitigation actions using derivative financial instruments.

21.2 Exchange rate risk

Exchange rate risks involve basically the following transactions:

- Debt taken on by the Group’s companies that is denominated in a currency other than the currency in which its cash flows are indexed.

- Payments to be made in a currency other than that in which its cash flows are indexed for the acquisition of project-related materials and for corporate insurance policies.

- Income in Group companies directly linked to changes in currencies other than the currency of its cash flows.

- Cash flows from foreign subsidiaries to the Chilean Parent Company which are exposed to exchange rate fluctuations.

In order to mitigate foreign currency risk, the Group’s foreign currency risk management policy is based on cash flows and includes maintaining a balance between U.S. dollar flows and the levels of assets and liabilities denominated in such currency. The objective is to minimize the exposure to variability in cash flows that are attributable to foreign exchange risk.

The hedging instruments currently being used to comply with the policy are currency swaps and forward exchange contracts. In addition, the policy works to refinance debt in the functional currency of each of the Group’s companies.

During the fourth quarter of 2021, exchange rate risk management continued in the context of complying with the aforementioned risk management policy, without difficulty to access the derivatives market. It should be noted that the volatility that characterized the financial markets during the first phase of the pandemic, in many cases went back to pre-COVID-19 levels and was offset by risk mitigation actions through derivative financial instruments.

21.3 Commodities risk

The Group has a risk exposure to price fluctuations in certain commodities, basically due to:

- Purchases of fuel used to generate electricity.

- Energy purchase/sale transactions that take place in local markets.

In order to reduce the risk in situations of extreme drought, the Group has designed a commercial policy that defines the levels of sales commitments in line with the capacity of its generating power plants in a dry year. It also includes risk mitigation terms in certain contracts with unregulated customers and with regulated customers subject to long-term tender processes, establishing indexation polynomials that allow for reducing commodities exposure risk.

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Considering the operating conditions faced by the power generation market, with drought and highly volatile commodity prices on international markets, the Company is constantly evaluating the use of hedging to minimize the impacts that these price fluctuations have on its results.

As of December 31, 2021, there are no current transactions for the purpose of hedging the contracting portfolio.

As of December 31, 2020, there are no current transactions for the purpose of hedging the contracting portfolio.

Thanks to the mitigation strategies implemented, the Group was able to minimize the effects of basic product price volatility on the results for the fourth quarter of 2021.

21.4  Liquidity risk

The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets.

Despite the negative working capital existing at the end of 2021, the Company has the capacity to overcome this situation and mitigate the risk through its liquidity risk policy and actions described herein.

The projected needs mentioned above include maturities of financial debt net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial derivatives (see Notes 19 and 22).

As of December 31, 2021, the Enel Américas Group has liquidity in the amount of ThUS$ 1,396,253 in cash and other equivalents and ThUS$ 1,119,278 in unconditionally available long-term credit facilities. As of December 31, 2020, the Enel Américas Group has liquidity in the amount of ThUS$ 1,506,993 in cash and other equivalents.

21.5  Credit risk

The Group closely monitors its credit risk.

Trade receivables:

The credit risk for receivables from the Group’s commercial activity has historically been very low, due to the short-term period of collections from customers, resulting in non-significant cumulative receivables amounts. This situation applies to the electricity generating and distribution lines of business.

In our electricity generating business, some countries’ regulations allow suspending the energy service to customers with outstanding payments, and most contracts have termination clauses for payment default. The Company monitors its credit risk on an ongoing basis and measures quantitatively its maximum exposure to payment default risk, which, as stated above, is very low.

Regarding our electricity distribution companies, the companies always have the right to cut off supply to customers for non-compliance. This is performed in accordance with local regulations by each country, which facilitates the process of evaluation and monitoring of credit risk, which is low. However, the supply cutoff due to lack of payment by vulnerable customers was suspended during the COVID-19 pandemic in all the countries where Enel Américas operates. In Argentina, in accordance with to Decree 311/2020 of March 24, 2020, supply cuts are still suspended. In

F-123

Brazil, cuts have resumed by the 4 distribution companies, including in Rio de Janeiro, where supply cuts were resumed on July 1, 2021 (when Law No. 8,769/20 expired). However, in accordance with Resolutions No. 878 dated March 24, 2020, and ANEEL No. 928 dated March 26, 2020, electricity cuts to low-income customers were prohibited until December 31, 2021. In Colombia, cutoffs to low-income customers were prohibited in accordance with Decrees Nos. 417 and 457, dated March 17, 2020. In Peru, this was also the case, in accordance with Decree 35/20 dated April 3, 2020. Through the present date, in both countries, supply cutoffs for non-compliance by customers have resumed as usual.

Regarding the impact of COVID-19, the results of specific internal analysis did not reveal significant statistical correlations between the main economic indicators (GDP, unemployment rate, etc.) and solvency.

Financial assets:

Cash surpluses are invested in the highest-rated local and foreign financial entities (with risk rating equivalent to investment grade where possible) with thresholds established for each entity.

Banks that have received investment grade ratings from the three major international rating agencies (Moody’s, S&P, and Fitch) are selected for making investments.

Investments may be backed with treasury bonds from the countries in which the company operates and/or with commercial papers issued by the highest rated banks; the latter are preferable as they offer higher returns (always in line with current investment policies).

It is noted that the downturn in the macroeconomic scenario due to COVID-19 had no significant impact on the counterparties’ credit quality.

21.6 Risk measurement

The Group measures the Value at Risk (VaR) of its debt positions and financial derivatives in order to monitor the risk assumed by the Company, thereby reducing volatility in the statement of income.

The portfolio of positions included for purposes of calculating the present Value at Risk include:

- Financial debt.

- Hedging derivatives for debt.

The VaR determined represents the potential variation in value of the portfolio of positions described above in a quarter with a 95% confidence level. To determine the VaR, we take into account the volatility of the risk variables affecting the value of the portfolio of positions, including:

- U.S. dollar LIBOR interest rate.

- The different currencies with which our companies operate and the customary local indices used in the banking industry.

- The exchange rates of the various currencies used in the calculation.

The calculation of VaR is based on generating possible future scenarios (one quarter) of market values for the risk variables based on scenarios based on actual observations for the same period (one quarter) during five years.

The quarter 95% confidence VaR number is calculated as the 5% percentile most adverse of the quarterly possible fluctuations.

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Taking into consideration the assumptions previously described, the quarter VaR of the previously discussed positions was ThUS$ 559,901.

This value represents the potential increase of the Debt and Derivatives’ Portfolio, thus these VaR are inherently related, among other factors, to the Portfolio’s value at each quarter end.

22. FINANCIAL INSTRUMENTS

22.1 Financial instruments, classified by type and category

a) The detail of financial assets, classified by type and category, as of December 31, 2021 and 2020, is as follows:

	December 31, 2021
	Financial assets at fair value through profit or loss	Financial assets measured at amortized cost	Financial assets at fair value through other comprehensive income	Hedging financial derivatives
	ThUS$	ThUS$	ThUS$	ThUS$
Trade and other accounts receivable	—	3,784,900	—	—
Derivative instruments	2,483	—	—	30,206
Other financial assets	156,174	123,167	—	—
Total Current	158,657	3,908,067	—	30,206
Equity instruments	—	—	2,155	—
Trade and other accounts receivable	—	724,877	—	—
Derivative instruments	48,426	—	—	123,479
Other financial assets	3,004,421	294,695	—	—
Total Non-Current	3,052,847	1,019,572	2,155	123,479
Total	3,211,504	4,927,639	2,155	153,685

	December 31, 2020
	Financial assets at fair value through profit or loss	Financial assets measured at amortized cost	Financial assets at fair value through other comprehensive income	Hedging financial derivatives
	ThUS$	ThUS$	ThUS$	ThUS$
Trade and other accounts receivable	—	3,281,885	—	—
Derivative instruments	37,420	—	—	49,045
Other financial assets	119,704	24,110	—	—
Total Current	157,124	3,305,995	—	49,045
Equity instruments	—	—	268	—
Trade and other accounts receivable	—	578,556	—	—
Derivative instruments	148	—	—	29,487
Other financial assets	2,493,609	267,351	—	—
Total Non-Current	2,493,757	845,907	268	29,487
Total	2,650,881	4,151,902	268	78,532

F-125

b) The detail of financial liabilities, classified by type and category, as of December 31, 2021 and 2020, is as follows:

	December 31, 2021
	Financial liabilities at fair value through profit or loss	Financial liabilities measured at amortized cost	Hedging financial derivatives
	ThUS$	ThUS$	ThUS$
Interest-bearing loans	—	1,181,392	—
Trade and other accounts payable	—	5,806,997	—
Derivative instruments	4,457	—	44,788
Other financial liabilities	2,197	60,687	—
Total Current	6,654	7,049,076	44,788
Interest-bearing loans	—	4,905,270	—
Trade and other accounts payable	—	3,836,795	—
Derivative instruments	5,015	—	7,298
Other financial liabilities	—	187,891	—
Total Non-Current	5,015	8,929,956	7,298
Total	11,669	15,979,032	52,086

	December 31, 2020
	Financial liabilities at fair value through profit or loss	Financial liabilities measured at amortized cost	Hedging financial derivatives
	ThUS$	ThUS$	ThUS$
Interest-bearing loans	—	1,815,160	—
Trade and other accounts payable	—	4,649,782	—
Derivative instruments	6,202	—	528
Other financial liabilities	3,240	51,495	—
Total Current	9,442	6,516,437	528
Interest-bearing loans	—	3,837,697	—
Trade and other accounts payable	—	2,205,194	—
Derivative instruments	—	—	9
Other financial liabilities	—	91,070	—
Total Non-Current	—	6,133,961	9
Total	9,442	12,650,398	537

22.2 Derivative instruments

The risk management policy of the Group uses primarily interest rate and foreign exchange rate derivatives to hedge its exposure to interest rate and foreign currency risks.

The Company classifies its hedges as follows:

> Cash flow hedges: Those that hedge the cash flows of the underlying hedged item.

> Fair value hedges: Those that hedge the fair value of the underlying hedged item.

> Non-hedge derivatives: Financial derivatives that do not meet the requirements established by IFRS to be designated as hedging instruments are recognized at fair value through profit or loss (financial assets held for trading).

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a) Assets and liabilities for hedge derivative instruments

As of December 31, 2021 and 2020, financial derivative operations, which qualify as hedging instruments, involved recognizing assets and liabilities in the statement of financial position according to the following detail:

	December 31, 2021				December 31, 2020
	Asset		Liability		Asset		Liability
	Current	Non-Current	Current	Non-Current	Current	Non-Current	Current	Non-Current
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Interest rate hedge:	18	18,866	5,369	4,473	306	18,416	—	—
Cash flow hedge	18	4,671	5,369	—	—	—	—	—
Fair value hedge	—	14,195	—	4,473	306	18,416	—	—
Exchange rate hedge:	32,671	153,039	43,876	7,840	86,159	11,219	6,730	9
Cash flow hedge	32,671	119,354	43,876	7,314	51,661	11,219	6,716	9
Fair value hedge	—	33,685	—	526	34,498	—	14	—
TOTAL	32,689	171,905	49,245	12,313	86,465	29,635	6,730	9

- General Information Related to Hedging Derivative Instruments

Hedging derivative instruments and their corresponding hedged instruments are shown in the following table:

Type of hedge instrument	Description of hedged risk	Description of hedged item	Fair value of hedged item 12-31-2021	Fair value of hedged item 12-31-2020
			ThUS$	ThUS$
SWAP	Interest rate	Bank loans	15,450	53,221
SWAP	Interest rate	Unsecured obligations (bonds)	—	—
SWAP	Exchange rate	Unsecured obligations (bonds)	(2,463)	3,682
SWAP	Exchange rate	Bank loans	118,202	56,494
SWAP	Exchange rate	Dividends receivable	—	—
FORWARD	Exchange rate	Operational Income	1,470	(2,725)
FORWARD	Exchange rate	Bank loans	(2,832)	(802)
FORWARD	Exchange rate	Unsecured obligations (bonds)	12,118	(509)
FORWARD	Exchange rate	Factoring	8	—
FORWARD	Exchange rate	Investments in Property, Plant and Equipment	1,083	—

As of December 31, 2021 and 2020, the Group has not recognized significant gains or losses for ineffective cash flow hedges.

For fair value hedges, the gain or losses on the hedging derivative instrument and on the underlying hedged item recognized for the years ended December 31, 2021, 2020 and 2019, is detailed in the following table:

	December 31, 2021		December 31, 2020		December 31, 2019
	Gains	Losses	Gains	Losses	Gains	Losses
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Hedging derivative instrument	43,715	—	26,570	—	1,618	—
Underlying hedged item	—	400	—	316	381	—
TOTAL	43,715	400	26,570	316	1,999	—

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b)Financial derivative instruments assets and liabilities at fair value through profit or loss

As of December 31, 2021 and 2020, financial derivative transactions recognized at fair value through profit or loss, resulted in the recognition of the following assets and liabilities in the statement of financial position:

	December 31, 2021				December 31, 2020
	Assets		Liabilities		Assets		Liabilities
	Current	Non-Current	Current	Non-Current	Current	Non-Current	Current	Non-Current
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Non-hedging derivative instrument (1)	3	—	2,197	—	1,321	—	3,240	—

(1) Correspond to forward contracts entered into by the Group mainly to hedge foreign exchange risk related to dividends received or to be received from its foreign subsidiaries. Although, the hedge relationship has economic substance, they do not comply with all the hedging documentation requirements set forth by IFRS 9 Financial Instruments to qualify for hedge accounting.

c) Other information on derivatives:

The following table sets forth the fair value of hedging and non-hedging derivatives entered into by the Group as well as the remaining contractual maturities as of December 31, 2021 and 2020:

	December 31, 2021
		Notional amount
	Fair value	Less than 1 year	1 - 2 years	2 - 3 years	3 - 4 years	More than five years	Subsequent	Total
Financial Derivatives	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Interest rate hedge:	9,042	8,000	8,000	59,967	8,000	251,830	177,021	512,818
Cash flow hedge	(680)	8,000	8,000	59,967	8,000	251,830	177,021	512,818
Fair value hedge	9,722	—	—	—	—	—	—	—
Exchange rate hedge:	133,994	1,060,472	331,249	669,209	187,668	73,595	125,454	2,447,647
Cash flow hedge	100,835	1,060,472	319,504	661,977	181,795	69,081	100,629	2,393,458
Fair value hedge	33,159	—	11,745	7,232	5,873	4,514	24,825	54,189
Derivatives not designated for hedge accounting	(2,194)	289,404	—	—	—	—	—	289,404
TOTAL	140,842	1,357,876	339,249	729,176	195,668	325,425	302,475	3,249,869

	December 31, 2020
		Notional Amount
	Fair value	Less than 1 year	1 - 2 years	2 - 3 years	3 - 4 years	More than five years	Subsequent	Total
Financial Derivatives	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Interest rate hedge:	18,722	—	—	—	—	—	153,944	153,944
Cash flow hedge		—	—	—	—	—	153,944	153,944
Fair value hedge	18,722	—	—	—	—	—	—	—
Exchange rate hedge:	90,639	833,438	87,972	76,972	—	—	—	998,382
Cash flow hedge	56,155	771,860	87,972	76,972	—	—	—	936,804
Fair value hedge	34,484	61,578	—	—	—	—	—	61,578
Derivatives not designated for hedge accounting	(1,919)	50,601	—	—	—	—	—	50,601
TOTAL	107,442	884,039	87,972	76,972	—	—	153,944	1,202,927

The contractual maturities of hedging and non-hedging derivatives do not represent the Group’s total risk exposure, as the amounts presented in the above tables have been drawn upon based on undiscounted contractual cash inflows and outflows for their settlement.

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22.3 Fair value hierarchies

Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the hierarchies described in Note 3.h.

The following table presents financial assets and liabilities measured at fair value as of December 31, 2021 and 2020:

Financial Instruments Measured at Fair Value		Fair Value Measured at End of Reporting Period Using:
	12-31-2021	Level 1	Level 2	Level 3
	ThUS$	ThUS$	ThUS$	ThUS$
Financial Assets :
Financial derivatives designated as cash flow hedge	156,712	—	156,712	—
Financial derivatives designated as fair value hedge	47,882	—	47,882	—
Financial derivatives not designated for hedge accounting	3	—	3	—
Financial assets at fair value through other comprehensive income	2,155	—	2,155	—
Financial assets at fair value through profit or loss	3,160,593	182,365	2,978,228	—
Total	3,367,345	182,365	3,184,980	—
Financial Liabilities:
Financial derivatives designated as cash flow hedge	56,559	—	56,559	—
Financial derivatives designated as fair value hedge	4,999	—	4,999	—
Financial derivatives not designated for hedge accounting	2,197	—	2,197	—
Total	63,755	—	63,755	—

Financial Instruments Measured at Fair Value		Fair Value Measured at End of Reporting Period Using:
	12-31-2020	Level 1	Level 2	Level 3
	ThUS$	ThUS$	ThUS$	ThUS$
Financial Assets :
Financial derivatives designated as cash flow hedge	62,878	—	62,878	—
Financial derivatives designated as fair value hedge	53,222	—	53,222	—
Financial derivatives not designated for hedge accounting	1,321	—	1,321	—
Financial assets at fair value through other comprehensive income	268	—	268	—
Financial assets at fair value through profit or loss	2,611,992	143,843	2,468,149	—
Total	2,729,681	143,843	2,585,838	—
Financial Liabilities:
Financial derivatives designated as cash flow hedge	6,725	—	6,725	—
Financial derivatives designated as fair value hedge	14	—	14	—
Financial derivatives not designated for hedge accounting	3,240	—	3,240	—
Total	9,979	—	9,979	—

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23. CURRENT AND NON-CURRENT PAYABLES

The detail of Trade and Other Current Payables as of December 31, 2021 and 2020 is as follows:

	Current		Non-Current
	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Trade and Other Payables	ThUS$	ThUS$	ThUS$	ThUS$
Trade payables
Energy suppliers	1,175,753	1,323,617	77,349	100,517
Fuel and gas suppliers	9,619	24,621	—	—
Payables for goods and services	1,484,387	1,071,248	20,921	3,155
Payables for assets acquisitions	147,574	49,332	—	10,990
Subtotal	2,817,333	2,468,818	98,270	114,662
Other payables
Dividends payable to third parties	43,302	145,875	—	—
Payables to CAMMESA (1)	626,696	337,317	14,996	27,475
Penalties and complaints (2)	23,109	18,817	37,638	56,013
Research and development obligations	112,083	154,595	31,411	40,925
Taxes payables other than income tax	60,840	40,916	210	672
Accounts payables to employees	150,627	154,269	874	1,136
PIS/COFINS on VAT (payable to consumers) (3)	411,066	211,611	2,252,434	1,474,165
Regulatory Liabilities Brazilian Subsidiaries (4)	399,238	418,680	170,147	186,946
Agreement Enel Distribución Sao Paulo with Eletrobras (5)	67,351	68,501	65,310	134,925
Other payables	200,485	74,177	17,777	24,556
Subtotal	2,094,797	1,624,758	2,590,797	1,946,813
Total	4,912,130	4,093,576	2,689,067	2,061,475

Note 21.4 for the description of the liquidity risk management policy.

(1) As of December 31, 2021 our subsidiary Edesur includes ThUS$ 614,171 of accounts payable for purchases of electricity from CAMMESA (ThUS$ 320,918 as of December 31, 2020). Additionally, a total of ThUS$ 27,521 (ThUS$ 43,874 as of December 31, 2020) is included for mutual contracts and assignment of collateral credits signed with CAMMESA for (i) financing of operational needs that cannot be postponed for the operation and of the generating plant in our subsidiary Enel Generación Costanera; (ii) financing the maintenance needs of the turbo generators at our subsidiary Dock Sud; and (iii) the financing of the extraordinary investment plan in our subsidiary Edesur.

(2) Correspond mainly to fines and complaints for the current and previous years, that our subsidiary Edesur S.A. has received from the regulating entity due to commercial service quality, quality of the technical product and public road safety. These fines have not been paid, since some are suspended by the Agreement Declaration signed in 2007 with the Argentine government. The value of these fines is updated in line with the changes in Distribution Added Value due to the tariff adjustments. As of December 31, 2021, ThUS$ 31,328 (ThUS$ 38,007 as of December 31, 2020) is included as a result of the application of ENRE Resolution No. 1/2016.

(3) See Note 8, discussing the recoverable PIS/COFINS Taxes.

(4) See Note 8(ii).

(5) This corresponds to an agreement between Enel Distribución Sao Paulo and Eletrobrás ending a lawsuit between both parties dating from 1986. This agreement will be paid over a five-year period ending in June 2023.

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The detail of trade payables, both up to date and past due as of December 31, 2021 and 2020 are presented in Appendix 4.

24. PROVISIONS

a) The detail of provisions as of December 31, 2021 and 2020, is as follows:

	Current		Non-Current
	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Provisions	ThUS$	ThUS$	ThUS$	ThUS$
Provisions for legal proceedings (*)	132,850	192,411	698,346	748,640
Decommissioning or restoration (**)	18,736	22,635	95,300	69,959
Provision for environmental issues	720	600	440	7,072
Other provisions (***)	12,538	4,779	44,733	8,229
Total	164,844	220,425	838,819	833,900

(*) The main contingencies are disclosed in Note 34.3.

(**) As of December 31, the decommissioning provisions arise mainly from the effects of the Colombian subsidiary Emgesa, for the electrical appliances of the Quimbo plant with a dismantling date of 2066, and other effects from companies of renewable energy from Brazil.

(***) The increase noted in 2021 is mainly due to the recognition of provisions of US$12,901 associated with a restructuring plan in our subsidiaries in Brazil and Colombia, in accordance with the Group’s digitization strategy. These provisions were recognized under the item “Other employee expenses” (see Note 29).

The expected timing and amount of any cash outflows related to the above provisions is uncertain and depends on the final resolution of the related matters

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b) Movements in provisions as of December 31, 2021 and 2020, are as follows:

	Legal Proceedings	Decommissioning or Restoration	Environmental Issues and Other Provisions	Total
Provisions	ThUS$	ThUS$	ThUS$	ThUS$
Movements in Provisions
Balance as of January 1, 2021	941,051	92,594	20,680	1,054,325
Increase (decrease) in existing provisions	100,104	22,773	38,913	161,790
Acquisition through business combinations	437	24,966	4,747	30,150
Provision used	(141,022)	(11,771)	—	(152,793)
Increase from adjustment to time value of money	83,700	(179)	119	83,640
Foreign currency translation	(84,135)	(14,347)	(6,028)	(104,510)
Transfer to P&L	(68,939)	—	—	(68,939)
Total Movements in Provisions	(109,855)	21,442	37,751	(50,662)
Balance as of December 31, 2021	831,196	114,036	58,431	1,003,663
	Legal Proceedings	Decommissioning or Restoration	Environmental Issues and Other Provisions	Total
Provisions	ThUS$	ThUS$	ThUS$	ThUS$
Movements in Provisions
Balance as of January 1, 2020	1,122,551	129,309	10,519	1,262,379
Increase (decrease) in existing provisions	199,922	(26,906)	8,860	181,876
Provision used	(120,184)	(6,654)	(748)	(127,586)
Increase from adjustment to time value of money	84,576	3,514	1,623	89,713
Foreign currency translation	(243,627)	(6,529)	441	(249,715)
Transfer to P&L	(102,187)	(140)	(15)	(102,342)
Total Movements in Provisions	(181,500)	(36,715)	10,161	(208,054)
Balance as of December 31, 2020	941,051	92,594	20,680	1,054,325

25. POST-EMPLOYMENT BENEFIT OBLIGATIONS

25.1 General information

The Company and certain of its subsidiaries in Brazil, Colombia, Peru and Argentina granted various post-employment benefits for all or certain of their active or retired employees. These benefits are calculated and recognized in the financial statements according to the policy described in Note 3.m.1, and include primarily the following:

a) Defined benefit plans:

● Complementary pension: The beneficiary is entitled to receive a monthly amount that supplements the pension obtained from the respective social security system.

● Health Plan: Pursuant to collective bargaining agreements, the companies provide a health plan to their employees. This benefit is granted to employees in the Brazilian (Enel Distribución Goiás, Enel Distribución Rio and Enel Distribución Ceará) and Colombian (Emgesa and Codensa) companies.

b) Other benefits

Five-year benefit: A benefit certain employees receive after 5 years and which begins to accrue from the second year onwards. This benefit is provided to Emgesa and Codensa employees.

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Employee severance indemnities: The beneficiary receives a certain number of contractual salaries upon retirement. Such benefit is subject to a vesting minimum service requirement period of 5 years. This benefit is provided to Enel Américas employees.

Unemployment: A benefit paid regardless of whether the employee is fired or leaves voluntarily. This benefit is accrued on a daily basis and is paid at the time of contract termination (although the law allows for partial withdrawals for housing and education). This benefit is provided to Emgesa and Codensa employees.

Seniority bonuses in Peru: There is an agreement to give employees (“subject to the collective bargaining agreement”) an extraordinary bonus for years of service upon completion of the equivalent of five years of actual work based on the following:

Years of Service	Benefit
For completing 5, 10 and 15 years	1 basic monthly remuneration
For completing 20 years	1 ½ basic monthly remuneration
For completing 25, 30, 35 & 40 years	2 ½ basic monthly remunerations

Education and Energy Plans: According to the collective bargaining Agreement, the Colombian companies Emgesa and Codensa grant education and electricity discount rates to their employees.

c) Defined contribution benefits:

The Group makes contributions to a retirement benefit plan where the beneficiary receives additional pension supplements upon his/her retirement, disability or death.

25.2 Details, changes and presentation in financial statements

a) The post-employment obligations associated with defined benefits plans and the related plan assets as of December 31, 2021 and 2020:

General ledger accounts:

	Balance as of
	12-31-2021	12-31-2020
	ThUS$	ThUS$
Post-employment obligations	3,357,838	3,706,545
(-) Plan assets (*)	(1,962,668)	(2,097,081)
Total	1,395,170	1,609,464
Amount not recognized due to limit on Plan Assets Ceiling (**)	23,804	14,753
Minimum funding required (IFRIC 14) (***)	4,507	—
Total Post-Employment Obligations, Net (i)	1,423,481	1,624,217

Reconciliation with general ledger accounts:

	Balance as of
	12-31-2021	12-31-2020
	ThUS$	ThUS$
Pension plans	1,323,388	1,489,472
Health plans	73,080	106,242
Other plans	27,013	28,503
Total Post-Employment Obligations, Net	1,423,481	1,624,217

(*)   Plan assets to fund defined benefit plans only in our Brazilian subsidiaries (Enel Distribución Rio S.A., Enel Distribución Ceará S.A., Enel Distribución Sao Paulo S.A. and Enel Distribución Goiás).

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(**) In Enel Distribución Ceará S.A., certain pension plans currently have an actuarial surplus amounting to ThUS$ 23,804 as of December 31, 2021 (ThUS$ 14,753 as of December 31, 2020), which actuarial surplus was not recognized as an asset in accordance with IFRIC 14 - The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction, because the Complementary Social Security (SPC) regulations - CGPC Resolution No. 26/2008 states that the surplus can only be used by the sponsor if the contingency reserve on the balance sheet of Faelce (an institution providing pension funds exclusively to employees and retired employees of Enel Distribución Ceará S.A.) is at the maximum percentage (25% of reserves). This ensures the financial stability of the plan based on the volatility of these obligations. If the surplus exceeds this limit, it may be used by the sponsor to reduce future contributions or be reimbursed to the sponsor.

(***) In Enel Distribución Rio S.A., an additional liability has been recognized in accordance with the provisions of IFRIC 14 - The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction as of December 31, 2021 in the amount of ThUS$ 4,507. This corresponds to actuarial debt contracts that the company signed with Brasiletros (an institution providing pension funds exclusively to employees and retired employees of Enel Distribución Rio S.A.). This was done to equalize deficits on certain pension plans, since the sponsor assumes responsibility for these plans, in accordance with current legislation.

b) The following amounts were recognized in the consolidated statement of comprehensive income for the years ended December 31, 2021, 2020 and 2019:

	12-31-2021	12-31-2020	12-31-2019
Expense Recognized in the Statement of Comprehensive Income	ThUS$	ThUS$	ThUS$
Current service cost for defined benefits plan	383	6,278	11,255
Interest cost for defined benefits plan	248,864	276,103	357,751
Interest income from the plan assets	(139,319)	(174,136)	(251,095)
Past Service Costs	—	(18,949)	(8,643)
Defined benefit plan obligation reductions	—	(69,859)	—
Interest cost on asset ceiling components	1,032	2,936	2,016
Total expenses recognized in Profit or Loss	110,960	22,373	111,284
(Gains) losses from remeasurement of defined benefit plans	(9,312)	476,805	576,143
Total expense recognized in Comprehensive Income	101,648	499,178	687,427

The gain from specific benefit plans is mainly due to an adjustment of the discount rate that the Group applied at the end of the fourth quarter of 2021. This change in actuarial assumptions (of more than 100 basis points in Brazil and Colombia) arose from changes in the macroeconomic and financial environment due to the COVID-19 pandemic (see Notes 2.3 and 34.5)

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c) The rollforward of net actuarial liabilities as of December 31, 2021 and 2020, are as follows:

Net Actuarial Liability	ThUS$
Opening balance as of 01-01-2020	1,836,362
Net interest cost	104,903
Service cost	6,278
Benefits paid	(10,602)
Contributions paid	(133,195)
Actuarial (gains) losses from changes in financial assumptions	33,096
Actuarial (gains) losses from changes in experience adjustments	568,564
Return on plan assets, excluding interest	(97,592)
Changes in the asset limit	(26,886)
Minimum finding required (IFRIC 14)	(377)
Past service credit defined benefit plan obligations (*)	(18,949)
Transfer of employees	226
Foreign currency translation differences	(390,993)
Transfer to financial debt (*)	(176,759)
Defined benefit plan obligation reductions (*)	(69,859)
Closing balance as of 12-31-2020	1,624,217
Net interest cost	110,577
Service cost	383
Benefits paid	(5,412)
Contributions paid	(174,315)
Actuarial (gains) losses from changes in financial assumptions	(709,016)
Actuarial (gains) losses from changes in experience adjustments	678,492
Return on plan assets, excluding interest	7,213
Changes in the asset limit	9,344
Minimum finding required (IFRIC 14)	4,655
Defined benefit plan obligations from business combinations	1,237
Transfer of employees	1,439
Foreign currency translation differences	(119,699)
Transfer to financial debt (*)	(5,634)
Closing balance as of 12-31-2021	1,423,481

(*) Voluntary Pension migration to the new defined contribution plan.

On April 13, 2020, our subsidiary Enel Distribución Sao Paulo approved the regulatory reform to the complementary retirement and pensions plan (hereinafter “PSAP”), which was effective from May 1, 2020, for the purpose of closing access to new plan participants. Additionally, and together with the National Superintendence of Complementary Pensions (“PREVIC”), it approved of a voluntary migration process to a new Defined Contribution Plan (hereinafter, “CD II plan”), exclusively for the employees belonging to the PSAP. The migration consisted of the transfer of participants from a defined benefit plan (PSAP) to a defined contribution plan (CD II plan), which also generates a programmed withdrawal option (as opposed to life annuities as in the PSAP). This voluntary migration process ended on December 31, 2020.

At the end of the process, 21.4% of the PSAP plan participants agreed to voluntarily transfer their savings to the CD II plan.

This migration generated a reduction in the net actuarial liability in the amount of ThUS$ 271,358, which is explained as follows:

• ThUS$ 182,393 (ThUS$ 176,759 registered in December 2020 and ThUS$ 5,634 in December 2021) corresponding to the portion of the obligation that was transferred to the CD II plan, in the same ratio as the mathematical reserves of the participants who opted for migration. This transfer was instrumentalized through a new debt contract of an exclusively financial nature and was reclassified to Other financial liabilities (current and non-current).

• ThUS$ 88,965 corresponding to (i) the net effect of the liquidation produced as a result of the migration, in the amount of ThUS$ 69,859; and (ii) ThUS$ 19,106 related to past service costs. With the partial migration, all future legal or constructive obligations, in relation to all or part of the benefits offered by the defined benefits

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plan, in proportion to the migrated participants. This effect was recognized as lower personnel expenses in the consolidated statement of income.

The Company will analyze the next steps in the restructuring plan with the final results of the plan, to be authorized by the competent regulatory authority.

d) The balance and movements in post-employment defined benefit obligations as of December 31, 2021 and 2020 are as follows:

Actuarial Value of Post-employment Obligations	ThUS$
Opening balance as of 01-01-2020	4,876,960
Current service cost	6,278
Interest cost	276,103
Contributions from plan participants	778
Foreign currency translation	(1,075,063)
Contributions paid	(294,910)
Past service credit defined benefit plan obligations	(18,949)
Transfer of employees	226
Actuarial (gains) losses from changes in financial assumptions	33,096
Actuarial (gains) losses from changes in experience adjustments	568,564
Defined benefit plan obligation reductions	(666,538)
Closing balance as of 12-31-2020	3,706,545
Current service cost	383
Interest cost	248,864
Contributions from plan participants	271
Foreign currency translation	(259,935)
Contributions paid	(310,442)
Past service credit defined benefit plan obligations	1,237
Defined benefit plan obligations from business combinations	1,439
Transfer of employees	(709,016)
Actuarial (gains) losses from changes in financial assumptions (*)	678,492
Closing balance as of 12-31-2021	3,357,838

As of December 31, 2021, the total amount of the actuarial liability corresponds to 0.07% with defined benefit plans in the Chilean companies (0.08% as of December 31, 2020), 96.67% is from defined benefit plans in Brazilian companies (96.02% as of December 31, 2020), 2.61% with defined benefit plans in Colombian companies (3.35% as of December 31, 2020), in a 0.51% with defined benefit plans in Argentine companies (0.38% as of December 31, 2020), 0.13% with defined benefit plans in Peruvian companies (0.17% as of December 31, 2020), and the remaining 0.01% with defined benefit plans in EGP Panama companies.

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Movements in the fair value of the benefit plan assets are as follows:

Fair Value of Plan Assets	ThUS$
Balance as of January 1, 2020	(3,090,862)
Interest income	(174,136)
Return on plan assets, excluding interest	(97,592)
Foreign currency translation differences	695,254
Employer contributions	(133,195)
Benefit paid	(778)
Contributions paid	284,308
Transfer to financial Debt	(176,759)
Defined benefit plan obligations reductions	596,679
Balance as of December 31, 2020	(2,097,081)
Interest income	(139,319)
Return on plan assets, excluding interest	7,213
Foreign currency translation differences	141,709
Employer contributions	(174,315)
Benefits paid	(271)
Contributions paid	305,030
Transfer to Financial Debt	(5,634)
Balance as of December 31, 2021	(1,962,668)

e) The main categories of benefit plan assets are as follows:

	12-31-2021		12-31-2020
Category of Plan Assets	ThUS$	%	ThUS$	%
Equity instruments (variable income)	217,259	14.50%	206,176	9.83%
Fixed-income assets	1,441,373	74.22%	1,774,894	84.64%
Real estate investments	67,610	3.48%	62,392	2.98%
Other	236,426	7.80%	53,619	2.56%
Total	1,962,668	100%	2,097,081	100%

The plans for retirement benefits and pension funds held by our Brazilian subsidiaries, Enel Distribución Rio S.A., Enel Distribución Ceará, Enel Distribución Goias and Enel Distribución Sao Paulo, maintain investments as determined by the resolutions of the National Monetary Council, ranked in fixed income, equities and real estate. Fixed income investments are predominantly invested in federal securities. Regarding equities, i) Faelce (an institution providing pension funds exclusively to employees and retired employees of Enel Distribución Ceará) holds common shares of Enel Distribución Ceará, ii) Brasiletros (a similar institution for employees of Enel Distribución Rio), Eletra (an institution pension fund exclusively for employees and retired staff of Enel Distribución Goias) and Funcesp, (the private pension entity responsible for the administration of the benefit plans sponsored by Enel Distribución Sao Paulo) hold shares in investment funds with a portfolio traded on Bovespa (the São Paulo Stock Exchange). Finally, with regard to real estate, the foundations Faelce and Brasiletros have properties that are currently leased to Enel Distribución Rio and Enel Distribución Ceará, while in Eletra the real estate investments are exclusively for the own use of the foundation.

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The following table sets forth the assets affected by the plans and invested in shares, leases and real estate owned by the Group.

	12-31-2021	12-31-2020
	ThUS$	ThUS$
Real Estate	20,564	20,522
Total	20,564	20,522

f) Reconciliation of asset ceiling:

Reconciliation of Asset Ceiling	ThUS$
Balance as of January 1, 2020	49,780
Interest on assets not recognized	2,936
Other changes in assets not recognized due to asset limit	(26,886)
Foreign currency translation differences	(11,077)
Balance as of December 31, 2020	14,753
Interest on assets not recognized	1,032
Other changes in assets not recognized due to asset limit	9,344
Foreign currency translation differences	(1,325)
Total asset ceiling as of December 31, 2021	23,804

25.3 Other disclosures:

● Actuarial assumptions:

As of December 31, 2021 and 2020, the following assumptions were used in the actuarial calculation of defined benefit plans:

	Chile		Brazil		Colombia		Argentina		Peru
	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
Discount rates used	5.60%	2.55%	9.30% - 9.67%	4.88% - 7.95%	6.94%	5.74%	50.68% - 51.23%	49.36% - 54.46%	5.90%	3.50%
Expected rate of salary increases	3.80%	3.80%	4.52% - 5.04%	4.52% - 5.04%	4.95%	4.85%	43.5% - 56.22%	37.68% - 42.25%	4.00%	4.00%
Mortality tables	CB-H-2014 and RV-M-2014	CB-H-2014 and RV-M-2014	AT 2000	AT 2000	RV 2008	RV 2008	CB-H-2014 and RV-M-2014	CB-H-2014 and RV-M-2014	SPP-S-2017	SPP-S-2017
Turnover rate	7.03%	7.25%	6.50%	5.19%	0.29%	0.46%	1.11%	1.26%	5.39%	5.20%

● Sensitivity:

As of December 31, 2021, the sensitivity of the value of the actuarial liability for post-employment benefits to variations of 100 basis points in the discount rate assumes a decrease of ThUS$ 263,184 (ThUS$ 319,395 as of December 31, 2020) in the event of an increase in the rate and an increase of ThUS$ 287,916 (ThUS$ 379,682 as of December 31, 2020) in the event of a rate drop.

● Defined contribution:

Contributions made to defined contribution plans are recorded directly under “personnel expenses” in the consolidated income statement. The amounts recorded for this concept as of December 31, 2021, 2020 and 2019 were ThUS$ 10,619, ThUS$ 10,689, and ThUS$ 13,419, respectively.

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● Future disbursements:

According to the available estimate, the disbursements foreseen (net of assets) to cover the defined benefits plans for next year amount to ThUS$ 168,397.

● Length of commitments:

The Group’s obligations have a weighted average length of 8-10 years, and the outflows of benefits for the next 10 years and more is expected to be as follows:

Years	ThUS$
1	312,277
2	301,047
3	295,841
4	288,736
5	284,030
Over 5 to 10	1,317,844

● Multi-employer plans of Enel Distribución Sao Paulo:

FUNCESP is the entity in charge of the benefit plans sponsored by Enel Distribución Sao Paulo. Through negotiations with representative trade unions, the Company reformulated the plan in 1997, considering as its main characteristic a mixed model made up by 70% of the actual wage contributed as defined benefit and 30% of the actual wage contributed as established contribution. The purpose of this reformulation was to consider the actuarial technical deficit and to reduce the risk of future deficits.

The cost of the defined benefit plan is parity between Enel Distribución Sao Paulo and the employees, according to the proportions mentioned above. Cost rates vary from 1.45% to 4.22%, depending on the salary range, and are reassessed annually by an independent actuary. The cost of the defined contribution is based on the percentage freely chosen by the participant (from 1% to 100% over 30% of the real contribution salary), with a contribution from Enel Distribución Sao Paulo up to the limit of 5% on the basis 30% of the remuneration of the contribution. (The contributions paid by Enel Distribución Sao Paulo were ThUS$ 137,917 and ThUS$ 113,203 for the years ended December 31, 2021 and 2020, respectively).

The Settled Proportional Supplementary Benefit (BSPS) guarantees the plan participating employees that adhered to the model implemented in the Company’s privatization. This benefit will ensure the proportional value corresponding to the previous service period to the adherence date to the new mixed plan. This benefit will be paid from the date in which the participant completes the minimum times required under the regulation of the new plan.

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26. EQUITY

26.1 Equity attributable to the shareholders of Enel Américas

26.1.1 Subscribed and paid capital and number of shares

The issued capital of the Company for the year ended December 31, 2021 is ThUS$ 15,799,499 divided into 107,281,698,561 authorized, subscribed and paid shares. The issued capital as of December 31, 2020 was ThUS$ 9,763,078 divided into 76,086,311,036 authorized, subscribed and paid shares. All of the shares issued by the Company are subscribed and paid, and they are listed for trade on the Bolsa de Comercio de Santiago de Chile, the Bolsa Electrónica de Chile, and the New York Stock Exchange (NYSE).

Treasury shares in portfolio

As of December 31, 2021, the value of treasury shares (1,809,031 shares) amounts to ThUS$272. These shares were acquired as a result of the merger detailed in Note 5.

Changes in Issued Capital

-Capital Increase in 2019

At an Extraordinary Shareholders’ Meeting of Company held on April 30, 2019, shareholders approved a capital increase for an amount of ThUS$ 3,000,000 by issuing 18,729,788,686 common shares, no-par value, of the same series. The purpose of this capital increase was to enable the Company’s subsidiary Enel Brasil to repay a loan provided by Enel Finance International N.V., which replaced bank debt incurred by Enel Brasil for the acquisition of the Brazilian company Eletropaulo Metropolitana Eletricidade de Sao Paulo S.A. (currently Enel Distribución Sao Paulo), and to restructure the liabilities of the Enel Distribución Sao Paulo’s pension funds.

All new common shares were offered preferably to shareholders on a pro rata basis based on the shares they own as of record in the Enel Américas shareholders registry, over 2 subscription periods. On June 26, 2019, the Company’s Board of Directors agreed that the subscription price of the 18,729,788,686 new shares, both in the first and second preemptive right subscription periods, would be US$ 0.162108214203236 per share.

During the first preemptive rights offering period held between June 27 and July 26, 2019, a total of 18,224,843,129 shares were subscribed and paid, representing 97.3% of the total of the new shares authorized for issuance under the capital increase mentioned above, for a total amount of ThUS$ 2,954,397.

During the subsequent rights offering period held between August 6 and August 29, 2019, a total of 408,826,391 shares were subscribed and paid, representing 80.96% of the total shares not subscribed in the first preemptive rights offer period and offered in the subsequent period, for a total amount of ThUS$ 66,274.

On September 12, 2019, the Company’s Board of Directors agreed not to place the remaining 96,119,166 shares and charged them to the capital increase which approximately amounted to 0.51% of the total shares which were pending subscription and payment after the end of the subsequent rights offering period. Therefore, and in accordance with the agreement of the Board, once the one-year period beginning April 30, 2019 has elapsed, the Company’s capital will be fully reduced to the amount actually paid at the expiration of the offerings indicated above.

As a result, during the capital increase process, a total of 18,633,669,520 shares were subscribed and paid for a total amount of ThUS$ 3,020,671.

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-Corporate integration operation of non-conventional, renewable energy generating companies in Central and South America (except for Chile)

At the extraordinary shareholders’ meeting held on December 18, 2020, the Company approved the following:

(i)The subtraction from the capital raised in the share issuance the placement expenses in the amount of ThUS$ 20,797 (see Note 26.5.c.8), related to the capital increase process performed in 2019; and

(ii)The proposed merger by incorporation of EGP Américas SpA (“EGP Américas”) into Enel Américas (the “Merger”). By virtue of this Merger, Enel Américas would acquire all of EGP Américas’ assets and liabilities and succeed into all of EGP Américas’ rights and obligations, allowing the Company to control and consolidate the ownership of the business and the non-conventional renewable energy generation assets developed and held by Enel Green Power S.p.A. in Central and South America (except Chile).

In order to complete the Merger, the Board approved a capital increase for Enel Américas in the amount of ThUS$ 6,036,421, through the issuance of 31,195,387,525 new common shares of a single series as existing shares and with no par value. These shares were subscribed and fully paid for in exchange for the incorporation of the EGP Américas equity, as an absorbed company, once the Merger becomes effective. For such purpose, 0.41 Enel Américas shares were delivered for each share in EGP Américas held by EGP Américas’ single shareholder, not considering fractions of shares.

The Merger was effective on April 1, 2021, after all the suspensive and connected conditions precedent agreed upon by the Shareholders’ Meeting were fulfilled (see Note 5).

Movements in the number of shares of Enel Américas resulting from the corporate reorganization process described above are detailed as follows:

Number of outstanding shares of the Company prior the Merger			76,086,311,036
	Number of shares	Merger Exchange Ratio	Number of shares
Merger with EGP Américas (1)
Shares issued to Enel SpA	76,086,311,039	0.41	31,195,387,525
Repurchase of shares (2):
Exercise of the right to withdraw by minority shareholders of Enel Américas	(1,809,031)		(1,809,031)
Number of Enel Américas shares outstanding after the merger			107,219,889,530
Total number of capital shares issued			107,281,698,561
Total number of treasury shares in portfolio			(1,809,031)
Number of outstanding shares of the Company after the Merger			107,279,889,530

(1) The valuation of the capital increase resulting from the merger was ThUS$6,036,421.

(2) The total amount paid for the repurchase of shares was ThUS$272.

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26.1.2Dividends

The following table sets forth the dividends paid in the last three years:

Dividend No.	Type of Dividend	Agreement Date	Payment Date	Total ThUS$	Dollar per Share	Charged to
98	Interim	11-26-2018	01-25-2019	76,900	0.00134	2018
99	Final	04-30-2019	05-17-2019	403,652	0.00703	2018
100	Interim	11-25-2019	01-24-2020	123,254	0.00162	2019
101	Final	04-30-2020	05-29-2020	683,789	0.00899	2019
102	Interim	11-26-2020	01-29-2021	72,992	0.00096	2020
103	Final	04-29-2021	05-28-2021	339,607	0.00317	2020
104	Interim	11-25-2021	01-28-2022	93,319	0.00087	2021

26.2 Foreign currency translation reserves

The following table sets forth foreign currency translation differences attributable to the shareholders of the Company for the years ended December 31, 2021, 2020 and 2019:

	Balance as of December 31,
Reserves for Accumulated Currency Translation Differences (*)	2021	2020	2019
	ThUS$	ThUS$	ThUS$
Empresa Distribuidora Sur S.A.	(807,898)	(715,165)	(548,877)
Compañía Distribuidora y Comercializadora de Energía S.A.	7,284	87,339	111,815
Enel Distribución Perú S.A.	(71,619)	(7,279)	50,466
Dock Sud S.A.	(140,018)	(122,728)	(93,738)
Enel Brasil S.A.	(3,299,765)	(2,924,373)	(1,430,604)
Enel Generación Costanera S.A.	(149,360)	(124,781)	(88,477)
Emgesa S.A. E.S.P.	(195,058)	(74,309)	(38,296)
Enel Generación El Chocón S.A.	(414,358)	(377,364)	(318,303)
Enel Peru S.A.	200,693	190,007	190,030
Enel Generación Perú S.A.	(241,258)	(168,547)	(94,082)
Enel Generación Piura S.A.	(16,933)	(4,854)	7,583
Enel Green Power Brasil Participacoes Ltda	54,671	—	—
Enel Green Power Colombia	(26,341)	—	—
Other	(90,234)	(66,242)	(30,672)
TOTAL	(5,190,194)	(4,308,296)	(2,283,155)

(*) See Note 2.9

26.3 Capital Management

The Company’s objective is to maintain an adequate level of capitalization in order to be able to secure its access to the financial markets, so as to fulfill its medium- and long-term goals while maximizing the return to its shareholders and maintaining a robust financial position.

26.4 Restrictions on subsidiaries transferring funds to the parent (equity note)

The Company has certain subsidiaries that must comply with certain financial ratios or covenants, which require a minimum level of equity or contain other characteristics that restrict the transfer of assets to the Parent Company. As of December 31, 2021, the company’s participation in the net restricted assets of its subsidiaries Enel Brasil and Enel Perú amount to ThUS$ 287,096, ThUS$ 355,286, respectively.

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26.5 Other reserves

Other reserves for the years ended December 31, 2021, 2020 and 2019, are as follows:

	Balance as of  January 1, 2021	Changes in 2021	Balance as of December 31, 2021
	ThUS$	ThUS$	ThUS$
Foreign currency translation difference (a)	(4,308,296)	(881,898)	(5,190,194)
Cash flow hedges (b)	(9,383)	9,809	426
Financial assets at fair value with changes in other comprehensive income	(692)	(5)	(697)
Other miscellaneous reserves (c)	(2,754,546)	(790,250)	(3,544,796)
TOTAL	(7,072,917)	(1,662,344)	(8,735,261)
	Balance as of January 1, 2020	Changes in 2020	Balance as of December 31, 2020
	ThUS$	ThUS$	ThUS$
Foreign currency translation difference (a)	(2,283,155)	(2,025,141)	(4,308,296)
Cash flow hedges (b)	(1,334)	(8,049)	(9,383)
Financial assets at fair value with changes in other comprehensive income	(687)	(5)	(692)
Other miscellaneous reserves (c)	(3,006,823)	252,277	(2,754,546)
TOTAL	(5,291,999)	(1,780,918)	(7,072,917)
	Balance as of January 1, 2019	Changes in 2019	Balance as of December 31, 2019
	ThUS$	ThUS$	ThUS$
Foreign currency translation difference (a)	(1,666,109)	(617,046)	(2,283,155)
Cash flow hedges (b)	(5,094)	3,760	(1,334)
Financial assets at fair value with changes in other comprehensive income	(397)	(290)	(687)
Other miscellaneous reserves (c)	(3,209,283)	202,460	(3,006,823)
TOTAL	(4,880,883)	(411,116)	(5,291,999)

a) Reserves for foreign currency translation differences: These reserves arise primarily from exchange differences relating to:

- Translation of the financial statements of our subsidiaries with functional currencies other than the U.S. dollar (see Note 2.9); and

- Translation of goodwill arising from the acquisition of companies with functional currencies other than the U.S. dollar (see Note 3.c).

b) Cash flow hedge reserves: These reserves represent the cumulative effective portion of gains and losses on cash flow hedges (see Note 3.g.5).

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c) Other miscellaneous reserves.

- The main items and their effects are the following:

Other Miscellaneous Reserves	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$
Reserve for capital increase in 2013 (1)	(1,345,368)	(1,345,368)	(1,345,368)
Company restructuring reserve (Division) (2)	716,712	716,712	716,712
Reserve for subsidiaries transactions (3)	(456,349)	(456,349)	(456,349)
Reserve for transition to IFRS (4)	(1,490,605)	(1,490,605)	(1,490,605)
Reserve for merger of Endesa Américas and Chilectra Américas with Enel Américas (5)	(730,748)	(730,748)	(730,748)
Reserve for Tender Offer of Endesa Américas and withdrawal rights (6)	(57,101)	(57,101)	(57,101)
Argentine hyperinflation (7)	1,149,319	675,139	446,196
Reserve for capital increase in 2019 (8)	—	—	(20,797)
Other miscellaneous reserves (9)	(13,944)	—	—
Reserve for merger of EGP Américas with Enel Américas (10)	(1,259,422)	—	—
Other miscellaneous reserves (11)	(57,290)	(66,226)	(68,763)
Total	(3,544,796)	(2,754,546)	(3,006,823)

1) Reserve originated from the capital increase that the Company made during the first quarter of 2013.

2) Reserve for corporate reorganization (Spin-Offs of companies) completed on March 1, 2016. Corresponds to the effects from the reorganization of Enersis Américas and the separation of the Chilean business into a new entity, Enel Chile S.A.

3) Reserve from transactions with our subsidiaries. It corresponds to the effect of purchases of equity interests in subsidiaries that were accounted for as transactions between entities under common control.

4) Reserve for transition to IFRS. In accordance with Official Bulletin No. 456 from the SVS (Superintendencia de Valores y Seguros de Chile), included in this line item is the price-level restatement of paid-in capital from the date of transition to IFRS, January 1, 2004 to December 31, 2008.

5) Reserve for merger of Endesa Américas and Chilectra Américas with and into the Company, completed on December 1, 2016. This represents the recognition of the difference between the capital increase in the Company and the carrying amount of the non-controlling interests that became part of the equity attributable to the owners of Enel Américas after completion of the Merger. The difference between the fair market value of the consideration received or paid and the amount by which the non-controlling interests is adjusted is being recognized in equity attributable to the owners of Enel Américas.

6) Reserve for Tender Offer of Endesa Américas and withdrawal rights. This represents the recognition of the difference between the carrying amount and the price paid for the non-controlling interests acquired in the Tender Offer on Endesa Américas, which resulted in a charge to other reserves for ThUS$ 56,578. It also, includes ThUS$ 523 related to the recognition of the difference between the carrying amount and the price paid for the shares of those shareholders who exercised their withdrawal rights.

7) Corresponds to the effect that our subsidiaries in Argentina have recognized through the application of IAS 29 on equity accounts.

8) Reserve for capital increase in 2019: As of December 31, 2019, the Company has recorded a charge of ThUS$ 20,797, which corresponds to expenses for the issuance and placement of shares, determined according to the accounting criteria described in Note 3.t). In December 2020, this reserve was reclassified and the Company’s capital was reduced (see Note 26.1.1).

9) Reserve for capital increase in 2021: During 2021, the Company recognized a debit in the item “Shared capital and paid-in capital” of Equity of ThUS$13,944, from share issuance and placement expenses. This debit was calculated according to the accounting criteria described in Note 3.t). For further information, see Note 26.1.1.

10) Reserve for the merger of EGP Américas with Enel Américas: During 2021, the Company recognized a debit in “Other miscellaneous reserves” (in Consolidated Equity) of ThUS$1,259,422 as a result of the merger of EGP Américas with Enel Américas. This referred to business combinations under common control.

11) Other miscellaneous reserves from transactions made in prior years.

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26.6 Non-controlling Interests

The detail of non-controlling interests as of December 31, 2021, 2020 and 2019, is as follows:

	Non-controlling interests
		Equity		Profit (Loss)
Companies	12-31-2021	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2019
	%	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Enel Distribución Ceará S.A.	25.95%	169,243	170,552	23,672	13,387	26,753
Enel Distribución Sao Paulo	0.00%	—	—	—	—	26,366
Compañía Distribuidora y Comercializadora de Energía S.A.	51.59%	413,048	513,182	135,660	117,923	129,624
Emgesa S.A. E.S.P.	51.52%	648,228	779,121	235,623	178,980	193,449
Enel Distribución Perú S.A.	16.85%	117,080	123,704	14,350	13,131	21,651
Enel Generacion Perú S.A.	16.40%	102,212	133,466	19,949	20,705	20,091
Chinango S.A.C.	33.12%	19,512	20,888	7,368	6,076	6,318
Empresa Distribuidora Sur S.A.	27.91%	194,835	198,054	(51,226)	(20,297)	50,352
Enel Generacion Costanera S.A.	24.38%	39,390	43,751	(14,814)	4,248	14,125
Enel Generacion El Chocón S.A.	34.31%	84,731	97,986	(7,003)	18,141	28,142
Inversora Dock Sud S.A.	42.86%	79,566	71,077	(2,132)	1,130	18,723
Central Dock Sud S.A.	29.76%	72,396	64,709	(1,970)	1,271	18,486
Enel Generacion Piura S.A.	3.50%	3,618	4,905	567	373	778
Enel Fortuna S.A.	49.95%	242,923	—	33,293	—	—
Tecnoguat, S.A.	25.00%	4,276	—	265	—	—
Other		6,378	6,409	50	987	820
TOTAL		2,197,436	2,227,804	393,652	356,055	555,678

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27. REVENUE AND OTHER OPERATING INCOME

The detail of revenue presented in the statement of comprehensive income for the years ended December 31, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
Revenues	2021	2020	2019
	ThUS$	ThUS$	ThUS$
Energy sales (1)	12,807,702	9,655,212	11,282,254
Generation	3,850,268	2,144,039	2,091,002
Regulated customers	763,612	397,653	450,145
Unregulated customers	1,401,833	883,045	1,045,965
Spot market sales	1,678,503	852,363	577,579
Other customers	6,320	10,978	17,313
Distribution	8,957,434	7,511,173	9,191,252
Residential	5,477,397	4,334,457	5,038,300
Business	1,978,044	1,760,922	2,302,100
Industrial	683,424	685,246	872,531
Other customers	818,569	730,548	978,321
Other sales	48,589	36,968	58,752
Gas sales	20,690	24,145	39,815
Other fuel sales	10,647	6,861	9,037
Sales of goods and services	17,252	5,962	9,900
Revenue from other services	1,678,733	1,546,796	1,712,370
Tolls and transmission	1,393,406	1,280,994	1,433,538
Metering equipment leases	116	126	118
Services and Business Advisories provided (Public lighting, connections and electrical advisories)	187,532	177,818	191,392
Other services	97,679	87,858	87,322
Total revenues	14,535,024	11,238,976	13,053,376
	For the years ended December 31,
Other Income	2021	2020	2019
	ThUS$	ThUS$	ThUS$
Revenue from construction contracts	1,203,370	807,671	770,356
Income from Regulatory agreement (2)	—	17,842	261,185
Updating of financial assets related to electricity distribution concessions in Brazil (*)	246,750	99,071	73,345
Other	207,192	128,185	229,195
Total other income	1,657,312	1,052,769	1,334,081

(*)See Note 2.2.c.

(1) As of December 31, 2021, an amount of ThUS$ 958,321 is included within this item, which corresponds to estimated and unbilled sales, which are related to estimates of energy sold in December 2021. As of December 31, 2020 and 2019, these amounts correspond to ThUS$ 1,051,011 and ThUS$ 803,499, respectively.

(2) 2020: see Note 34.6 (ii) Framework Agreement.

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28. RAW MATERIALS AND CONSUMABLES USED

The detail of raw materials and consumables used presented in profit or loss for the years ended December 31, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	2021	2020	2019
Raw Materials and Consumables Used	ThUS$	ThUS$	ThUS$
Energy purchases	(7,711,330)	(5,337,887)	(6,096,863)
Fuel consumption	(116,666)	(137,850)	(277,117)
Gas	(104,941)	(113,992)	(246,044)
Oil	(9,927)	(3,587)	(13,101)
Coal	(1,798)	(20,271)	(17,972)
Transportation costs	(1,020,192)	(1,016,486)	(1,110,921)
Costs from construction contracts	(1,186,239)	(807,671)	(770,356)
Other variable supplies and services	(416,956)	(256,021)	(285,766)
Total Raw Materials and Consumables Used	(10,451,383)	(7,555,915)	(8,541,023)

29. EMPLOYEE BENEFITS EXPENSE

The detail of employee expenses for the years ended December 31, 2021, 2020 and 2019, are as follows:

	For the years ended December 31,
	2021	2020	2019
Employee Benefits Expenses	ThUS$	ThUS$	ThUS$
Wages and salaries	(438,205)	(390,791)	(482,009)
Post-employment benefit expense	(11,002)	71,841	(16,031)
Social security and other contributions	(238,993)	(219,754)	(286,459)
Other employee expenses (*)	(41,702)	(26,342)	(25,254)
Total Employee Benefits Expenses	(729,902)	(565,046)	(809,753)

(*) See Note 24.

30. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES OF PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS UNDER-IFRS 9

a) The detail of depreciation and amortization for the years ended December 31, 2021, 2020 and 2019, is as follows:

	For the years ended December 31,
	2021	2020	2019
	ThUS$	ThUS$	ThUS$
Depreciation	(584,723)	(481,634)	(498,867)
Amortization	(408,373)	(376,465)	(449,463)
Subtotal	(993,096)	(858,099)	(948,330)

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b) The detail of the items related to impairment for the years ended December 31, 2021, 2020 and 2019, is as follows:

	Generation			Distribution			Other			For the year ended December 31,
	2021	2020	2019	2021	2020	2019	2021	2020	2019	2021	2020	2019
Information on Impairment Losses by Reportable Segment	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Assets and groups held for sale	—	—	—	—	—	3,433	—	—	—	—	—	3,433
Reversal (Losses) due to impairment of Intangibles (see Note 14)	—	—	—	—	—	—	(750)	—	—	(750)	—	—
Reversal (Losses) due to goodwill impairment (see Note 15)	—	—	—	—	—	—	(9,963)	—	—	(9,963)	—	—
Property, plants and equipment (see Note 16)	(89,344)	—	(1,307)	—	—	—	—	—	—	(89,344)	—	(1,307)
Total Reversal of impairment losses (impairment losses) recognized in income for the period	(89,344)	—	(1,307)	—	—	3,433	(10,713)	—	—	(100,057)	—	2,126
Trade accounts receivable and other accounts receivable (see Note 9)	(7,207)	(349)	645	(308,439)	(211,289)	(159,909)	(358)	102	14	(316,004)	(211,536)	(159,250)
Other assets	(1,723)	(585)	—	(27,117)	(30,251)	(119,325)	(328)	—	(550)	(29,168)	(30,836)	(119,875)
Impairment gains and reversal of impairment losses (Impairment losses) determined in accordance with IFRS 9	(8,930)	(934)	645	(335,556)	(241,540)	(279,234)	(686)	102	(536)	(345,172)	(242,372)	(279,125)
Total reversal (losses) due to Impairment	(98,274)	(934)	(662)	(335,556)	(241,540)	(275,801)	(11,399)	102	(536)	(445,229)	(242,372)	(276,999)

31. OTHER EXPENSE, BY NATURE

Other miscellaneous operating expenses for the years ended December 31, 2021, 2020 and 2019, are as follows:

		For the years ended December 31,
Other expenses		2021	2020	2019
		ThUS$	ThUS$	ThUS$
Professional, outsourced and other services		(563,796)	(473,655)	(518,101)
Administrative expenses		(101,574)	(99,813)	(106,433)
Repairs and maintenance		(195,566)	(232,305)	(253,036)
Indemnities and fines		(5,162)	(8,886)	(11,535)
Taxes and charges		(28,648)	(24,470)	(25,673)
Insurance premiums		(52,198)	(39,525)	(38,755)
Leases and rental costs		(2,728)	(10,641)	(10,341)
Public relations and advertising		(12,049)	(9,175)	(11,811)
Other supplies and services		(151,588)	(161,673)	(155,940)
Travel expenses		(4,133)	(2,892)	(16,324)
Environmental expenses	���	(1,790)	(2,243)	(2,760)
Total		(1,119,232)	(1,065,278)	(1,150,709)

Research expenses are recognized directly in income for the year. The amount of these expenses for the years ended December 31, 2021, 2020 and 2019, amounted to ThUS$ 154, ThUS$ 54 and ThUS$ 86, respectively.

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32. FINANCIAL RESULTS

Finance income and costs for the years ended December 31, 2021, 2020 and 2019, are as follows:

	For the years ended December 31,
	2021	2020 (*)	2019 (*)
Finance Income	ThUS$	ThUS$	ThUS$
Cash and cash equivalents	64,812	59,510	64,794
Financial income on plan assets (Brazil) (1)	3	15	27
Interest collected to customers on energy bills and invoices	97,028	66,080	76,122
Other financial income (2)	133,599	96,801	235,373
Total financial income	295,442	222,406	376,316
	For the years ended December 31,
	2021	2020	2019
Finance Costs	ThUS$	ThUS$	ThUS$
Finance Costs	(1,052,065)	(768,453)	(1,088,631)
Bank loans	(126,357)	(70,023)	(134,024)
Bonds payable	(224,733)	(208,630)	(281,359)
Lease obligations	(2,918)	(9,396)	(11,712)
Valuation of financial derivatives	(107,027)	(10,207)	(18,610)
Financial restatement of provisions (3)	(83,640)	(89,713)	(119,966)
Capitalized finance expenses	19,628	7,561	15,703
Post-employment benefit obligations (1)	(110,580)	(104,918)	(108,699)
Formalization of debt and other associated expenses	(10,505)	(7,134)	(11,323)
Financial expenses - related parties (4)	(64,094)	(2,441)	(127,977)
Other financial costs (5)	(341,839)	(273,552)	(290,664)
Gains (losses) from indexed assets and liabilities (*)	30,667	76,698	124,477
Foreign currency exchange differences (**)	(1,686)	57,171	136,960
Total financial costs	(1,023,084)	(634,584)	(827,194)
Total financial results	(727,642)	(412,178)	(450,878)

(*) See Note 2.2.c

(1) See Note 25.2. c).

(2) For the year ended December 31, 2021, this includes finance income from the regulatory assets of the Brazilian subsidiaries of ThUS$ 38,220 (ThUS$ 32,715 and ThUS$ 48,228 as of December 31, 2020 and 2019, respectively), finance income from the financial update of PIS/Cofins taxes receivable of Enel Generación Fortaleza of ThUS$ 3,076 (ThUS$ 546 and ThUS$ 14,330 as of December 31, 2020 and 2019, respectively), finance income from VOSA accounts receivable of Argentine generation subsidiaries of ThUS$ 11,470 (ThUS$ 12,387 and ThUS$ 80,738 as of December 31, 2020 and 2019, respectively), income from the revaluation of investments after the change in ownership of the Manuel Belgrano Thermal Power Plant and San Martin Thermal Power Plant of ThUS$ 5,064 (ThUS$24,893 and ThUS$0 as of December 31, 2020 and 2019, respectively) (see Note 13) and other income of ThUS$ 75,769 (ThUS$ 26,260 and ThUS$ 92,077 as of December 31, 2020 and 2019, respectively).

(3) For the year ended December 31, 2021, the Company included ThUS$ 27,870 (ThUS$ 13,754 and ThUS$ 56,225 as of December 31, 2020 and 2019, respectively) from our subsidiary Edesur, related to the finance cost generated by the update of the penalty for service quality due to the application of ENRE Resolution No. 1/2016 (See Note 23). Additionally, our Brazilian subsidiaries have recognized ThUS$ 57,389, ThUS$ 70,622 and ThUS$54,002 during the years ended December 31, 2021, 2020 and 2019, respectively, for accounting update of legal claims.

F-149

(4) For the year ended December 31, 2021, this item records interest on the debt with Enel Finance International NV of ThUS$39,181 (ThUS$ 2,441 and ThUS$ 127,977 as of December 31, 2020 and 2019, respectively) and finance costs related to guarantees granted by Enel SpA of ThUS$ 24,913 (ThUS$ 0 as of December 31, 2020 and 2019) (see Note 10.d).

(5) For the year ended December 31, 2021, this item records interest from CAMMESA’s debt of ThUS$ 187,277 (ThUS$ 88,415 and ThUS$ 91,864 as of December 31, 2020 and 2019, respectively), banking costs of ThUS$16,050 (ThUS$ 32,533 and ThUS$ 53,458 as of December 31, 2020 and 2019, respectively) and Others of ThUS$ 138,512 (ThUS$ 152,604 and ThUS$ 145,342 as of December 31, 2020 and 2019, respectively).

(**) The origins of the effects on financial results by adjustment units and exchange differences are detailed as follows:

	For the years ended December 31,
	2021	2020	2019
Gains (losses) from Indexed Assets and Liabilities (*)	ThUS$	ThUS$	ThUS$
Inventories	31,336	27,150	25,670
Investments accounted for using the equity method	55	48	79
Intangible assets other than goodwill	26,844	11,601	8,867
Goodwill	10,263	6,530	8,858
Property, plant and equipment	755,603	485,353	646,811
Deferred tax assets	29,002	14,665	20,861
Deferred tax liabilities	(137,607)	(89,669)	(119,471)
Total Equity	(670,974)	(355,914)	(382,962)
Revenues	(162,558)	(150,056)	(346,360)
Raw materials and consumables used	137,615	126,134	241,081
Financial results	14,725	2,818	(1,559)
Other Expenses	(576)	(3,317)	95
Corporate tax	(3,061)	1,355	22,507
Hiperinflation Result (1)	30,667	76,698	124,477
Gain from Indexed Assets and Liabilities	30,667	76,698	124,477
	For the years ended December 31,
	2021	2020	2019
Foreign Currency Exchange Differences (**)	ThUS$	ThUS$	ThUS$
Cash and cash equivalents	(7,767)	8,277	3,553
Other financial assets	270,329	130,570	57,818
Other non-financial assets	14,618	27,195	379
Trade accounts receivable and other accounts receivable	42,099	57,226	210,587
Investment property	6,222	—	—
Other financial liabilities (financial debt and derivative instruments)	(240,245)	(30,988)	(43,692)
Trade and other payables	(66,775)	(46,073)	(45,142)
Other non-financial liabilities	(20,167)	(89,036)	(46,543)
Total	(1,686)	57,171	136,960

1) Corresponds to the financial effect derived from the application of IAS 29 "Financial Reporting in Hyperinflationary Economies". (See Note 2.9).

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33. INFORMATION BY SEGMENT

33.1 Basis of segmentation

The Group’s activities operate under a matrix management structure with dual and cross management responsibilities (based on business and geographical areas of responsibility), and its subsidiaries are engaged in either the Generation and Transmission Business or the Distribution Business.

The Group adopted a “bottom-up” approach to determine its reportable segments. The Generation and Transmission and the Distribution reportable segments have been defined based on IFRS 8.9 and on the criteria described in IFRS 8.12, taking into account the aggregation of the operating segments having similar economic drivers that are common in all countries.

Generation and Transmission Business: The Generation and Transmission Reportable Segment is comprised of a group of electricity companies that own electricity generating plants, whose energy is transmitted and distributed to end customers.

The following 5 operating segments have been aggregated into one combined set of information for the Generation and Transmission Reportable Segment:

Generation and Transmission Reportable Segment:

> Generation and Transmission Business in Argentina

> Generation and Transmission Business in Brazil

> Generation and Transmission Business in Colombia

> Generation and Transmission Business in Peru

> Generation and Transmission Business in Central America

The Generation and Transmission Business is conducted: in Argentina through Enel Trading Argentina (formerly Cemsa), Central Dock Sud, Enel Generación Costanera, Enel Generación El Chocón and Enel Green Power Argentina S.A.; in Brazil through through our subsidiaries, EGP Cachoeira Dourada, Enel CIEN, Enel Green Power Proyectos I (Volta Grande), Fortaleza, Enel Trading Brasil S.A. and the EGP Group companies; in Colombia through our subsidiary Emgesa and Enel Green Power Colombia S.A.S ESP; in Peru through our subsidiaries Enel Generación Perú, Enel Generación Piura, Chinango and Enel Green Power Peru S.A.C and in Central America by our subsidiaries Enel Green Power Costa Rica S.A., Enel Green Power Guatemala S.A. and Enel Power Panamá S.R.L.

Distribution Business: The Distribution Reportable Segment is comprised of a group of electricity companies operating under a public utility concession, with service obligations and regulated tariffs for supplying regulated customers in four different countries.

The following 4 operating segments have been aggregated into one combined set of information for the Distribution Reportable Segment:

Distribution Reportable Segment:

> Distribution Business in Argentina

> Distribution Business in Brazil

> Distribution Business in Colombia

> Distribution Business in Peru

The Distribution Business is conducted: in Argentina through Edesur; in Brazil through Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Goias and Enel Distribución Sao Paulo (formerly Eletropaulo); in Colombia through Codensa; and in Peru through Enel Distribución Perú.

F-151

Each of the operating segments generates separate financial information, which is aggregated into one combined set of information for the Generation and Transmission Business, and another set of combined information for the Distribution Business at the reportable segment level. In addition, in order to assist the decision maker process, the Planning & Control Department at the parent company level prepares internal reports containing combined information at the reportable segment level about the main key performance indicators (KPIs), such as: Gross Operating Result, Gross Margin, Total Capex, Total Opex, profit or loss, Total Energy Generation and Transmission, among others. The presentation of information under this business/country approach has been made taking into consideration that the KPIs are similar and comparable in all countries, in each of the following aspects:

a) the nature of the activities: generation and transmission, on one hand, and distribution on the other;

b) the nature of the production processes: The Generation and Transmission Business deals with the generation of electricity and its transmission to dispatch centers, while the Distribution Business does not generate electricity, but distributes electricity to end customers;

c) the type or class of customer for their products and services: The Generation and Transmission Business provides services mainly to unregulated customers, while the Distribution Business provides energy to regulated customers;

d) the methods used to distribute their products or provide their services: generators generally sell the energy through energy auctions, while distributors provide energy in their concession area; and

e) the nature of the regulatory environment (public utilities): the regulatory frameworks differs in the Generation and Transmission Business and Distribution Business.

The Company’s chief operating decision maker (“CODM”) in conjunction with the country managers reviews on a monthly basis these internal reports and uses the KPI information to make decisions on the allocation of resources and the assessment of the performance of the operating segments for each reportable segment.

The information disclosed in the following tables is based on the financial information of the companies forming each segment. The accounting policies used to determine the segment information are the same as those used in the preparation of the Group’s consolidated financial statements.

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33.2 Generation and transmission, distribution and others

	Generation and Transmission		Distribution		Holdings, Eliminations and Others		Total
Line of business	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
ASSETS	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT ASSETS	1,940,708	1,752,168	4,934,818	4,321,551	186,953	105,537	7,062,479	6,179,256
Cash and cash equivalents	764,320	678,856	466,372	748,245	165,561	79,892	1,396,253	1,506,993
Other current financial assets	157,768	77,146	77,710	151,746	76,552	1,387	312,030	230,279
Other current non-financial assets	142,715	70,693	640,755	430,800	45,290	59,293	828,760	560,786
Trade and other current receivables	468,470	699,288	3,216,126	2,524,640	26,545	11,007	3,711,141	3,234,935
Current accounts receivable from related parties	220,992	110,101	30,074	19,689	(177,307)	(82,840)	73,759	46,950
Inventories	108,127	86,375	429,395	384,790	754	268	538,276	471,433
Current tax assets	78,316	29,709	73,866	61,641	49,558	36,530	201,740	127,880
Non-current assets or disposal groups held-for-sale or held for distribution to owners	—	—	520	—	—	—	520	—
NON-CURRENT ASSETS	10,275,479	5,023,349	16,146,273	14,821,340	1,474,707	909,613	27,896,459	20,754,302
Other non-current financial assets	506,387	293,011	2,911,429	2,497,735	55,360	117	3,473,176	2,790,863
Other non-current non-financial assets	125,676	44,772	3,013,019	2,284,187	6,726	3,897	3,145,421	2,332,856
Trade and other non-current receivables	244,390	280,119	467,016	297,872	13,445	533	724,851	578,524
Non-current accounts receivable from related parties	53,410	43,945	26	32	(53,410)	(43,945)	26	32
Investments accounted for using the equity method	402,308	111,027	13,748	1,596	(413,687)	(110,350)	2,369	2,273
Intangible assets other than goodwill	409,293	136,560	4,205,651	4,370,876	141,326	17,390	4,756,270	4,524,826
Goodwill	3,833	—	—	—	1,466,392	945,512	1,470,225	945,512
Property, plant and equipment	8,269,946	3,953,188	4,626,574	4,396,560	101,008	4,924	12,997,528	8,354,672
Investment properties	—	—	6,272	7,942	—	—	6,272	7,942
Right-of-use asset	191,230	127,537	112,756	94,180	23,967	703	327,953	222,420
Deferred tax assets	69,006	33,190	789,782	870,360	133,580	90,832	992,368	994,382
TOTAL ASSETS	12,216,187	6,775,517	21,081,091	19,142,891	1,661,660	1,015,150	34,958,938	26,933,558
Line of business	Generation and Transmission		Distribution		Holdings, Eliminations and Others		Total
LIABILITIES AND EQUITY	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT LIABILITIES	1,942,219	1,652,616	6,242,563	5,178,351	(389,248)	446,255	7,795,534	7,277,222
Other current financial liabilities	286,850	317,285	753,298	1,020,125	192,686	487,720	1,232,834	1,825,130
Current lease liability	21,519	21,478	36,795	29,753	2,373	264	60,687	51,495
Trade and other current payables	966,843	881,993	3,767,621	3,081,693	177,666	129,890	4,912,130	4,093,576
Current accounts payable to related parties	419,864	155,817	1,342,862	651,021	(807,019)	(209,716)	955,707	597,122
Other current provisions	29,711	79,356	134,918	141,067	215	2	164,844	220,425
Current tax liabilities	157,031	150,727	22,685	69,379	3,344	2,764	183,060	222,870
Other current non-financial liabilities	60,401	45,960	184,384	185,313	41,487	35,331	286,272	266,604
NON-CURRENT LIABILITIES	2,170,984	1,280,831	9,154,908	7,759,713	807,419	282,129	12,133,311	9,322,673
Other non-current financial liabilities	1,304,390	727,682	2,782,559	2,518,301	830,634	591,723	4,917,583	3,837,706
Non-current lease liability	84,031	11,591	82,232	78,882	21,628	597	187,891	91,070
Trade and other non-current payables	9,746	979	2,678,438	2,049,498	883	10,998	2,689,067	2,061,475
Non-current accounts payable to related parties	104,447	19,252	998,873	444,950	(40,822)	(319,811)	1,062,498	144,391
Other long-term provisions	132,432	84,179	705,375	749,514	1,012	207	838,819	833,900
Deferred tax liabilities	443,996	335,101	443,742	282,397	(8,338)	(4,545)	879,400	612,953
Non-current provisions for employee benefits	25,503	32,753	1,395,556	1,588,504	2,422	2,960	1,423,481	1,624,217
Other non-current non-financial liabilities	66,439	69,294	68,133	47,667	—	—	134,572	116,961
EQUITY	8,102,984	3,842,070	5,683,620	6,204,827	1,243,489	286,766	15,030,093	10,333,663
Equity attributable to shareholders of Enel Américas	8,102,984	3,842,070	5,683,620	6,204,827	1,243,489	286,766	12,832,657	8,105,859
Share and paid-in capital	5,636,230	1,821,697	2,972,017	2,902,092	7,191,252	5,039,289	15,799,499	9,763,078
Retained earnings (losses)	1,195,679	1,122,697	(270,485)	(82,505)	4,843,497	4,375,506	5,768,691	5,415,698
Issuance premium	337,107	37,138	46,819	55,685	(383,926)	(92,823)	—	—
Treasury shares in portfolio	(50)	(54)	—	—	(222)	54	(272)	—
Other reserves	934,018	860,592	2,935,269	3,329,555	(10,407,112)	(9,035,260)	(8,735,261)	(7,072,917)
Non-controlling interests	—	—	—	—	—	—	2,197,436	2,227,804
Total Liabilities and Equity	12,216,187	6,775,517	21,081,091	19,142,891	1,661,660	1,015,150	34,958,938	26,933,558

F-153

The Holding, Eliminations and Other column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

	Generation			Distribution			Holdings, Eliminations and Others			Total
Line of business STATEMENTS OF PROIT (LOSS)	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
REVENUE AND OTHER OPERATING INCOME	4,850,694	3,000,829	3,057,056	12,157,149	10,068,885	12,189,594	(815,507)	(777,969)	(859,193)	16,192,336	12,291,745	14,387,457
Revenues	4,774,522	2,977,178	3,007,419	10,647,295	9,039,284	10,905,824	(886,793)	(777,486)	(859,867)	14,535,024	11,238,976	13,053,376
Energy sales	4,670,098	2,880,510	2,885,369	8,961,340	7,511,207	9,217,909	(823,736)	(736,505)	(821,024)	12,807,702	9,655,212	11,282,254
Other sales	42,610	32,291	48,946	5,729	5,221	9,805	250	(544)	1	48,589	36,968	58,752
Other services rendered	61,814	64,377	73,104	1,680,226	1,522,856	1,678,110	(63,307)	(40,437)	(38,844)	1,678,733	1,546,796	1,712,370
Other income	76,172	23,651	49,637	1,509,854	1,029,601	1,283,770	71,286	(483)	674	1,657,312	1,052,769	1,334,081
RAW MATERIALS AND CONSUMABLES USED	(2,550,453)	(1,375,163)	(1,218,451)	(8,718,819)	(6,953,255)	(8,175,432)	817,889	772,503	852,860	(10,451,383)	(7,555,915)	(8,541,023)
Energy purchases	(2,004,478)	(918,086)	(578,373)	(6,524,262)	(5,149,046)	(6,323,836)	817,410	729,245	805,346	(7,711,330)	(5,337,887)	(6,096,863)
Fuel consumption	(116,682)	(137,850)	(277,116)	16	—	—	—	—	(1)	(116,666)	(137,850)	(277,117)
Transportation expenses	(297,568)	(226,531)	(260,281)	(782,629)	(838,996)	(903,489)	60,005	49,041	52,849	(1,020,192)	(1,016,486)	(1,110,921)
Other miscellaneous supplies and services	(131,725)	(92,696)	(102,681)	(1,411,944)	(965,213)	(948,107)	(59,526)	(5,783)	(5,334)	(1,603,195)	(1,063,692)	(1,056,122)
CONTRIBUTION MARGIN	2,300,241	1,625,666	1,838,605	3,438,330	3,115,630	4,014,162	2,382	(5,466)	(6,333)	5,740,953	4,735,830	5,846,434
Other work performed by the entity and capitalized	15,431	3,946	10,023	192,393	143,146	171,479	2,728	59	63	210,552	147,151	181,565
Employee benefits expense	(144,033)	(101,339)	(114,226)	(559,121)	(442,217)	(671,025)	(26,748)	(21,490)	(24,502)	(729,902)	(565,046)	(809,753)
Other expenses	(206,453)	(145,700)	(136,526)	(843,336)	(859,869)	(937,650)	(69,443)	(59,709)	(76,533)	(1,119,232)	(1,065,278)	(1,150,709)
GROSS OPERATING RESULT	1,965,186	1,382,573	1,597,876	2,228,266	1,956,690	2,576,966	(91,081)	(86,606)	(107,305)	4,102,371	3,252,657	4,067,537
Depreciation and amortization expense	(354,523)	(240,241)	(261,958)	(635,551)	(614,224)	(683,668)	(3,022)	(3,634)	(2,704)	(993,096)	(858,099)	(948,330)
Impairment (losses) reversals recognized in profit or loss	(89,344)	—	(1,307)	—	—	3,433	(10,713)	—	—	(100,057)	—	2,126
Gains (losses) for impairment in accordance with IFRS 9	(8,930)	(934)	645	(335,556)	(241,540)	(279,234)	(686)	102	(536)	(345,172)	(242,372)	(279,125)
OPERATING INCOME	1,512,389	1,141,398	1,335,256	1,257,159	1,100,926	1,617,497	(105,502)	(90,138)	(110,545)	2,664,046	2,152,186	2,842,208
FINANCIAL RESULT	(189,740)	(56,160)	4,788	(416,941)	(318,978)	(334,982)	(120,961)	(37,040)	(120,684)	(727,642)	(412,178)	(450,878)
Financial income	96,341	93,720	153,668	199,401	123,949	212,375	(300)	4,737	10,273	295,442	222,406	376,316
Cash and cash equivalents	33,709	32,879	99,237	19,663	14,687	26,372	11,440	11,944	19,923	64,812	59,510	145,532
Other financial income	62,632	60,841	54,431	179,738	109,262	186,003	(11,740)	(7,207)	(9,650)	230,630	162,896	230,784
Financial costs	(167,536)	(149,750)	(178,978)	(877,741)	(598,296)	(745,402)	(6,788)	(20,407)	(164,251)	(1,052,065)	(768,453)	(1,088,631)
Bank borrowings	(37,419)	(3,945)	(12,603)	(86,575)	(56,676)	(92,211)	(2,363)	(9,402)	(29,210)	(126,357)	(70,023)	(134,024)
Secured and unsecured obligations	(63,195)	(70,317)	(80,638)	(137,007)	(113,505)	(175,496)	(24,531)	(24,808)	(25,225)	(224,733)	(208,630)	(281,359)
Other	(66,922)	(75,488)	(85,737)	(654,159)	(428,115)	(477,695)	20,106	13,803	(109,816)	(700,975)	(489,800)	(673,248)
Income from indexation units	(164,888)	(85,734)	(83,759)	279,374	161,586	206,845	(83,819)	846	1,391	30,667	76,698	124,477
Foreign exchange profits (losses)	46,343	85,604	113,857	(17,975)	(6,217)	(8,800)	(30,054)	(22,216)	31,903	(1,686)	57,171	136,960
Share of profit (loss) of associates and joint ventures accounted for using the equity method	982	2,630	790	32	28	20	167	475	(227)	1,181	3,133	583
Other gains (losses)	2,100	3,764	1,287	1,118	903	12,909	—	4	—	3,218	4,671	14,196
Gain (loss) from other investments	—	50	1,042	543	—	6	—	4	—	543	54	1,048
Gain (loss) from the sale of assets	2,100	3,714	245	575	903	12,903	—	—	—	2,675	4,617	13,148
Profit (loss) before taxes	1,325,731	1,091,632	1,342,121	841,368	782,879	1,295,444	(226,296)	(126,699)	(231,456)	1,940,803	1,747,812	2,406,109
Income tax expense (income)	(446,211)	(326,573)	(419,338)	(396,085)	(278,107)	160,650	36,004	38,120	22,342	(806,292)	(566,560)	(236,346)
Profit (loss) from continuing operations	879,520	765,059	922,783	445,283	504,772	1,456,094	(190,292)	(88,579)	(209,114)	1,134,511	1,181,252	2,169,763
PROFIT (LOSS)	879,520	765,059	922,783	445,283	504,772	1,456,094	(190,292)	(88,579)	(209,114)	1,134,511	1,181,252	2,169,763
Profit (loss) attributable to	879,520	765,059	922,783	445,283	504,772	1,456,094	(190,292)	(88,579)	(209,114)	1,134,511	1,181,252	2,169,763
Profit (loss) attributable to owners of the parent	—	—	—	—	—	—	—	—	—	740,859	825,197	1,614,085
Profit (loss) attributable to non-controlling interests	—	—	—	—	—	—	—	—	—	393,652	356,055	555,678
Line of Business	Generation			Distribution			Eliminations			Total
STATEMENT OF CASH FLOWS	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Net cash flows from (used in) operating activities	1,845,460	1,109,985	1,052,312	855,641	1,448,867	1,603,242	(85,525)	(133,342)	(128,043)	2,615,576	2,425,510	2,527,511
Net cash flows from (used in) investing activities	(1,272,200)	(164,687)	(84,523)	(1,711,211)	(1,364,627)	(1,471,137)	1,049,114	(6,302)	(44,138)	(1,934,297)	(1,535,616)	(1,599,798)
Net cash flows from (used in) financing activities	(738,729)	(797,743)	(1,039,947)	627,354	40,508	(64,693)	(483,375)	(429,300)	281,736	(594,750)	(1,186,535)	(822,904)

The Holding, Eliminations and Other column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-154

33.3 Segment information by country

	Chile ( and Others)		Argentina		Brazil		Colombia		Peru		Central America		Eliminations		Total
Country ASSETS	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT ASSETS	445,620	249,106	617,133	603,494	4,804,124	4,138,518	657,247	850,472	550,690	546,260	290,651	—	(302,986)	(208,594)	7,062,479	6,179,256
Cash and cash equivalents	124,187	8,050	63,620	139,448	757,875	741,381	156,714	383,257	140,835	234,857	153,022	—	—	—	1,396,253	1,506,993
Other current financial assets	146	116	145,102	65,382	89,881	160,734	76,750	4,047	61	—	90	—	—	—	312,030	230,279
Other current non-financial assets	4,484	16,730	30,526	42,123	655,856	411,573	13,731	27,496	115,248	62,864	8,915	—	—	—	828,760	560,786
Trade and other current receivables	1,585	1,587	312,034	310,882	2,822,353	2,407,709	328,827	331,070	182,201	182,959	64,015	—	126	728	3,711,141	3,234,935
Current accounts receivable from related parties	305,735	213,077	1,694	148	6,885	38,761	1,662	1,790	4,930	2,496	55,965	—	(303,112)	(209,322)	73,759	46,950
Inventories	—	—	55,911	42,883	342,555	272,754	76,415	102,781	56,516	53,015	6,879	—	—	—	538,276	471,433
Current tax assets	9,483	9,546	8,246	2,628	128,719	105,606	2,628	31	50,899	10,069	1,765	—	—	—	201,740	127,880
Non-current assets or disposal groups held-for-sale or held for distribution to owners	—	—	—	—	—	—	520	—	—	—	—	—	—	—	520	—
NON-CURRENT ASSETS	16,425,543	10,473,781	2,810,065	2,468,259	16,352,912	11,374,761	4,253,624	4,397,892	2,670,200	2,382,886	1,406,373	—	(16,022,258)	(10,343,277)	27,896,459	20,754,302
Other non-current financial assets	—	—	26,194	25,461	3,326,017	2,765,194	6,718	153	12	55	114,235	—	—	—	3,473,176	2,790,863
Other non-current non-financial assets	5,157	2,980	831	898	3,041,765	2,272,857	27,954	33,029	36,068	23,092	33,646	—	—	—	3,145,421	2,332,856
Trade and other non-current receivables	43	77	226,424	268,536	470,304	276,346	20,201	33,565	—	—	7,879	—	—	—	724,851	578,524
Non-current accounts receivable from related parties	245,049	225,000	26	32	—	—	—	—	—	—	—	—	(245,049)	(225,000)	26	32
Investments accounted for using the equity method	16,172,024	10,245,701	309,908	315,981	—	—	118	127	10,033	—	288,385	—	(16,778,099)	(10,559,536)	2,369	2,273
Intangible assets other than goodwill	—	—	86,948	61,159	4,322,605	4,256,831	165,571	135,881	82,872	70,955	98,274	—	—	—	4,756,270	4,524,826
Goodwill	—	—	—	4,523	460,793	494,129	4,709	5,601	2,675	—	1,158	—	1,000,890	441,259	1,470,225	945,512
Property, plant and equipment	—	—	2,143,757	1,762,799	3,670,373	304,256	3,963,160	4,158,620	2,371,121	2,128,997	849,117	—	—	—	12,997,528	8,354,672
Investment properties	—	—	—	—	6,272	7,942	—	—	—	—	—	—	—	—	6,272	7,942
Right-of-use asset	—	24	49	124	117,760	43,099	60,872	19,639	138,295	159,534	10,977	—	—	—	327,953	222,420
Deferred tax assets	3,270	(1)	15,928	28,746	937,023	954,107	4,321	11,277	29,124	253	2,702	—	—	—	992,368	994,382
TOTAL ASSETS	16,871,163	10,722,887	3,427,198	3,071,753	21,157,036	15,513,279	4,910,871	5,248,364	3,220,890	2,929,146	1,697,024	—	(16,325,244)	(10,551,871)	34,958,938	26,933,558

	Chile (and Others)				Argentina		Brazil		Colombia		Peru		Central America		Eliminations		Total
Country LIABILITIES AND EQUITY	12-31-2021		12-31-2020		12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$		ThUS$		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT LIABILITIES	130,647		595,828		1,010,729	689,017	4,979,138	4,192,739	1,026,528	1,206,026	749,910	627,532	72,238	—	(173,656)	(33,920)	7,795,534	7,277,222
Other current financial liabilities	9,914		339,842		5,756	6,088	552,177	797,217	372,308	454,167	292,679	227,816	—	—	—	—	1,232,834	1,825,130
Current lease liability	—		19		14	78	23,393	15,702	9,246	4,792	27,366	30,904	668	—	—	—	60,687	51,495
Trade and other current payables	25,629		46,970		866,558	527,729	3,230,087	2,758,445	467,335	492,040	276,187	207,027	22,601	—	23,733	61,365	4,912,130	4,093,576
Current accounts payable to related parties	94,134		208,628		38,322	31,787	897,617	337,202	27,518	72,213	62,475	42,577	33,030	—	(197,389)	(95,285)	955,707	597,122
Other current provisions	54		—		49,900	45,167	76,248	77,844	30,974	40,176	7,668	57,238	-	—	—	—	164,844	220,425
Current tax liabilities	—	—	—		13,882	44,383	13,703	33,986	87,273	110,724	53,643	33,777	14,559	—	—	—	183,060	222,870
Other current non-financial liabilities	916		369		36,297	33,785	185,913	172,343	31,874	31,914	29,892	28,193	1,380	—	—	—	286,272	266,604
NON-CURRENT LIABILITIES	594,560		597,203		651,831	509,899	8,551,717	6,168,982	1,513,850	1,537,229	909,570	734,467	157,224	—	(245,441)	(225,107)	12,133,311	9,322,673
Other non-current financial liabilities	590,081		591,722		36,210	40,785	2,525,836	1,539,623	1,213,912	1,251,199	551,544	414,377	—	—	—	—	4,917,583	3,837,706
Non-current lease liability	—		—		24	45	99,943	35,901	53,588	15,639	23,212	39,485	11,124	—	—	—	187,891	91,070
Trade and other non-current payables	—		—		53,914	86,559	2,633,688	1,962,061	874	1,136	591	11,719	—	—	—	—	2,689,067	2,061,475
Non-current accounts payable to related parties	—		—		—	—	1,203,492	369,498	—	—	7,804	—	96,643	—	(245,441)	(225,107)	1,062,498	144,391
Other long-term provisions	—		—		19,116	19,760	685,669	714,757	74,773	78,504	51,819	20,879	7,442	—	—	—	838,819	833,900
Deferred tax liabilities	2,057		2,521		459,883	286,936	41,194	40,030	83,284	63,683	251,287	219,783	41,695	—	—	—	879,400	612,953
Non-current provisions for employee benefits	2,422		2,960		17,231	13,920	1,311,654	1,476,884	87,419	124,248	4,435	6,205	320	—	—	—	1,423,481	1,624,217
Other non-current non-financial liabilities	—		—		65,453	61,894	50,241	30,228	—	2,820	18,878	22,019	—	—	—	—	134,572	116,961
EQUITY	16,145,956		9,529,856		1,764,638	1,872,837	7,626,181	5,151,558	2,370,493	2,505,109	1,561,410	1,567,147	1,467,562	—	(15,906,147)	(10,292,844)	15,030,093	10,333,663
Equity attributable to shareholders of Enel Américas	16,145,956		9,529,856		1,764,638	1,872,837	7,626,181	5,151,558	2,370,493	2,505,109	1,561,410	1,567,147	1,467,562	—	(15,906,147)	(10,292,844)	12,832,657	8,105,859
Share and paid-in capital	16,512,785		9,763,079		1,733,076	953,561	5,830,987	3,695,565	167,712	195,415	1,632,426	1,483,352	997,095	—	(11,074,582)	(6,327,894)	15,799,499	9,763,078
Retained earnings (losses)	3,290,142		3,008,390		(1,075,881)	(121,454)	726,440	197,561	843,648	972,249	116,498	272,808	407,820	—	1,460,024	1,086,144	5,768,691	5,415,698
Issuance premium	—		—	0	—	—	536,514	575,327	380,242	88,781	1,483	1,612	—	—	(918,239)	(665,720)	—	—
Treasury shares in portfolio	(272)		—		—	—	(19,933)	(21,375)	—	—	—	—	—	—	19,933	21,375	(272)	—
Other reserves	(3,656,699)		(3,241,613)		1,107,443	1,040,730	552,173	704,480	978,891	1,248,664	(188,997)	(190,625)	62,647	—	(5,393,283)	(4,406,749)	(8,735,261)	(7,072,917)
Non-controlling interests	—		—		—	—	—	—	—	—	—	—	—	—	—	—	2,197,436	2,227,804
Total Liabilities and Equity	16,871,163		10,722,887		3,427,198	3,071,753	21,157,036	15,513,279	4,910,871	5,248,364	3,220,890	2,929,146	1,697,024	—	(16,325,244)	(10,551,871)	34,958,938	26,933,558

F-155

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

	Chile (and Others)			Argentina			Brazil			Colombia			Peru			Central America			Eliminations			Total
Country STATEMENTS OF PROIT (LOSS)	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
REVENUE AND OTHER OPERATING INCOME	459	165	902	1,020,808	1,030,361	1,782,532	11,010,682	7,679,515	8,682,235	2,611,405	2,337,750	2,538,922	1,316,723	1,243,993	1,382,940	232,548	—	—	(289)	(39)	(74)	16,192,336	12,291,745	14,387,457
Revenues	147	—	—	1,002,520	995,970	1,481,493	9,485,935	6,696,125	7,685,111	2,525,043	2,311,045	2,513,971	1,304,744	1,235,836	1,372,801	216,619	—	—	16	—	—	14,535,024	11,238,976	13,053,376
Energy sales	—	—	—	959,343	958,852	1,435,040	8,660,405	5,944,342	6,805,945	1,732,425	1,564,664	1,734,645	1,241,473	1,187,354	1,306,624	214,056	—	—	—	—	—	12,807,702	9,655,212	11,282,254
Other sales	—	—	—	3,007	2,431	2,771	152	698	3,755	30,159	23,990	28,737	15,273	9,849	23,489	—	—	—	(2)	—	—	48,589	36,968	58,752
Other services rendered	147	—	—	40,170	34,687	43,682	825,378	751,085	875,411	762,459	722,391	750,589	47,998	38,633	42,688	2,563	—	—	18	—	—	1,678,733	1,546,796	1,712,370
Other income	312	165	902	18,288	34,391	301,039	1,524,747	983,390	997,124	86,362	26,705	24,951	11,979	8,157	10,139	15,929	—	—	(305)	(39)	(74)	1,657,312	1,052,769	1,334,081
RAW MATERIALS AND CONSUMABLES USED	(44)	(99)	—	(547,878)	(551,514)	(903,365)	(8,160,658)	(5,450,908)	(5,906,736)	(1,047,352)	(930,528)	(1,054,749)	(652,394)	(622,866)	(676,173)	(43,057)	—	—	—	—	—	(10,451,383)	(7,555,915)	(8,541,023)
Energy purchases	—	—	—	(492,225)	(490,953)	(715,723)	(6,206,070)	(3,896,510)	(4,311,902)	(537,258)	(500,924)	(596,652)	(453,791)	(449,500)	(473,129)	(21,986)	—	—	—	—	543	(7,711,330)	(5,337,887)	(6,096,863)
Fuel consumption	—	—	—	(1,170)	(1,180)	(100,579)	(32,314)	(41,363)	(58,506)	(20,599)	(39,785)	(49,225)	(62,583)	(55,522)	(68,807)	—	—	—	—	—	-	(116,666)	(137,850)	(277,117)
Transportation expenses	—	—	—	(18,016)	(24,348)	(25,949)	(639,364)	(675,394)	(739,219)	(273,634)	(247,325)	(261,082)	(77,002)	(69,419)	(84,128)	(12,176)	—	—	—	—	(543)	(1,020,192)	(1,016,486)	(1,110,921)
Other miscellaneous supplies and services	(44)	(99)	—	(36,467)	(35,033)	(61,114)	(1,282,910)	(837,641)	(797,109)	(215,861)	(142,494)	(147,790)	(59,018)	(48,425)	(50,109)	(8,895)	—	—	—	—	—	(1,603,195)	(1,063,692)	(1,056,122)
CONTRIBUTION MARGIN	415	66	902	472,930	478,847	879,167	2,850,024	2,228,607	2,775,499	1,564,053	1,407,222	1,484,173	664,329	621,127	706,767	189,491	—	—	(289)	(39)	(74)	5,740,953	4,735,830	5,846,434
Other work performed by the entity and capitalized	—	—	—	50,036	31,296	48,095	114,189	76,744	89,871	31,984	28,877	32,179	14,343	10,234	11,420	—	—	—	—	—	—	210,552	147,151	181,565
Employee benefits expense	(7,532)	(5,957)	(7,695)	(194,075)	(154,984)	(200,284)	(353,816)	(234,994)	(434,266)	(98,364)	(107,827)	(102,834)	(63,957)	(61,284)	(64,674)	(12,158)	—	—	—	—	—	(729,902)	(565,046)	(809,753)
Other expenses	(24,059)	(21,054)	(23,211)	(175,618)	(169,255)	(175,437)	(662,059)	(632,746)	(713,637)	(145,507)	(148,088)	(146,478)	(93,137)	(94,174)	(92,020)	(19,156)	—	—	304	39	74	(1,119,232)	(1,065,278)	(1,150,709)
GROSS OPERATING RESULT	(31,176)	(26,945)	(30,004)	153,273	185,904	551,541	1,948,338	1,437,611	1,717,467	1,352,166	1,180,184	1,267,040	521,578	475,903	561,493	158,177	—	—	15	—	—	4,102,371	3,252,657	4,067,537
Depreciation and amortization expense	—	—	—	(191,590)	(160,424)	(143,179)	(462,945)	(393,848)	(488,163)	(192,774)	(181,986)	(195,488)	(118,166)	(121,841)	(121,500)	(27,621)	—	—	—	—	—	(993,096)	(858,099)	(948,330)
Impairment (losses) reversals recognized in profit or loss	—	—	—	(87,492)	—	—	—	—	—	—	—	3,433	(8,193)	—	(1,307)	—	—	—	(4,372)	—	—	(100,057)	—	2,126
Gains (losses) for impairment in accordance with IFRS 9	(110)	—	—	(8,957)	(44,434)	(42,541)	(314,155)	(167,469)	(225,557)	(14,354)	(16,442)	(6,609)	(7,653)	(14,027)	(4,418)	57	—	—	—	—	—	(345,172)	(242,372)	(279,125)
OPERATING INCOME	(31,286)	(26,945)	(30,004)	(134,766)	(18,954)	365,821	1,171,238	876,294	1,003,747	1,145,038	981,756	1,068,376	387,566	340,035	434,268	130,613	—	—	(4,357)	—	—	2,664,046	2,152,186	2,842,208
FINANCIAL RESULT	(118,049)	(21,872)	(31,514)	(33,872)	65,733	160,817	(478,215)	(391,757)	(447,507)	(97,679)	(119,660)	(140,101)	(29,964)	(26,007)	(30,553)	(3,111)	—	—	33,248	81,385	37,980	(727,642)	(412,178)	(450,878)
Financial income	21,333	25,063	37,675	90,274	85,954	122,200	181,403	112,030	217,917	14,675	13,848	11,548	5,803	6,508	8,632	2,792	—	—	(20,838)	(20,997)	(21,656)	295,442	222,406	376,316
Cash and cash equivalents	495	4,066	16,018	50,182	40,218	90,691	9,074	4,727	25,405	4,431	7,743	8,573	572	2,756	4,845	58	—	—	—	—	—	64,812	59,510	145,532
Other financial income	20,838	20,997	21,657	40,092	45,736	31,509	172,329	107,303	192,512	10,244	6,105	2,975	5,231	3,752	3,787	2,734	—	—	(20,838)	(20,997)	(21,656)	230,630	162,896	230,784
Financial costs	(64,235)	(62,972)	(50,740)	(247,098)	(148,439)	(189,401)	(617,330)	(414,707)	(679,377)	(109,145)	(132,205)	(151,500)	(28,767)	(31,127)	(39,268)	(6,328)	—	—	20,838	20,997	21,655	(1,052,065)	(768,453)	(1,088,631)
Bank borrowings	(1,616)	(9,190)	(11,379)	(723)	(3,334)	(4,019)	(104,414)	(45,544)	(106,312)	(12,641)	(8,732)	(10,896)	(6,963)	(3,223)	(1,418)	—	—	—	—	—	—	(126,357)	(70,023)	(134,024)
Secured and unsecured obligations	(24,530)	(24,809)	(25,225)	—	(1)	—	(98,599)	(67,717)	(112,770)	(81,574)	(91,178)	(116,309)	(20,030)	(24,925)	(27,055)	—	—	—	—	—	—	(224,733)	(208,630)	(281,359)
Other	(38,089)	(28,973)	(14,136)	(246,375)	(145,104)	(185,382)	(414,317)	(301,446)	(460,295)	(14,930)	(32,295)	(24,295)	(1,774)	(2,979)	(10,795)	(6,328)	—	—	20,838	20,997	21,655	(700,975)	(489,800)	(673,248)
Income from indexation units	-	-	-	30,667	76,698	124,477	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	30,667	76,698	124,477
Foreign exchange profits (losses)	(75,147)	16,037	(18,449)	92,285	51,520	103,541	(42,288)	(89,080)	13,953	(3,209)	(1,303)	(149)	(7,000)	(1,388)	83	425	—	—	33,248	81,385	37,981	(1,686)	57,171	136,960
Share of profit (loss) of associates and joint ventures accounted for using the equity method	168	475	(227)	1,013	2,658	810	—	—	—	—	—	—	—	—	—	—	—		—	—	—	1,181	3,133	583
Other gains (losses)	-	-	—	1,602	61	1,080	523	870	2,144	640	124	308	26	3,616	10,664	427	—	—	—	—	—	3,218	4,671	14,196
Gain (loss) from other investments	-	-	—	-	54	1,041	543	—	1	—	—	6	—	—	-	—	—	—	—	—	—	543	54	1,048
Gain (loss) from the sale of assets	-	-	—	1,602	7	39	(20)	870	2,143	640	124	302	26	3,616	10,664	427	—	—	—	—	—	2,675	4,617	13,148
Profit (loss) before taxes	(149,167)	(48,342)	(61,745)	(166,023)	49,498	528,528	693,546	485,407	558,384	1,047,999	862,220	928,583	357,628	317,644	414,379	127,929	—	—	28,891	81,385	37,980	1,940,803	1,747,812	2,406,109
Income tax expense (income)	1,101	(3,840)	9,598	(138,296)	(36,154)	(132,137)	(183,498)	(147,963)	313,730	(327,227)	(286,707)	(302,350)	(125,751)	(91,896)	(125,187)	(32,621)	—	—	—	—	—	(806,292)	(566,560)	(236,346)
Profit (loss) from continuing operations	(148,066)	(52,182)	(52,147)	(304,319)	13,344	396,391	510,048	337,444	872,114	720,772	575,513	626,233	231,877	225,748	289,192	95,308	—	—	28,891	81,385	37,980	1,134,511	1,181,252	2,169,763
PROFIT (LOSS)	(148,066)	(52,182)	(52,147)	(304,319)	13,344	396,391	510,048	337,444	872,114	720,772	575,513	626,233	231,877	225,748	289,192	95,308	—	—	28,891	81,385	37,980	1,134,511	1,181,252	2,169,763
Profit (loss) attributable to	(148,066)	(52,182)	(52,147)	(304,319)	13,344	396,391	510,048	337,444	872,114	720,772	575,513	626,233	231,877	225,748	289,192	95,308	—	—	28,891	81,385	37,980	1,134,511	1,181,252	2,169,763
Profit (loss) attributable to owners of the parent																						740,859	825,197	1,614,085
Profit (loss) attributable to non-controlling interests																						393,652	356,055	555,678
Line of Business	Chile (and Others)			Argentina			Brazil			Colombia			Peru			Central America			Eliminations			Total
STATEMENT OF CASH FLOWS	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Net cash flows from (used in) operating activities	(64,071)	(52,803)	(49,135)	396,787	272,134	241,095	679,753	922,297	999,122	1,028,000	939,651	865,922	448,032	342,021	454,719	122,998	—	—	4,077	2,210	15,788	2,615,576	2,425,510	2,527,511
Net cash flows from (used in) investing activities	391,298	175,657	(2,220,047)	(263,820)	(169,918)	(175,679)	(1,868,087)	(755,047)	(855,965)	(587,280)	(464,647)	(386,559)	(241,946)	(176,299)	(208,685)	1,168	—	—	634,370	(145,362)	2,247,137	(1,934,297)	(1,535,616)	(1,599,798)
Net cash flows from (used in) financing activities	(920,387)	(719,042)	2,475,888	(140,081)	(59,659)	(47,566)	1,087,188	(55,832)	(66,875)	(641,850)	(303,393)	(705,497)	(283,804)	(192,090)	(215,929)	(85,426)	—	—	389,610	143,481	(2,262,925)	(594,750)	(1,186,535)	(822,904)

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-156

33.4  Generation and Transmission, and Distribution by Country

a)  Generation and transmission

Line of business	Argentina		Brazil		Colombia		Peru		Centro America		Eliminations		Total
Country ASSETS	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT ASSETS	341,299	297,094	786,002	725,298	187,002	353,946	335,969	375,830	290,651	—	(215)	—	1,940,708	1,752,168
Cash and cash equivalents	50,719	80,741	417,963	167,713	62,443	239,549	80,173	190,853	153,022	—	—	—	764,320	678,856
Other current financial assets	110,340	41,991	34,053	31,382	13,267	3,773	18	—	90	—	—	—	157,768	77,146
Other current non-financial assets	13,328	12,401	34,081	25,705	4,393	9,254	81,998	23,333	8,915	—	—	—	142,715	70,693
Trade and other current receivables	98,619	111,216	155,202	444,478	80,857	70,578	69,769	73,008	64,015	—	8	8	468,470	699,288
Current accounts receivable from related parties	19,263	18,509	117,535	38,033	1,024	926	27,428	52,641	55,965	—	(223)	(8)	220,992	110,101
Inventories	43,587	29,608	8,613	320	23,135	29,866	25,913	26,581	6,879	—	—	—	108,127	86,375
Current tax assets	5,443	2,628	18,555	17,667	1,883	—	50,670	9,414	1,765	—	—	—	78,316	29,709
NON-CURRENT ASSETS	618,490	715,591	4,292,782	693,610	2,438,355	2,420,482	1,519,479	1,193,666	1,406,373	—	—	—	10,275,479	5,023,349
Other non-current financial assets	26,189	25,454	365,845	267,351	118	151	-	55	114,235	—	—	—	506,387	293,011
Other non-current non-financial assets	782	839	46,944	12,463	8,236	8,378	36,068	23,092	33,646	—	—	—	125,676	44,772
Trade and other non-current receivables	226,047	268,076	6,515	8,020	3,949	4,023	—	—	7,879	—	—	—	244,390	280,119
Non-current accounts receivable from related parties	11,199	18,411	—	—	—	—	42,211	25,534	—	—	—	—	53,410	43,945
Investments accounted for using the equity method	1,158	1,145	53,658	55,520	2,081	2,475	57,026	51,887	288,385	—	—	—	402,308	111,027
Intangible assets other than goodwill	12,963	11,092	205,812	69,410	63,225	30,113	29,019	25,945	98,274	—	—	—	409,293	136,560
Goodwill	—	—	—	—	—	—	2,675	—	1,158	—	—	—	3,833	-
Property, plant and equipment	331,081	371,322	3,542,071	266,974	2,330,673	2,373,206	1,217,004	941,686	849,117	—	—	—	8,269,946	3,953,188
Right-of-use asset	—	—	43,822	184	30,073	2,136	106,358	125,217	10,977	—	—	—	191,230	127,537
Deferred tax assets	9,071	19,252	28,115	13,688	—	—	29,118	250	2,702	—	—	—	69,006	33,190
TOTAL ASSETS	959,789	1,012,685	5,078,784	1,418,908	2,625,357	2,774,428	1,855,448	1,569,496	1,697,024	—	(215)	—	12,216,187	6,775,517

Line of business
Country	Argentina		Brazil		Colombia		Peru		Centro America		Eliminations		Total
LIABILITIES AND EQUITY	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT LIABILITIES	147,137	161,117	971,751	665,046	444,371	570,719	306,937	255,734	72,238	—	(215)	—	1,942,219	1,652,616
Other current financial liabilities	5,756	6,088	61,544	21,768	151,919	263,242	67,631	26,187	—	—	—	—	286,850	317,285
Current lease liability	—	—	4,633	138	4,974	1,793	11,244	19,547	668	—	—	—	21,519	21,478
Trade and other current payables	68,361	60,088	594,020	578,444	172,812	153,466	109,049	89,995	22,601	—	—	—	966,843	881,993
Current accounts payable to related parties	34,873	29,041	280,513	49,014	16,305	45,183	55,358	32,579	33,030	—	(215)	—	419,864	155,817
Other current provisions	6,629	1,380	163	(3)	20,259	29,096	2,660	48,883	—	—	—	—	29,711	79,356
Current tax liabilities	13,775	41,620	13,672	7,071	67,973	70,498	47,052	31,538	14,559	—	—	—	157,031	150,727
Other current non-financial liabilities	17,743	22,900	17,206	8,614	10,129	7,441	13,943	7,005	1,380	—	—	—	60,401	45,960
									33,646	—	—	—
NON-CURRENT LIABILITIES	133,970	144,807	779,011	179,215	614,399	697,178	486,380	259,631	157,224	—	—	—	2,170,984	1,280,831
Other non-current financial liabilities	36,210	40,785	676,689	127,378	419,434	542,592	172,057	16,927	—	—	—	—	1,304,390	727,682
Non-current lease liability	—	—	40,152	83	26,329	515	6,426	10,993	11,124	—	—	—	84,031	11,591
Trade and other non-current payables	—	—	9,103	215	643	764	—	—	—	—	—	—	9,746	979
Non-current accounts payable to related parties	—	—	—	19,252	—	—	7,804	—	96,643	—	—	—	104,447	19,252
Other long-term provisions	54	62	8,569	1,730	64,963	61,967	51,404	20,420	7,442	—	—	—	132,432	84,179
Deferred tax liabilities	54,384	52,504	34,870	29,787	83,284	63,683	229,763	189,127	41,695	—	—	—	443,996	335,101
Non-current provisions for employee benefits	4,034	3,190	—	—	19,746	27,657	1,403	1,906	320	—	—	—	25,503	32,753
Other non-current non-financial liabilities	39,288	48,266	9,628	770	—	—	17,523	20,258	—	—	—	—	66,439	69,294
										—	—	—
EQUITY	678,682	706,761	3,328,022	574,647	1,566,587	1,506,531	1,062,131	1,054,131	1,467,562	—	—	—	8,102,984	3,842,070
Equity attributable to shareholders of Enel Américas	678,682	706,761	3,328,022	574,647	1,566,587	1,506,531	1,062,131	1,054,131	1,467,562	—	—	—	8,102,984	3,842,070
Share and paid-in capital	623,259	561,138	2,887,438	215,930	164,398	191,473	964,040	853,156	997,095	—	—	—	5,636,230	1,821,697
Retained earnings (losses)	(126,251)	11,406	283,482	237,270	526,401	665,670	104,227	208,351	407,820	—	—	—	1,195,679	1,122,697
Issuance premium	—	—	—	—	333,423	33,096	3,684	4,042	—	—	—	—	337,107	37,138
Treasury shares	—	—	(50)	(54)	—	—	—	—	—	—	—	—	(50)	(54)
Other reserves	181,674	134,217	157,152	121,501	542,365	616,292	(9,820)	(11,418)	62,647	—	—	—	934,018	860,592
TOTAL LIABILITIES AND EQUITY	959,789	1,012,685	5,078,784	1,418,908	2,625,357	2,774,428	1,855,448	1,569,496	1,697,024	—	(215)	—	12,216,187	6,775,517

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-157

Line of business	Argentina			Brazil			Colombia			Peru			Central America			Eliminations			Total
Country STATEMENTS OF PROIT (LOSS)	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
REVENUE AND OTHER OPERATING INCOME	227,924	230,575	436,376	2,551,440	1,105,875	777,501	1,265,862	1,159,133	1,246,988	573,155	505,246	596,240	232,548	—	—	(235)	—	(49)	4,850,694	3,000,829	3,057,056
Revenues	223,247	224,081	415,055	2,503,577	1,102,091	761,534	1,265,392	1,150,185	1,240,405	565,687	500,821	590,425	216,619	—	—	—	—	—	4,774,522	2,977,178	3,007,419
Energy sales	221,484	220,869	413,343	2,449,812	1,040,995	691,904	1,236,953	1,128,070	1,213,754	547,793	490,576	566,368	214,056	—	—	—	—	—	4,670,098	2,880,510	2,885,369
Other sales	354	1,281	—	—	—	—	28,251	21,978	26,479	14,005	9,032	22,467	—	—	—	—	—	—	42,610	32,291	48,946
Other services rendered	1,409	1,931	1,712	53,765	61,096	69,630	188	137	172	3,889	1,213	1,590	2,563	—	—	—	—	—	61,814	64,377	73,104
Other income	4,677	6,494	21,321	47,863	3,784	15,967	470	8,948	6,583	7,468	4,425	5,815	15,929	—	—	(235)	—	(49)	76,172	23,651	49,637
RAW MATERIALS AND CONSUMABLES USED	(17,329)	(19,110)	(129,661)	(1,906,531)	(781,186)	(418,618)	(408,423)	(412,529)	(465,768)	(175,113)	(162,338)	(204,404)	(43,057)	—	—	—	—	—	(2,550,453)	(1,375,163)	(1,218,451)
Energy purchases	(2,020)	(969)	(877)	(1,807,435)	(710,206)	(328,984)	(152,794)	(179,897)	(209,204)	(20,243)	(27,014)	(39,851)	(21,986)	—	—	—	—	543	(2,004,478)	(918,086)	(578,373)
Fuel consumption	(1,170)	(1,180)	(100,579)	(32,330)	(41,363)	(58,505)	(20,599)	(39,785)	(49,225)	(62,583)	(55,522)	(68,807)	—	—	—	—	—	—	(116,682)	(137,850)	(277,116)
Transportation expenses	(3,578)	(6,542)	(8,959)	(51,486)	(23,874)	(28,107)	(153,326)	(126,696)	(138,544)	(77,002)	(69,419)	(84,128)	(12,176)	—	—	—	—	(543)	(297,568)	(226,531)	(260,281)
Other miscellaneous supplies and services	(10,561)	(10,419)	(19,246)	(15,280)	(5,743)	(3,022)	(81,704)	(66,151)	(68,795)	(15,285)	(10,383)	(11,618)	(8,895)	—	—	—	—	—	(131,725)	(92,696)	(102,681)
CONTRIBUTION MARGIN	210,595	211,465	306,715	644,909	324,689	358,883	857,439	746,604	781,220	398,042	342,908	391,836	189,491	—	—	(235)	—	(49)	2,300,241	1,625,666	1,838,605
Other work performed by the entity and capitalized	2,566	375	4,785	8,387	215	653	3,237	2,438	3,008	1,241	918	1,577	—	—	—	—	—	—	15,431	3,946	10,023
Employee benefits expense	(38,733)	(30,398)	(38,147)	(34,062)	(12,934)	(16,422)	(31,380)	(31,049)	(31,806)	(27,700)	(26,958)	(27,851)	(12,158)	—	—	—	—	—	(144,033)	(101,339)	(114,226)
Other expenses	(39,649)	(41,328)	(28,259)	(57,537)	(14,876)	(22,191)	(42,238)	(44,547)	(42,102)	(48,108)	(44,949)	(44,023)	(19,156)	—	—	235	—	49	(206,453)	(145,700)	(136,526)
GROSS OPERATING RESULT	134,779	140,114	245,094	561,697	297,094	320,923	787,058	673,446	710,320	323,475	271,919	321,539	158,177	—	—	—	—	—	1,965,186	1,382,573	1,597,876
Depreciation and amortization expense	(108,849)	(86,575)	(89,645)	(90,077)	(23,371)	(32,785)	(68,280)	(66,263)	(73,761)	(59,696)	(64,032)	(65,767)	(27,621)	—	—	—	—	—	(354,523)	(240,241)	(261,958)
Impairment (losses) reversals recognized in profit or loss	(81,902)	—	—	—	—	—	—	—	—	(7,442)	—	(1,307)	—	—	—	—	—	—	(89,344)	—	(1,307)
Gains (losses) for impairment in accordance with IFRS 9	(380)	(96)	(40)	(5,910)	(535)	32	(1,427)	(315)	663	(1,270)	12	(10)	57	—	—	—	—	—	(8,930)	(934)	645
OPERATING INCOME	(56,352)	53,443	155,409	465,710	273,188	288,170	717,351	606,868	637,222	255,067	207,899	254,455	130,613	—	—	—	—	—	1,512,389	1,141,398	1,335,256
FINANCIAL RESULT	(38,372)	6,766	73,292	(100,239)	5,214	19,427	(42,302)	(70,522)	(81,785)	(5,716)	5,087	(6,146)	(3,111)	—	—	—	(2,705)	—	(189,740)	(56,160)	4,788
Financial income	66,576	72,368	98,572	21,434	11,100	41,484	3,642	5,465	6,239	1,897	4,787	7,373	2,792	—	—	—	—	—	96,341	93,720	153,668
Cash and cash equivalents	27,211	27,765	82,760	3,699	(1,009)	7,644	2,407	3,792	4,696	334	2,331	4,137	58	—	—	—	—	—	33,709	32,879	99,237
Other financial income	39,365	44,603	15,812	17,735	12,109	33,840	1,235	1,673	1,543	1,563	2,456	3,236	2,734	—	—	—	—	—	62,632	60,841	54,431
Financial costs	(8,318)	(29,397)	(47,784)	(100,262)	(39,278)	(31,209)	(46,827)	(76,221)	(87,896)	(5,801)	(4,854)	(12,089)	(6,328)	—	—	—	—	—	(167,536)	(149,750)	(178,978)
Bank borrowings	(318)	(2,955)	(62)	(32,001)	(579)	(9,925)	(3,112)	—	(2,522)	(1,988)	(411)	(94)	—	—	—	—	—	—	(37,419)	(3,945)	(12,603)
Secured and unsecured obligations	—	—	—	(21,123)	(13,088)	(2,415)	(41,015)	(55,682)	(76,258)	(1,057)	(1,547)	(1,965)	—	—	—	—	—	—	(63,195)	(70,317)	(80,638)
Other	(8,000)	(26,442)	(47,722)	(47,138)	(25,611)	(18,869)	(2,700)	(20,539)	(9,116)	(2,756)	(2,896)	(10,030)	(6,328)	—	—	—	—	—	(66,922)	(75,488)	(85,737)
Income from indexation units	(164,888)	(85,734)	(83,759)	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	(164,888)	(85,734)	(83,759)
Foreign exchange profits (losses)	68,258	49,529	106,263	(21,411)	33,392	9,152	883	234	(128)	(1,812)	5,154	(1,430)	425	—	—	—	(2,705)	—	46,343	85,604	113,857
Positive	96,832	174,233	234,818	76,706	48,805	62,728	23,440	5,594	8,167	50,020	31,653	21,311	1,667	—	—	—	(30,010)	(1,208)	248,665	230,275	325,816
Negative	(28,574)	(124,704)	(128,555)	(98,117)	(15,413)	(53,576)	(22,557)	(5,360)	(8,295)	(51,832)	(26,499)	(22,741)	(1,242)	—	—	—	27,305	1,208	(202,322)	(144,671)	(211,959)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	982	2,630	790	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	982	2,630	790
Other gains (losses)	1,602	50	1,042	5	—	—	66	103	235	—	3,611	10	427	—	—	—	—	—	2,100	3,764	1,287
Gain (loss) from other investments	—	50	1,042	—	—	—	—	—	—	—	-	—	—	—	—	—	—	—	—	50	1,042
Gain (loss) from the sale of assets	1,602	—	—	5	—	—	66	103	235	—	3,611	10	427	—	—	—	—	—	2,100	3,714	245
Profit (loss) before taxes	(92,140)	62,889	230,533	365,476	278,402	307,597	675,115	536,449	555,672	249,351	216,597	248,319	127,929	—	—	—	(2,705)	—	1,325,731	1,091,632	1,342,121
Income tax expense (income)	2,238	(15,129)	(48,085)	(114,871)	(66,505)	(116,746)	(216,981)	(188,883)	(180,207)	(83,976)	(56,056)	(74,300)	(32,621)	—	—	—	—	—	(446,211)	(326,573)	(419,338)
Profit (loss) from continuing operations	(89,902)	47,760	182,448	250,605	211,897	190,851	458,134	347,566	375,465	165,375	160,541	174,019	95,308	—	—	—	(2,705)	—	879,520	765,059	922,783
PROFIT (LOSS)	(89,902)	47,760	182,448	250,605	211,897	190,851	458,134	347,566	375,465	165,375	160,541	174,019	95,308	—	—	—	(2,705)	—	879,520	765,059	922,783
Country	Argentina			Brazil			Colombia			Peru			Central America			Eliminations			Total
STATEMENT OF CASH FLOWS	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$	12-31-2021 ThUS$	12-31-2020 ThUS$	12-31-2019 ThUS$
Net cash flows from (used in) operating activities	142,938	125,114	128,806	741,313	193,848	206,616	606,661	549,006	509,622	231,550	242,006	207,268	122,998	—	—	—	11	—	1,845,460	1,109,985	1,052,312
Net cash flows from (used in) investing activities	(66,607)	(59,107)	6,478	(882,706)	(9,470)	34,463	(262,588)	(54,430)	(85,078)	(61,467)	(41,680)	(40,386)	1,168	—	—	—	—	—	(1,272,200)	(164,687)	(84,523)
Net cash flows from (used in) financing activities	(96,806)	(54,520)	(115,161)	237,780	(162,012)	(221,809)	(516,366)	(353,785)	(545,075)	(277,911)	(227,426)	(157,902)	(85,426)	—	—	—	—	—	(738,729)	(797,743)	(1,039,947)

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-158

b)  Distribution

Line of business	Argentina		Brazil		Colombia		Peru		Eliminations		Total
Country	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
ASSETS	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT ASSETS	272,122	274,170	4,033,868	3,356,268	420,426	499,983	208,451	191,178	(49)	(48)	4,934,818	4,321,551
Cash and cash equivalents	6,404	8,016	310,415	557,280	92,356	141,721	57,197	41,228	—	—	466,372	748,245
Other current financial assets	22,482	23,383	53,501	128,089	1,684	274	43	—	—	—	77,710	151,746
Other current non-financial assets	17,087	29,464	609,241	374,088	9,295	18,191	5,132	9,057	—	—	640,755	430,800
Trade and other current receivables	213,415	199,667	2,642,513	1,954,523	247,884	260,485	112,269	109,912	45	53	3,216,126	2,524,640
Current accounts receivable from related parties	410	364	11,118	8,480	15,407	6,396	3,233	4,550	(94)	(101)	30,074	19,689
Inventories	12,324	13,276	333,214	272,167	53,280	72,916	30,577	26,431	—	—	429,395	384,790
Current tax assets	—	—	73,866	61,641	—	—	—	—	—	—	73,866	61,641
Non-current assets or disposal groups held-for-sale or held for distribution to owners	—	—	—	—	520	—	—	—	—	—	520	—
NON-CURRENT ASSETS	1,887,183	1,442,359	11,210,471	10,141,977	1,811,019	1,973,507	1,237,600	1,263,497	—	—	16,146,273	14,821,340
Other non-current financial assets	5	6	2,904,813	2,497,727	6,599	2	12	—	—	—	2,911,429	2,497,735
Other non-current non-financial assets	49	60	2,993,253	2,259,476	19,717	24,651	—	—	—	—	3,013,019	2,284,187
Trade and other non-current receivables	377	460	450,387	267,871	16,252	29,541	—	—	—	—	467,016	297,872
Non-current accounts receivable from related parties	26	32	—	—	—	—	—	—	—	—	26	32
Investments accounted for using the equity method	135	133	—	—	13,613	1,463	—	—	—	—	13,748	1,596
Intangible assets other than goodwill	73,985	50,067	3,978,918	4,174,705	100,569	103,745	52,179	42,359	—	—	4,205,651	4,370,876
Property, plant and equipment	1,812,557	1,391,477	28,059	32,860	1,632,486	1,785,402	1,153,472	1,186,821	—	—	4,626,574	4,396,560
Investment properties	—	—	6,272	7,942	—	—	—	—	—	—	6,272	7,942
Right-of-use asset	49	124	62,826	42,236	17,944	17,503	31,937	34,317	—	—	112,756	94,180
Deferred tax assets	—	—	785,943	859,160	3,839	11,200	—	—	—	—	789,782	870,360
TOTAL ASSETS	2,159,305	1,716,529	15,244,339	13,498,245	2,231,445	2,473,490	1,446,051	1,454,675	(49)	(48)	21,081,091	19,142,891
Line of business
Country	Argentina		Brazil		Colombia		Peru		Eliminations		Total
	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020	12-31-2021	12-31-2020
LIABILITIES AND EQUITY	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT LIABILITIES	902,066	591,523	4,474,546	3,697,032	550,502	640,775	315,498	249,069	(49)	(48)	6,242,563	5,178,351
Other current financial liabilities	—	—	463,072	775,450	220,389	190,925	69,837	53,750	—	—	753,298	1,020,125
Current lease liability	14	78	17,378	15,396	3,281	2,999	16,122	11,280	—	—	36,795	29,753
Trade and other current payables	797,949	467,412	2,538,667	2,159,212	264,665	338,490	166,340	116,577	—	2	3,767,621	3,081,693
Current accounts payable to related parties	42,444	69,660	1,249,196	513,115	15,602	32,604	35,669	35,692	(49)	(50)	1,342,862	651,021
Other current provisions	43,269	43,785	75,926	77,846	10,715	11,080	5,008	8,356	—	—	134,918	141,067
Current tax liabilities	—	-	—	26,914	16,094	40,226	6,591	2,239	—	—	22,685	69,379
Other current non-financial liabilities	18,390	10,588	130,307	129,099	19,756	24,451	15,931	21,175	—	—	184,384	185,313
NON-CURRENT LIABILITIES	558,266	415,192	7,273,663	6,033,093	887,339	840,051	435,640	471,377	—	—	9,154,908	7,759,713
Other non-current financial liabilities	—	—	1,608,594	1,412,245	794,478	708,607	379,487	397,449	—	—	2,782,559	2,518,301
Non-current lease liability	24	45	49,844	35,221	15,578	15,124	16,786	28,492	—	—	82,232	78,882
Trade and other non-current payables	53,914	86,559	2,623,702	1,961,838	231	372	591	729	—	—	2,678,438	2,049,498
Non-current accounts payable to related parties	40,821	50,566	958,052	394,384	—	—	—	—	—	—	998,873	444,950
Other long-term provisions	19,063	19,698	676,518	712,820	9,379	16,537	415	459	—	—	705,375	749,514
Deferred tax liabilities	405,082	233,966	4,684	10,243	—	—	33,976	38,188	—	—	443,742	282,397
Non-current provisions for employee benefits	13,197	10,730	1,311,655	1,476,884	67,673	96,591	3,031	4,299	—	—	1,395,556	1,588,504
Other non-current non-financial liabilities	26,165	13,628	40,614	29,458	—	2,820	1,354	1,761	—	—	68,133	47,667
EQUITY	698,973	709,814	3,496,130	3,768,120	793,604	992,664	694,913	734,229	—	—	5,683,620	6,204,827
Equity attributable to shareholders of Enel Américas	698,973	709,814	3,496,130	3,768,120	793,604	992,664	694,913	734,229	—	—	5,683,620	6,204,827
Share and paid-in capital	652,952	528,339	2,182,599	2,222,793	3,314	3,941	133,152	147,019	—	—	2,972,017	2,902,092
Retained earnings (losses)	(262,208)	(67,928)	(758,693)	(882,158)	248,707	346,671	501,709	520,910	—	—	(270,485)	(82,505)
Issuance premium	—	—	—	—	46,819	55,685	—	—	—	—	46,819	55,685
Other reserves	308,229	249,403	2,072,224	2,427,485	494,764	586,367	60,052	66,300	—	—	2,935,269	3,329,555
TOTAL LIABILITIES AND EQUITY	2,159,305	1,716,529	15,244,339	13,498,245	2,231,445	2,473,490	1,446,051	1,454,675	(49)	(48)	21,081,091	19,142,891

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-159

Line of business	Argentina			Brazil			Colombia			Peru			Eliminations			Total
Country STATEMENTS OF PROIT (LOSS)	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
REVENUE AND OTHER OPERATING INCOME	793,771	801,228	1,346,888	8,761,513	6,834,057	8,227,064	1,706,530	1,546,964	1,665,317	895,367	886,663	950,349	(32)	(27)	(24)	12,157,149	10,068,885	12,189,594
Revenues	779,524	772,583	1,066,437	7,291,539	5,855,047	7,246,928	1,685,480	1,529,090	1,646,864	890,752	882,564	945,595	—	—	—	10,647,295	9,039,284	10,905,824
Energy sales	737,859	737,983	1,021,696	6,522,617	5,168,342	6,441,861	859,847	760,540	850,524	841,017	844,342	903,828	—	—	—	8,961,340	7,511,207	9,217,909
Other sales	2,689	1,695	2,771	—	698	3,755	1,906	2,011	2,257	1,134	817	1,022	—	—	—	5,729	5,221	9,805
Other services rendered	38,976	32,905	41,970	768,922	686,007	801,312	823,727	766,539	794,083	48,601	37,405	40,745	—	—	—	1,680,226	1,522,856	1,678,110
Other income	14,247	28,645	280,451	1,469,974	979,010	980,136	21,050	17,874	18,453	4,615	4,099	4,754	(32)	(27)	(24)	1,509,854	1,029,601	1,283,770
RAW MATERIALS AND CONSUMABLES USED	(528,448)	(530,338)	(773,693)	(6,573,470)	(4,937,646)	(5,820,384)	(1,011,914)	(886,155)	(962,174)	(604,987)	(599,116)	(619,181)	—	—	—	(8,718,819)	(6,953,255)	(8,175,432)
Energy purchases	(490,205)	(489,984)	(714,844)	(4,722,860)	(3,451,265)	(4,310,694)	(749,941)	(646,721)	(717,608)	(561,256)	(561,076)	(580,690)	—	—	—	(6,524,262)	(5,149,046)	(6,323,836)
Fuel consumption	—	—	—	16	—	—	—	—	—	—	—	—	—	—	—	16	—	—
Transportation expenses	(14,438)	(17,806)	(16,990)	(593,753)	(658,797)	(720,945)	(174,438)	(162,393)	(165,554)	—	—	—	—	—	—	(782,629)	(838,996)	(903,489)
Other miscellaneous supplies and services	(23,805)	(22,548)	(41,859)	(1,256,873)	(827,584)	(788,745)	(87,535)	(77,041)	(79,012)	(43,731)	(38,040)	(38,491)	—	—	—	(1,411,944)	(965,213)	(948,107)
CONTRIBUTION MARGIN	265,323	270,890	573,195	2,188,043	1,896,411	2,406,680	694,616	660,809	703,143	290,380	287,547	331,168	(32)	(27)	(24)	3,438,330	3,115,630	4,014,162
Other work performed by the entity and capitalized	47,471	30,921	43,311	103,072	76,469	89,154	28,747	26,439	29,171	13,103	9,317	9,843	—	—	—	192,393	143,146	171,479
Employee benefits expense	(154,220)	(123,792)	(162,137)	(302,308)	(207,724)	(401,264)	(66,732)	(76,778)	(71,028)	(35,861)	(33,923)	(36,596)	—	—	—	(559,121)	(442,217)	(671,025)
Other expenses	(135,942)	(128,108)	(147,303)	(556,744)	(579,070)	(638,654)	(102,054)	(103,675)	(104,774)	(48,628)	(49,043)	(46,943)	32	27	24	(843,336)	(859,869)	(937,650)
GROSS OPERATING RESULT	22,632	49,911	307,066	1,432,063	1,186,086	1,455,916	554,577	506,795	556,512	218,994	213,898	257,472	—	—	—	2,228,266	1,956,690	2,576,966
Depreciation and amortization expense	(82,711)	(73,850)	(53,534)	(370,763)	(366,439)	(451,835)	(123,631)	(115,540)	(121,669)	(58,446)	(58,395)	(56,630)	—	—	—	(635,551)	(614,224)	(683,668)
Gains (losses) for impairment in accordance with IFRS 9	(8,551)	(44,338)	(42,501)	(307,815)	(167,035)	(225,053)	(12,807)	(16,127)	(7,272)	(6,383)	(14,040)	(4,408)	—	—	—	(335,556)	(241,540)	(279,234)
OPERATING INCOME	(68,630)	(68,277)	211,031	753,485	652,612	779,028	418,139	375,128	431,004	154,165	141,463	196,434	—	—	—	1,257,159	1,100,926	1,617,497
FINANCIAL RESULT	28,590	22,606	54,470	(369,355)	(267,371)	(308,117)	(54,585)	(49,171)	(58,397)	(21,605)	(25,042)	(22,938)	14	-	-	(416,941)	(318,978)	(334,982)
Financial income	19,930	10,657	22,964	164,114	100,950	179,304	10,984	8,571	5,668	4,373	3,771	4,439	—	—	—	199,401	123,949	212,375
Cash and cash equivalents	12,274	4,422	1,908	5,167	5,954	19,928	1,993	3,894	3,859	229	417	677	—	—	—	19,663	14,687	26,372
Other financial income	7,656	6,235	21,056	158,947	94,996	159,376	8,991	4,677	1,809	4,144	3,354	3,762	—	—	—	179,738	109,262	186,003
Financial costs	(262,785)	(148,619)	(168,782)	(531,140)	(366,558)	(484,231)	(61,476)	(56,225)	(64,047)	(22,340)	(26,894)	(28,342)	—	—	—	(877,741)	(598,296)	(745,402)
Bank borrowings	(405)	(379)	(3,957)	(72,414)	(44,964)	(78,675)	(9,528)	(8,732)	(8,375)	(4,228)	(2,601)	(1,204)	—	—	—	(86,575)	(56,676)	(92,211)
Secured and unsecured obligations	—	(1)	—	(77,476)	(54,629)	(110,355)	(40,559)	(35,496)	(40,051)	(18,972)	(23,379)	(25,090)	—	—	—	(137,007)	(113,505)	(175,496)
Other	(262,380)	(148,239)	(164,825)	(381,250)	(266,965)	(295,201)	(11,389)	(11,997)	(15,621)	860	(914)	(2,048)	—	—	—	(654,159)	(428,115)	(477,695)
Income from indexation units	279,374	161,586	206,845	—	—	—	—	—	—	—	—	—	—	—	—	279,374	161,586	206,845
Foreign exchange profits (losses)	(7,929)	(1,018)	(6,557)	(2,329)	(1,763)	(3,190)	(4,093)	(1,517)	(18)	(3,638)	(1,919)	965	14	—	—	(17,975)	(6,217)	(8,800)
Positive	—	1,777	86	323,815	173,425	126,129	4,218	5,834	8,389	9,328	3,726	2,217	5	(2)	(2)	337,366	184,760	136,819
Negative	(7,929)	(2,795)	(6,643)	(326,144)	(175,188)	(129,319)	(8,311)	(7,351)	(8,407)	(12,966)	(5,645)	(1,252)	9	2	2	(355,341)	(190,977)	(145,619)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	32	28	20	—	—	—	—	—	—	—	—	—	—	—	—	32	28	20
Other gains (losses)	—	7	39	519	870	2,143	573	21	73	26	5	10,654	—	—	—	1,118	903	12,909
Gain (loss) from other investments	—	—	—	543	—	—	—	—	6	—	—	—	—	—	—	543	—	6
Gain (loss) from the sale of assets	—	7	39	(24)	870	2,143	573	21	67	26	5	10,654	—	—	—	575	903	12,903
Profit (loss) before taxes	(40,008)	(45,636)	265,560	384,649	386,111	473,054	364,127	325,978	372,680	132,586	116,426	184,150	14	—	—	841,368	782,879	1,295,444
Income tax expense (income)	(138,481)	(22,866)	(76,548)	(102,921)	(118,872)	414,913	(107,270)	(97,881)	(122,066)	(47,413)	(38,488)	(55,649)	—	—	—	(396,085)	(278,107)	160,650
Profit (loss) from continuing operations	(178,489)	(68,502)	189,012	281,728	267,239	887,967	256,857	228,097	250,614	85,173	77,938	128,501	14	—	—	445,283	504,772	1,456,094
PROFIT (LOSS)	(178,489)	(68,502)	189,012	281,728	267,239	887,967	256,857	228,097	250,614	85,173	77,938	128,501	14	—	—	445,283	504,772	1,456,094
Line of Business	Argentina			Brazil			Colombia			Peru			Eliminations			Total
STATEMENT OF CASH FLOWS	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019	12-31-2021	12-31-2020	12-31-2019
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Net cash flows from (used in) operating activities	266,871	159,556	116,487	(53,565)	797,144	877,694	421,301	391,312	357,362	221,034	100,855	251,699	—	—	—	855,641	1,448,867	1,603,242
Net cash flows from (used in) investing activities	(187,632)	(115,347)	(184,578)	(1,043,563)	(740,848)	(818,838)	(326,150)	(381,939)	(303,833)	(153,866)	(126,493)	(163,888)	—	—	—	(1,711,211)	(1,364,627)	(1,471,137)
Net cash flows from (used in) financing activities	(76,665)	(54,133)	75,332	878,164	56,395	84,704	(125,249)	22,061	(158,135)	(48,896)	16,185	(66,594)	—	—	—	627,354	40,508	(64,693)

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

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34. GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS

34.1  Direct guarantees

				Assets Committed
	Debtor					Carrying	Outstanding balance as of
Creditor of Guarantee	Company	Relationship	Type of Guarantee	Type	Currency	Amount	Currency	12-31-2021	12-31-2020
Mitsubishi Corporation	Enel Generación Costanera S.A.	Creditor	Pledge	Combined cycle	US$	30,341	US$	41,953	46,802
BNDES	Enel Distribución Rio S.A.	Creditor	Pledge on collection and others	Collections	US$	4,603	US$	2,099	3,845
Miscellaneous creditors	Enel Distribución Ceará S.A.	Creditor	Pledge on collection and others	Collections	US$	11,823	US$	59,626	74,198
Banco Bradesco	Enel Distribución Goiás S.A.	Creditor	Pledge on collection and others	Collections	US$	19,316	US$	26,096	43,802
Fundação Cesp	Enel Distribuicao Sao Paulo S.A.	Creditor	Pledge on collection and others	Down Payment	US$	—	US$	—	816,798
Miscellaneous creditors	Enel Green Power Brasil	Creditor	Various	Escrow Account	US$	501,277	US$	321,352	—
Miscellaneous creditors	Enel Generación Piura S.A.	Creditor	Mortgage	Fixed Assets	US$	20,065	US$	8,638	16,933
Miscellaneous creditors	Enel Distribución Perú S.A.	Creditor	Mortgage	Fixed Assets	US$	32,713	US$	16,520	24,065
Banco Continental SA	Enel Generación Perú S.A.	Creditor	Mortgage	Fixed Assets	US$	2,198	US$	2,221	7,129

As of December 31, 2021 and 2020, the carrying amount of property, plant and equipment pledged as security for liabilities amounted to ThUS$ 85,317 and ThUS$ 104,577, respectively (see Note 16.c.ii).

As of December 31, 2021 and 2020, the Company had future energy purchase commitments amounting to ThUS$ 68,628,702 and ThUS$ 71,322,737, respectively.

34.2  Indirect guarantees

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				Debtor			Outstanding balance as of
Type	Contract Name	Ending Date	Creditor of Guarantee	Company	Relationship	Type of Guarantee	Currency	12-31-2021		12-31-2020
Joint & Several	Bono H	October 2028	Bondholders Enel Generación Chile Bonds Program (formerly Endesa Chile)	Enel Generación Chile	Divided companies of the original debtor, Endesa Chile (joint debtor Endesa Américas and post-merger Enel Américas) *	Joint co-debtor	US$	55,893	���	70,897
Joint & Several	Bono M	December 2029	Bondholders Enel Generación Chile Bonds Program (formerly Endesa Chile)	Enel Generación Chile	Divided companies of the original debtor, Endesa Chile (joint debtor Endesa Américas and post-merger Enel Américas) *	Joint co-debtor	US$	267,394		335,240
Bank Loan	BNP PARIBAS 4131	February 2022	BNP PARIBAS	Enel Distribución Río	Enel Brasil	Guarantor	US$	74,137		79,612
Bank Loan	BNP PARIBAS 4131 II	December 2022	BNP PARIBAS	Enel Distribución Río	Enel Brasil	Guarantor	US$	39,458		39,230
Bank Loan	CITIBANK 4131 II	March 2021	CITIBANK	Enel Distribución Río	Enel Brasil	Guarantor	US$	—		96,461
Bank Loan	ITAÚ 4131	July 2021	ITAÚ	Enel Distribución Río	Enel Brasil	Guarantor	US$	—		77,194
Bank Loan	SCOTIABANK 4131 III	February 2025	SCOTIABANK	Enel Distribución Río	Enel Brasil	Guarantor	US$	37,115		—
Bank Loan	SCOTIABANK 4131 IV	February 2025	SCOTIABANK	Enel Distribución Río	Enel Brasil	Guarantor	US$	22,249		—
Bank Loan	BNDES FINAME GIRO	May 2023	BNDES	Enel Distribución Goiás S.A.	Enel Brasil	Guarantor	US$	9,927		18,170
Bank Loan	SCOTIABANK 4131 CELG	August 2022	SCOTIABANK	Enel Distribución Goiás S.A.	Enel Brasil	Guarantor	US$	49,336		48,870
Bank Loan	BNP PARIBAS 4131 II	March 2021	BNP PARIBAS- CREDIT AGREEMENT	Enel Distribución Goias (former-CELG)	Enel Brasil	Guarantor	US$	—		33,108
Bonds	DEBÊNTURES - 23ª EMISSÃO – 1st series	September 2021	DEBENTURES	Enel Distribución Sao Paulo	Enel Brasil	Guarantor	US$	—		136,305
Bonds	DEBÊNTURES - 23ª EMISSÃO – 2nd series	September 2023	DEBENTURES	Enel Distribución Sao Paulo	Enel Brasil	Guarantor	US$	256,055		270,297
Bank Loan	SCOTIABANK 4131	April 2023	SCOTIABANK	EGP Cachoeira Dourada	Enel Brasil	Guarantor	US$	31,363		—
Bank Loan	BNDES BOA VISTA B1, B2 e B3	December 2034	BNDES	EGP BOA VISTA	EGP BRASIL	Guarantor	US$	13,344		—
Bank Loan	SAN 4131 EGP- 1	August 2033	BANCO SANTANDER (BRASIL) S.A.	EGP Brasil	Enel SPA	Guarantor	US$	51,014		—
Bank Loan	CHINA 4131 EGP- 1	August 2033	BANK OF CHINA LTD - MILAN BRANCH	EGP Brasil	Enel SPA	Guarantor	US$	53,096		—
Bank Loan	SAN 4131 EGP- 2	August 2033	BANCO SANTANDER (BRASIL) S.A.	EGP Brasil	Enel SPA	Guarantor	US$	45,631		—
Bank Loan	CHINA 4131 EGP- 2	August 2033	BANK OF CHINA LTD - MILAN BRANCH	EGP Brasil	Enel SPA	Guarantor	US$	47,493		—
Bank Loan	BNDES DELFINA B A1, A2 e A3	September 2034	BNDES	EGP DELFINA B	EGP BRASIL	Guarantor	US$	13,865		—
Bank Loan	BNDES DELFINA C B1, B2 e B3	September 2034	BNDES	EGP DELFINA C	EGP BRASIL	Guarantor	US$	3,247		—
Bank Loan	BNDES DELFINA D A1, A2, A3, C1 e C2	September 2034	BNDES	EGP DELFINA D	EGP BRASIL	Guarantor	US$	13,888		—
Bank Loan	BNDES DELFINA E A1, A2, A3, D1 e D2	September 2034	BNDES	EGP DELFINA E	EGP BRASIL	Guarantor	US$	13,954		—
Bank Loan	CHINA 4131 ITUVERAVA N	December 2031	BANK OF CHINA	EGP ITUVERAVA NORTE	ENEL SPA	Guarantor	US$	12,448		—
Bank Loan	SAN 4131 ITUVERAVA N	December 2031	BANCO SANTANDER BRASIL	EGP ITUVERAVA NORTE	ENEL SPA	Guarantor	US$	11,960		—
Bank Loan	PROPARCO 4131 ITUVERAVA N	December 2031	PROPARCO	EGP ITUVERAVA NORTE	ENEL SPA	Guarantor	US$	26,951		—
Bank Loan	CHINA 4131 ITUVERAVA N	December 2031	BANK OF CHINA	EGP ITUVERAVA SUL	ENEL SPA	Guarantor	US$	18,673		—
Bank Loan	SAN 4131 ITUVERAVA N	December 2031	BANCO SANTANDER BRASIL	EGP ITUVERAVA SUL	ENEL SPA	Guarantor	US$	17,941		—
Bank Loan	PROPARCO 4131 ITUVERAVA N	June 2032	PROPARCO	EGP ITUVERAVA SUL	ENEL SPA	Guarantor	US$	40,427		—
Bank Loan	CHINA 4131 ITUVERAVA N	December 2031	BANK OF CHINA	EGP ITUVERAVA	ENEL SPA	Guarantor	US$	12,448		—
Bank Loan	SAN 4131 ITUVERAVA N	December 2031	BANCO SANTANDER BRASIL	EGP ITUVERAVA	ENEL SPA	Guarantor	US$	11,960		—
Bank Loan	PROPARCO 4131 ITUVERAVA N	June 2032	PROPARCO	EGP ITUVERAVA	ENEL SPA	Guarantor	US$	26,951		—
Bank Loan	BNDES SÂO ABRAÂO A1, A2 e A3	December 2034	BNDES	EGP SAO ABRAAO	EGP BRASIL	Guarantor	US$	13,377		—
Bank Loan	BEI 1 PERGEIBPTMO1	December 2032	European Investment Bank	EGP Perú	Enel SPA	Guarantor	US$	88,970		—
Bank Loan	BEI 1 PERGEIBPTMO2	July 2033	European Investment Bank	EGP Perú	Enel SPA	Guarantor	US$	48,469		—
						Total		1,429,034		1,205,384

(*) Upon the demerger of the original issuer into Endesa Chile (currently Enel Generación Chile S.A.) and Endesa Américas, and in accordance with the bond indenture, all entities arising from the demerger are liable for the debt, regardless that the payment obligation remains in Enel Generación Chile S.A. After the merger carried out in 2016, the Company became liable for the obligations of Endesa Américas.

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34.3 Litigation and Arbitration Proceedings

As of the date of these consolidated financial statements, the most relevant litigation and arbitration proceedings of Enel Américas and its subsidiaries are the following:

a) Enel Américas’pending lawsuits:

The Chilean Tax Authority (SII) carried out a regular audit for the 2012 business year (Tax Year 2013). On September 4, 2015, it provided notice of a tax assessment for the additional tax due, based on article 74 of the Income Tax Act, justifying its position on the ground that a modification of the Taxable Profits Fund (Fondo Utilidad Tributaria or FUT) allegedly entailed a modification of the base for the additional tax. The company responded that the SII had accepted the income rectification and the income tax return it had filed, thereby accepting the declared tax amounts. On December 23, 2015, Enel Américas (formerly named Enersis S.A.) filed a tax claim before the Tax and Customs Courts (TTA), claiming that the tax obligation had been fully complied with, since the additional tax had been paid provisionally on a monthly basis, and the tax obligation had been fully settled and resolved when the income rectification was made on May 8, 2014, which included the rectification of the FUT amount. Following an unfavorable ruling by the TTA and several appeals, on August 3, 2021, the Supreme Court (the court of first instance) rendered an unfavorable ruling was rendered against Enel Américas. On August 5, 2021, a letter of notification of the judgment was sent. On August 20, 2021, Enel Américas filed an appeal. On September 8, 2021 the Supreme Court admitted the appeal for processing. On September 30, 2021, Enel Américas became a party to the appeal before the Court of Appeals and requested the suspension of the tax collection. On November 23, 2021, the suspension of the tax collection was granted for the maximum legal term of 6 months. As of December 31, 2021, the amount involved in the lawsuit was ThCh$5,023,208 (ThUS$ 5,898).

b) Subsidiaries´pending lawsuits

Argentina

Edesur S.A.

1. On February 14, 2019, Edesur S.A. filed an administrative claim against the Argentine National Government for damages derived from the non-compliance of the works related to the "Renewal and Repowering Plan for Conventional Lines and Extension of Public Lighting" (Plan Más Cerca Eléctrico) that should have been paid by the Federal Authority and implemented by the local jurisdictions in which Edesur S.A. provides services. The financing of such partially performed and/or non-performed works implied a tariff revenue replacement prior to the entry into force of the Comprehensive Tariff Review on February 1, 2017. The damages are related to the costs of the execution of the works and the claim against the penalties for poor service quality that Edesur S.A. had to face in the areas where the aforementioned electric infrastructure plan was not properly carried out. The claim continues to be analyzed by the Administration. To date, no ruling has been issued by the National Government on the merits of the claim. As of December 31, 2021, the amount involved in the lawsuit was ThARS$3,100,000 (ThUS$30,189).

Brazil:

Enel Distribución Ceará (Companhia Energética do Ceará S.A. or “Coelce”)

2. The Public Prosecutor’s Office filed a public civil action against Enel Distribución Ceará, Enel Generación Fortaleza and the Brazilian Electricity Regulatory Agency (ANEEL) alleging that a) the electric power purchase agreement (PPA) signed between Enel Distribución Ceará and Enel Generación Fortaleza (companies of the same economic group) was illegal, the price of the contracted energy being very high, with excessive costs in the final consumers’ tariff and b) the tariff review conducted by ANEEL since 2002 was wrong, since it took into consideration inaccurate data in the process. The Public Prosecutor’s Office is seeking the exclusion of these components from the tariff and the return of the sums unduly collected by the concessionaire. The PPA’s legality was confirmed at the judicial courts of first and second instances, but the tariff review process (item b) was held

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to be erroneous at these rulings. On December 8, 2020, a special appeal filed by Enel Distribución Ceará, was summarily dismissed. Enel Distribución Ceará filed motions for clarification of the decision, and to date they remain pending. The amount involved in this lawsuit cannot be estimated.

3. The Public Prosecutor’s Office for Labor Matters filed a public civil action against Enel Distribución Ceará in the Brazilian Superior Labor Court alleging that the company was hiring third parties for the provision of final services (“outsourcing”), which was contrary to Brazilian law (Ruling 331 of the Brazilian Superior Labor Court), which allegedly only allows the provision of non-essential services by third parties. The Superior Labor Court issued a ruling declaring the outsourcing illegal. An appeal filed by Enel Distribución Ceará is currently pending before the Collective Bargaining Section (the reviewing section of the Superior Labor Court). Enel Distribución Ceará submitted a complaint to the Federal Supreme Court due to procedural irregularities (under the plenary reservation clause of the Federal Constitution), which was accepted by the court. The Federal Supreme Court has vacated the ruling of the Superior Labor Court that prohibited the outsourcing of activities by Enel Distribución Ceará), and the lawsuit will return to the Superior Labor Court for the trial of Enel Distribución Ceará’s appeal. The amount involved in this lawsuit cannot be estimated.

4. Several rural electricity cooperatives have filed lawsuits to review the lease fee for the energy supply network in the rural area of the State of Ceará allegedly owned by them. Although Enel Distribución Ceará regularly pays the network lease fee to 13 rural electricity companies, a discussion on the ownership of these assets is pending decision, since they allegedly have already been directly replaced by Enel Distribución Ceará throughout the more than 30 years of these lease contracts.

• Cooperativa de Eletrificação Rural do Vale do Acaraú (COPERVA) versus Enel Distribución Ceará (collection action): There is no preliminary injunction and there is still no first instance decision from the Ceará state court; and

• Cooperativa de Eletrificação Rural do Vale do Acaraú (COPERVA) versus Enel Distribución Ceará (action to review the sums charged by Enel Distribución Ceará): The Court of Justice (court of second instance) ruled in favor of Enel Distribución Ceará, rejecting the request for lease review, and a special appeal was filed by COPERVA and is currently pending before the Superior Court of Justice (court of third instance). On November 5, 2018, the Superior Court of Justice rendered a single-judge decision on a special appeal filed by COPERVA and vacated the ruling on the clarification attachments requested. In summary, the ruling judge held that the decision by the Court of Justice failed to provide satisfactory clarification on the facts claimed in COPERVA’s clarification attachment petitions and declared a retrial to hear this appeal. Enel Distribución Ceará filed an appeal against this decision on December 3, 2018 with the Superior Court of Justice requesting that an en-banc decision be rendered (since the ruling had been issued by a single judge), which is pending. As of December 31, 2021 the amount involved in the two COPERVA lawsuits was ThBRL 374,370 (ThUS$ 67,211).

• Cooperativa de Energia, Telefonia e Desenvolvimento Rural (COERCE) versus Enel Distribución Ceará: There is no preliminary injunction and there is still no first instance decision from the Ceará state court. As of December 31, 2021, the amount involved in this lawsuit was ThBRL 224,580 (ThUS$ 40,319).

• Cooperativa de Energia, Telefonia e Desenvolvimento Rural (COPERCA) versus Enel Distribución Ceará: On June 13, 2019, the judge in the Ceará state court issued a decision ordering the transfer of the claim to the federal courts, considering Brazilian Electricity Regulatory Agency’s (ANEEL) interest in the claim, which transfer occurred on November 28, 2019. On April 24, 2020, the federal court judge issued a decision excluding ANEEL, as it would not be an interested party in the lawsuit and the lawsuit returned to the Ceará state court on June 1, 2020. On August 8, 2021, a decision was issued for the parties to indicate the evidence they still wish to produce in the lawsuit. As of December 31, 2021, the amount involved in this lawsuit was ThBRL 195,080 (ThUS$ 35,023).

5. Fiação Nordeste do Brasil S/A (FINOBRASA), which has now been succeeded by Vicunha, filed a lawsuit against Enel Distribución Ceará claiming that the readjustment of electricity tariffs made through Decrees Nos. 38 and 45 (DNAEE) in February 1986 are illegal. FINOBRASA is seeking the declaration of illegality of the

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readjustments and an order that its effects be reflected in all subsequent readjustments and the return of amounts inappropriately collected. The Court of Justice (court of second instance) rendered a decision declaring the readjustment made in 1986 illegal, but rejected the reflection of its effects in the subsequent readjustments (cascade effect). A special appeal filed by FINOBRASA is currently pending before the Superior Court of Justice (court of third instance). As of December 31, 2021, the amount involved in the lawsuit was ThBRL 139,270 (ThUS$ 25,003).

6. Endicon Engenharia de Instalações e Construções S/A has filed a lawsuit for material and reputational damages against Enel Distribución Rio and Enel Distribución Ceará for alleged contractual breaches. On December 2, 2021, the defendants filed their defenses. As of December 31, 2021, the amount involved in the lawsuit in relation to the contracts of Enel Distribución Ceará was ThBRL 215,408 (ThUS$38,673).

7. Due to the differences that arose in the interpretation of the ICMS tax laws, Enel Distribución Ceará has a total of 10 lawsuits covering the years 2005 to 2014 brought by the Brazilian Tax Authority. Enel Distribución Ceará must apply the “pro rata” rule to calculate the amount of the ICMS deductible with respect to the total ICMS included in energy purchases. The rule stipulates that the percentage represented by the income taxed by ICMS over the total income (whether or not subject to ICMS) is deductible. For the purposes of its inclusion in the pro rata denominator, Enel Distribución Ceará’s position is that the untaxed income is the result of applying the energy’s final selling price (the price after deducting the State of Ceará subsidy for low-income consumers) and the Brazilian Tax Authority maintains that the untaxed income is the price of the normal tariff (without deducting the State of Ceará subsidy for low-income consumers). The company continues its defense in the administrative and judicial proceedings. As of December 31, 2021, the total amount involved in these lawsuits was estimated at ThBRL 250,000 (ThUS$ 44,883).

8. The State of Ceará issued assessments to Enel Distribución Ceará for 2003, and the period from 2004 to 2014, claiming that the ICMS for the acquisition of fixed assets had been incorrectly deducted. Enel Distribución Ceará filed its administrative defenses in all administrative proceedings and is awaiting final decisions. As of December 31, 2021, the total amount involved in these lawsuits was estimated at ThBRL 215,000 (ThUS$ 38,599).

9. The State of Ceará filed proceedings against Enel Distribución Ceará to demand ICMS on the subsidy paid by the Federal Government to Enel Distribución Ceará (and all distributors in Brazil) for regulatory discounts applied to certain consumers, such as rural producers and others for 2015 and 2016. For the 2015 proceedings, Enel Distribución Ceará filed an appeal with the second administrative instance, after an unfavorable decision in the first administrative instance, and for the 2016 proceedings, the decision of the first administrative instance is pending. As of December 31, 2021, the total amount involved in these proceedings was estimated at ThBRL 129,000 (ThUS$23,159).

Enel Distribución Goiás S.A. (formerly CELG Distribuição S.A.)

10. Several municipalities have filed lawsuits against Enel Distribución Goiás claiming that an agreement made with the State of Goiás and the Goiana Association of Municipalities (AGM) which provides for the direct transfer to Enel Distribución Goiás of ICMS amounts owed to the municipalities by the State of Goiás is illegal. The amounts transferred were used to pay late electric bills. Enel Distribución Goiás responded that despite the potential illegality of the agreement, the amounts were effectively due and it would not be possible to return them to the municipalities. The Court of Justice of Goiás is divided and there is still no decision, which will only be rendered by the Superior Court of Justice (the court of third instance).

- Municipality of Aparecida de Goiânia versus Enel Distribución Goiás. As of December 31, 2021, the amount involved in the claim was ThBRL 715,977 (ThUS$ 128,540).

- Municipality of Quirinópolis versus Enel Distribución Goiás. As of December 31, 2021, the amount involved in the claim was ThBRL 387,930 (ThUS$ 69,646).

- Municipality of Anápolis versus Enel Distribución Goiás. As of December 31, 2021, the amount involved in the claim was ThBRL 368,690 (ThUS$ 66,192).

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- Municipality of Cezarina versus Enel Distribución Goiás. As of December 31, 2021, the amount involved in the claim was ThBRL 162,490 (ThUS$ 29,172).

11. Enel Brasil S.A. and Enel Distribución Goiás filed a security order against the tax authority of the State of Goiás so that the process for restitution of the amounts paid by Enel Distribución Goiás in relation to the claims guaranteed by Laws Nos. 17,555 (reimbursement for FUNAC) and 19,473 (reimbursement for ICMS – IVA Tax Credits) continues normally. The judge previously rejected a request for an injunction. Enel Brasil and Enel Distribuci��n Goiás filed an appeal against the decision, which was accepted by the Court of Justice of the State of Goiás, suspending the application of the new law and upholding the validity of Laws Nos. 17,555 (FUNAC) and 19,473 (Tax Credits). The injunction was subsequently revoked by the Court, as the Court did not recognize the urgency that justified an injunctive measure. Enel Brasil S.A. and Enel Distribución Goiás have filed an appeal against the decision, arguing that the right to the guaranty is legal and contractual, and the actions of the State of Goiás with the goal of suspending the integral application of the laws are clearly illegal. On June 14, 2021 a decision in the merits of the claims was rendered and an unconstitutionality motion was proposed, which by the procedural rules must be judged by a special part of the court. On November 9, 2021 a summary decision was rendered and dismissed the unconstitutionality motion. The claim returned for trial by the ordinary part of the court. There is no decision on the merits. The amount involved in the lawsuit is indeterminate.

12. Enel Brasil S.A. and Enel Distribución Goiás filed an ordinary action against the State of Goiás requesting that Law No. 20,648 and all its effects be suspended. In summary, Law No. 20,648 completely revoked Law No. 19,473 (Tax Credits), which grants Enel Distribución Goiás, as an alternative to cash payment, the right to offset payments made by the company for litigation whose events arose before 2015 by means of ICMS (IVA) tax credits. The judge rejected the injunction request. Enel Brasil S.A. and Enel Distribución Goiás have filed an appeal against the decision, arguing that the repeal of Law No. 19,473 (Tax Credits) is unconstitutional, since the tax incentive provided in the Law was established in full conformity with applicable legislation and was characterized as an acquired right, which is inviolable in accordance with Article XXXVI of the Brazilian Constitution.

In addition to characterizing the acquired right, article 178 of the Brazilian Tax Code establishes the impossibility of revocation of a tax incentive granted by certain conditions, an understanding confirmed by repeated statements of the Federal Supreme Court (STF Precedent 544). There has not been a decision in the first instance. The amount involved in the lawsuit is indeterminate.

13. The Public Prosecutor’s Office for Labor Matters filed a public civil action against Enel Distribución Goiás alleging that the company was hiring third parties for the provision of final services (“outsourcing”), contrary to Brazilian law (Ruling 331 of the Brazilian Superior Labor Court). In the court of first instance, the labor judge declared the sub-contracting legal. The Regional Labor Court accepted the appeal filed by the Public Prosecutor’s Office for Labor Matters, reversed the decision of the labor judge in the court of first instance and has declared the sub-contracting illegal. Enel Distribución Goiás filed an appeal with the Brazilian Superior Labor Court, which upheld the Regional Labor Court decision. The decision was suspended by the Federal Supreme Court until judgment of the constitutional complaint relating to the matter is decided by the Federal Supreme Court. The appeals by the Public Prosecutor’s Office for Labor Matters were dismissed and the decision was rendered final. The amount involved in the lawsuit is indeterminate.

14. A union representing 1,715 employees filed a lawsuit against Enel Distribución Goiás questioning the legal nature of the "food aid". The legal issue is the inclusion of this benefit in the compensation of the employees who received it before the company’s adhesion to the PAT (Food Program for Workers) in 2008. A judgment was issued ordering the company to pay the difference (integration of food aid to compensation of employees prior to May 7, 2008). Enel Distribución Goiás’ appeal was rejected by the Regional Labor Court of the 18th Region (Goiás). Enel Distribución Goiás filed an appeal with the Superior Labor Court, which was preliminarily rejected. Enel Distribución Goiás filed a clarification request against the decision, which the court has dismissed and the decision was rendered final. Enel Distribución Goiás filed a request to annul the court’s decision. In parallel, the union started to enforce the decision. As of December 31, 2021, the estimated amount involved in the lawsuit was ThBRL 231,650 (ThUS$ 41,588).

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15. Enel Distribución Goiás was audited by the Brazilian Tax Authority due to its position on the exclusion of ICMS amounts from the Social Contributions base (PIS/COFINS). The company excluded the ICMS before a final decision was made, and consequently the Brazilian Tax Authority issued four assessments against Enel Distribución Goiás, arguing that exclusion was not permitted. In an unrelated case with precedential value, the decision by the Superior Court acknowledged that ICMS should not be part of the PIS and COFINS tax base. In the specific case of Enel Distribución Goiás, the company learned in March 2021 about the final decision by the court on the right of Enel Distribución Goiás not to include the ICMS in the Social Contributions base. The company obtained a firm and definitive decision in an annulment action for the cancellation of two assessments collected in tax foreclosure. Because of that the Brazilian Tax Authority canceled a large part of the assessment, which was reduced from ThBRL 398,447 (ThUS$ 71,534) to ThBRL 12,943 (ThUS$ 2,324). The company will continue to challenge judicially the remaining assessments. The other assessments remain suspended. As of December 31, the total amount involved in these lawsuits (including the reduction) was ThBRL 240,000 (ThUS$ 43,088).

16. In March 2017, the Federal Supreme Court resolved a matter of general applicability, related to the calculation of PIS and COFINS taxes. The Federal Supreme Court confirmed the theory that the ICMS tax should not be part of the base for calculation of PIS and COFINS taxes; however, the Brazilian federal government filed an appeal, in order to determine the temporary effects and make some clarifications. On May 2021 the Federal Supreme Court ruled on the appeal and confirmed that the invoiced ICMS should be considered in these credits and not the ICMS paid. In addition, the Federal Supreme Court established that the effects will apply as of the March 2017 ruling, except for taxpayers who filed individual claims prior to that date.

Enel Brasil’s subsidiaries in Brazil that were affected by the Federal Supreme Court decision filed legal actions to this effect in the respective Federal Regional Courts. During 2019 and 2020, Enel Distribución São Paulo was notified, Enel Distribución Ceará was notified in 2019, and Enel Distribución Goiás was notified in March 2021, as well as Enel Distribución Rio in September 2021, regarding the final judgments issued by their respective Federal Regional Courts, recognizing their right to deduct the ICMS applied to their own operations from the base for calculation of PIS and COFINS taxes (for the periods between December 2003 and December 2014 for Enel Distribución São Paulo, May 2001 onwards for Enel Distribución Ceará, for Enel Distribución Goiás the action was filed in 2003 and December 2003 onwards for Enel Distribución Rio).

Considering various internal analyses and the advice of legal advisors, as well as the best available estimates, Enel Distribución São Paulo, Enel Distribución Ceará, Enel Distribución Goiás, and Enel Distribución Rio recognized assets amounting to ThBRL 5,931,750 (ThUS$ 1,064,948), ThBRL 1,045,643 (ThUS$187,727), ThBRL 2,973,397 (ThUS$533,824), and ThBRL 3,211,470 (ThUS$576,566), respectively, as of December 2021. As the overpayment of PIS and COFINS taxes was passed on to end customers at the time, simultaneously with the recognition of these taxes to be recovered, Enel Brasil’s subsidiaries have recognized a liability of a regulatory nature for the same amounts indicated above, net of any costs incurred or to be incurred by the companies in these legal proceedings. These liabilities represent the obligation to refund to the end customers the taxes that are recovered.

The Enel Américas Group will adopt tax credit recovery procedures in accordance with legal requirements. The transfer to end customers will depend on the effective use of the tax credit by the companies and will be carried out in accordance with the regulations of the Brazilian Electricity Regulatory Agency (ANEEL).

Enel Distribución Río (formerly Ampla Energia e Serviços S.A.)

17. Companhia Brasileira de Antibióticos (CIBRAN) filed a lawsuit against Enel Distribución Río seeking compensation for energy supply failures in the years 1987 to 1994. The courts have dismissed another lawsuit filed by CIBRAN for similar failures that occurred between 1995 and 1999.

The judge in the court of first instance, ruled in favor of CIBRAN, against which Enel Distribución Rio has filed an appeal. On November 6, 2019, the Court of Justice of the State of Rio de Janeiro (court of second instance) issued a decision accepting Enel Distribución Rio’s appeal and dismissing all of CIBRAN’s requests. CIBRAN

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filed several appeals to the Superior Court of Justice, the last one was dismissed on June 8, 2021. On June 22, 2021, CIBRAN filed a new appeal to the Superior Court of Justice, which to date is pending. As of December 31, 2021, the amount involved in the claim was ThBRL 612,100 (ThUS$ 109,892).

18. Indústria de Papel e Embalagens S.A. (CIBRAPEL) filed a lawsuit against Enel Distribución Rio seeking compensation due to energy supply failures. A final decision was rendered against Enel Distribución Río. The expert opinion fixed the compensation at ThBRL 21,500 (ThUS$ 3,860), but the amount has been challenged by Enel Distribución Río, and the appeal is pending resolution. As of December 31, 2021, the amount involved in the claim was ThBRL 256,600 (ThUS$ 46,068).

19. Endicon Engenharia de Instalações e Construções S/A filed a lawsuit for material and reputational damages against Enel Distribución Rio and Enel Distribución Ceará for alleged contractual breaches. On December 2, 2021, the two companies filed their defenses. As of December 31, 2021, the amount involved in the lawsuit in relation to the contracts of Enel Distribución Rio was ThBRL 152,864 (ThUS$27,444).

20. The Niterói Workers Union filed a labor claim against Enel Distribución Rio demanding the payment of a 26.05% wage differential from February 1989, by virtue of the Economic Plan instituted by Decree Law No. 2,335/87. The claim was adjudicated against Enel Distribución Rio in all of the preceding court instances, and became final. Currently, an action for rescission filed by Enel Distribución Rio is pending before the Superior Labor Court. In parallel, 887 former employees filed 543 lawsuits for enforcement of the judgment against Enel Distribución Rio. On December 31, 2021, the amount involved in the lawsuit was ThBRL 127,379 (ThUS$ 22,868).

21. The Brazilian Tax Authority served a notice of violation in 2003 against Enel Distribución Río to collect alleged COFINS tax deficiencies for the period from December 2001 until March 2002. After adverse rulings in the courts of first and second instance, Enel Distribución Río filed an extraordinary appeal with the Federal Supreme Court and received an unfavorable decision. Enel Distribución Río submitted a new appeal to the Federal Supreme Court. The appeal was decided against the company. Furthermore, in the view of the judge, the appeal filed was intended to cause a delay in the end of the litigation and, therefore, the court applied a penalty of 5% on the value of the tax deficiency. The company filed an appeal to void the fine applied and the decision reduced the penalty from 5% to 1% of the amount involved in June 2021. The litigation will be paid. On December 31, 2021, the debt and fine amount involved in the lawsuit was ThBRL 175,000 (ThUS$ 31,418).

22. In 2005, the Brazilian Tax Authority notified Enel Distribución Río on the non-applicability of the special tax treatment that had reduced to zero the withholding tax rate on interest paid abroad on the Fixed Rate Notes (FRN) issued by the company in 1998. Enel Distribución Río is still litigating this issue in the judicial court of the first instance. As of December 31, 2021, the total amount of this dispute is estimated at ThBRL 1,332,000 (ThUS$ 239,138).

23. The State of Río de Janeiro levied a tax assessment against Enel Distribución Río for the periods from 1996 to 1999 and from 2007 to 2017, since it believed that the ICMS recorded on the acquisition of fixed assets had been incorrectly deducted. Enel Distribución Río filed its administrative and judicial defenses in all proceedings. Part of the administrative proceedings was resolved in Enel Distribución Río’s favor and the remaining part was appealed and the judicial proceedings await final decisions. As of December 31, 2021, the total amount of this litigation is estimated at ThBRL 133,000 (ThUS$ 23,977).

Enel Distribución São Paulo (Eletropaulo)

24. Enel Distribución São Paulo filed an action seeking the annulment of Brazilian Electricity Regulatory Agency’s (ANEEL) administrative decision, which determined the retroactive exclusion of the tariffs applied by Enel Distribución São Paulo before the date of its third periodic review, with the refund of sums associated with a possibly non-existent network and rejected a subsidiary request (made by Enel Distribución São Paulo) for inclusion of other existing service assets (network), but not recorded in the company’s remuneration base. There

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is no first instance decision yet, and the lawsuit is in its initial phase. As of December 31, 2021, the amount involved in the lawsuit was ThBRL 1,288,000 (ThUS$ 231,239).

25. The São Paulo electric power industry workers’ union filed five class-actions seeking the payment of hazard allowance for all employees (except management positions) of Enel Distribución São Paulo located in the Barueri office until the decommissioning of the generating unit that was in the attic (below the heliport), during the period from February 2012 to February 2016, the time of the decommissioning of the generator unit and its installation outside the building. On July 11, 2019, a decision favorable to Enel Distribución São Paulo was issued. The union filed an appeal with the court, which was dismissed on August 13, 2020. As of December 31, 2021, the amount involved in the lawsuit was ThBRL 139,730 (ThUS$ 25,086).

26. The Federal Public Prosecutor’s Office filed a public civil action against Enel Distribución São Paulo and Brazilian Electricity Regulatory Agency (ANEEL) seeking to block the inclusion in consumers’ tariffs of amounts contracted with affiliated parties (AES Tietê, at that time) and the reimbursement of double the amounts already collected. The court ruled in Enel Distribución São Paulo’s favor, rejecting the actions, but the Federal Regional Court admitted the Federal Public Prosecutor’s Office’s appeal and overturned the decision. An Enel Distribución São Paulo appeal against the Federal Regional Court’s decision is currently pending in the Superior Court of Justice. The amount involved in the claim is indeterminate.

27. The Public Prosecutor’s Office for Labor Matters filed a public civil action against Enel Distribución São Paulo alleging that the company was hiring third parties for the provision of final services (“outsourcing”), which is contrary to Brazilian law (Ruling 331 of the Brazilian Superior Labor Court), which allegedly only allows the provision of non-essential services by third parties. On April 5, 2019, the judge issued a judgment rejecting (i) the request for a declaration of the existence of outsourcing fraud and (ii) a link between the employees of the suppliers with Enel Distribución São Paulo, nevertheless, the judgment has ordered Enel Distribución São Paulo to pay compensation for collective punitive damages in an amount of ThBRL 5,000 (ThUS$ 898), and to align remuneration between Enel Distribución São Paulo’s own employees and the suppliers’ employees, with a fine of ThBRL 1,000 (ThUS$179) for non-compliance. Enel Distribución São Paulo filed an appeal against the judgment with the Regional Labor Court. On February 11, 2021, the Regional Labor Court accepted the appeal and dismissed all claims. The amount involved in the claim is indeterminate.

28. Enel Distribución São Paulo filed a complaint requesting a declaration that the amounts of COFINS paid by the company were paid in accordance with the rules of the Amnesty Program of the Brazilian Federal Government (reduction of fines and interest) created in 1999. The complaint was filed by the company in September 1999. Following the decision in the court of second instance that decided partly in its favor regarding the principal amount, interest and fine, in April 2018, the company filed appeals with the Superior Court of Justice and the Federal Supreme Court which are currently pending. Of the total amount of ThBRL 818,000 (ThUS$ 146,858) ThBRL 163,000 (ThUS$ 29,264) comprise the attorneys’ fees (20%) paid by the Brazilian Tax Authority. The balance of ThBRL 654,000 (ThUS$ 117,415) is related to the capital (tax) paid with amnesty benefits. As of December 31, 2021, the amount of possible loss involved in the litigation is ThBRL 163,000 (ThUS$ 29,264).

29. In May 2008, the Brazilian Tax Authority filed a lawsuit against Enel Distribución São Paulo seeking payment of the PIS tax, corresponding to the rate increase for the period from March 1996 to December 1998. After unfavorable rulings in the courts of first and second instances with respect to statute of limitation claims and not on the merits, Enel Distribución São Paulo filed appeals with the Superior Court of Justice and the Federal Supreme Court. The amounts subject to dispute have been covered by a bank guarantee. In this regard, while awaiting the outcome of this proceeding, the Attorney General of the Department of the National Treasury of Brazil requested the replacement of the bank guarantee letter with a legal deposit. This request was rejected and the Attorney General’s Office appealed this decision. In June 2019, the court of first instance upheld the Attorney General’s appeal. Prior to the decision, the company made a legal deposit in the amount involved and, in opposition to the decision, filed a petition for clarification of the decision which is currently pending. As of December 31, 2021, the amount in dispute was ThBRL 245,000 (ThUS$ 43,986).

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30. In accordance with a final decision issued after a trial, Enel Distribución São Paulo was granted the right to offset claims for FINSOCIAL (the social contribution system established in March 1992 before COFINS) related to amounts paid from September 1989 to March 1992. However, due to differences in the calculation of the credits stipulated by the Brazilian Tax Authority, part of the offsets requested by the company were not accepted and were determined to be due by the Tax Authority. Following a decision unfavorable to the company in the court of first instance, the company appealed this decision and this appeal is pending before the administrative court of second instance. As of December 31, 2021, the amount in dispute was ThBRL 230,000 (ThUS$ 41,293).

31. The Brazilian Tax Authority issued a tax assessment to Enel Distribución São Paulo, based on the alleged non-payment of Personal Income Tax (IRPJ) and Social Contribution on Net Profit (CSLL) for the 2001 and 2002 fiscal years, because the company allegedly deducted integrated amounts paid to its pension fund from both the IRPJ and the CSLL, when the specific regulation establishes a 20% limit for such deductions. After the unfavorable final ruling in the administrative proceeding in October 2017, the dispute was submitted to the courts of law. In June 2019, a ruling favorable to Enel Distribución São Paulo was issued in the court of first instance for re-adjudication of the company’s appeal in the Administrative Court. The Attorney General’s Office appealed this decision. As of December 31, 2021, the amount in dispute was ThBRL 175,000 (ThUS$ 31,418).

32. The Brazilian Tax Authority issued a tax assessment to Enel Distribución São Paulo which rejected the offset related to the credits of the PIS originated by legislative changes introduced by Decrees 2,445 and 2,449/1988, which were declared unconstitutional by the Federal Supreme Court, that were offset against other federal taxes due in April and May 2013. The company filed its defense in September 2014. In January 2019, following a partially favorable ruling in the court of first instance, the company filed an appeal, which is pending before the Administrative Court of the second administrative instance. As of December 31, 2021, the amount in dispute was ThBRL 162,000 (ThUS$ 29,084).

33. Enel Distribución São Paulo filed a lawsuit seeking recognition of the right to offset the total tax credits resulting from Enel Distribución São Paulo’s division against the Social Contribution on Net Profit (CSLL). Favorable rulings were issued in the courts of first and second instance. In May 2017, the Tax Authority filed an interlocutory appeal with the Superior Court of Justice, which is pending. As of December 31, 2021, the amount in dispute was ThBRL 155,000 (ThUS$ 27,828).

34. In July 2000, Enel Distribución São Paulo filed a lawsuit seeking the recognition of credits arising from improper payments of PIS made pursuant to Decrees 2,445 and 2,449/1988, which were declared unconstitutional by the Federal Supreme Court. In May 2012, a final decision was issued in favor of the company recognizing the right to the credits. However, tax assessments were made on Enel Distribución São Paulo by the Brazilian Tax Authority because the offsets were rejected due to the fact that they had been made before the legal action had ended, using federal tax debits in addition to PIS. The company claims that the offsets were made on the basis of the favorable court ruling and that the adopted procedure was correct. After unfavorable decisions were rendered in the court of first instance, the company filed appeals with the court of second instance. As of December 31, 2021, the amount in dispute was ThBRL 667,000 (ThUS$ 119,749).

35. Enel Distribución São Paulo filed a complaint against the tax assessment issued by the Tax Authority of the Municipality of São Paulo, seeking payment of the Public Lighting Contribution (COSIP) related to the period from March 2011 to December 2015. These tax assessments are based on the alleged irregularities attributed to the company: (i) incorrect classification of customers, (ii) illegally applied tax exemption, and (iii) non-payment of the penalty for non-payment of contributions past due. In August 2021, the Municipality of São Paulo filed 26 assessments against Enel Distribución São Paulo. Enel Distribución São Paulo filed a guarantee and will present its defense. Enel Distribución São Paulo filed another guarantee in order to dispute two other debts related to the same subject that the company is awaiting the collection acts. As of December 31, 2021, the amount in dispute was ThBRL 181,000 (ThUS$ 32,496).

36. The Tax Authority of the State of São Paulo issued five tax assessments seeking payment of ICMS due to allegedly invalid setoffs in which the company used assigned credits in the acquisition of fixed assets, and which the Tax Authority believed was not appropriate. The company filed its administrative defenses in all the

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administrative procedures and is awaiting the final decisions.  As of December 31, 2021, the amount in dispute was ThBRL 156,000 (ThUS$ 28,008)

37. Enel Distribución São Paulo filed a complaint against Federal Decree No. 8,426/2015, which reinstated the PIS/PASEP and COFINS taxes on financial income earned by companies subject to the non-cumulative PIS/PASEP and COFINS regime, at a rate of 4.65%, as of July 1, 2015. The status of the litigation is that unfavorable decisions were rendered in the court of first instance (November 2015) and at the court of second judicial instance (August 2017). In December 2017, the company filed appeals with the Superior Court of Justice and the Federal Supreme Court. The Federal Supreme Court confirmed in a general impact procedure the constitutionality of the PIS and COFINS tax on financial income. Therefore, the Enel Distribución São Paulo considered it more appropriate to desist from discussing this litigation in September 2021. In November 2021, the desistance was approved, and it was determined that the reports of the judicial deposits must be submitted in order to convert the deposited securities into tax revenue. As of December 31, 2021, Enel Distribución São Paulo is awaiting approval of the conversion of the deposited securities into tax revenue. The amounts involved in the matter are judicially deposited and will be converted for the Federal Government. As of December 31, 2021, the amount in dispute was ThBRL 159,000 (ThUS$ 28,546).

38. Enel Distribución São Paulo filed a complaint claiming the right not to consider in its bases of calculation of Personal Income Tax (IRPJ) and Social Contribution on Net Profit (CSLL), the amounts related to interest derived from the delay in fulfilling contractual obligations on the part of third parties that maintain contractual relations of any type with the company (interest as an advance valuation of damages). In March 2012, the court of first instance issued a decision favorable to Enel Distribución São Paulo. The Brazilian Tax Authority appealed this decision, and the appeal is awaiting decision. Since the decision of the court of first instance was rendered, the company has not paid the disputed taxes to the federal government. As of December 31, 2021, the amount in dispute was ThBRL 176,000 (ThUS$ 31,598).

39. Enel Distribución São Paulo filed lawsuits against several tax assessments issued by the Tax Authority of the State of São Paulo claiming the payment of ICMS due to alleged irregularities in the debt reversal transactions. The company is presently challenging five tax assessments and two administrative proceedings, for which final decisions are pending. As of December 31, 2021, the amount in dispute was ThBRL 193,000 (ThUS$ 34,650)

40. The Brazilian Tax Authority issued tax assessments to Enel Distribución São Paulo based on the alleged non-payment of PIS/PASEP and COFINS taxes for the period from 2013 to 2015, arising from the disallowance of credits assigned in the acquisition of goods and services. In 2020, Enel Distribución São Paulo received two more violation notices indicating credits of said contributions, taken advantage of from August 2016 to December 2018, for not excluding credits related to the value of non-technical energy losses. The company filed its defenses in the two administrative proceedings and is awaiting the final decisions. As of December 31, 2021, the amount in dispute was ThBRL 252,000 (ThUS$ 45,242).

41. Tax assessment issued by the Brazilian Tax Authority against Enel Distribución São Paulo, based on the alleged non-payment of Personal Income Tax (IRPJ) and Social Contribution on Net Profit (CSLL) for the fiscal years 2017, 2018 and 2019, due to the fact that the company allegedly deducted premium amounts from the IRPJ and from the CSLL. The tax use of the premium amortization was initiated after the corporate reorganizations carried out by the former controlling company in 2016. Enel Distribución São Paulo filed its defense in the administrative proceedings and is awaiting the final decisions. As of December 31, 2020, the amount in dispute was ThBRL 751,000 (ThUS$134,830).

Enel CIEN S.A.

42. Enel CIEN S.A. is an Enel Américas group transmission company in Brazil. Its network connects the electrical system of Brazil and Argentina. Enel CIEN has signed a contract with Tractebel Energia S.A. for the purchase and sale of energy with firm power and associated energy from Argentina. In 2005, due to the energy and economy crisis in Argentina, it was no longer possible to fulfill the terms of the contract. Tractebel Energia S.A.

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filed actions for declaration of contractual termination, imposition of contractual penalties and claims for compensation (not estimable to date).

There is no injunction and there is still no first instance decision. The case is currently in the production of evidence stage (expert opinions). As of December 31, 2021, the amount involved in the lawsuit was ThBRL 597,480 (ThUS$ 107,269).

Enel Brasil S.A.

43. In 2014, the Brazilian Tax Authority issued an assessment to Enel Brasil claiming violations in the collection of income tax on dividends allegedly distributed in an amount larger than owed in 2009 and 2010. After adverse rulings at the first and second administrative instances, the company appealed to the third administrative level (special body) and the decision was unfavorable. Enel Brasil appealed to the judiciary and the interim decision was unfavorable. The company appealed to the court of second instance, but the decision was also unfavorable. The company posted bond in the collection lawsuit, and it was accepted. Enel Brasil submitted its defense within the legal deadline. As of December 31, 2021, the total amount involved in this litigation is estimated at ThBRL 365,000 (ThUS$ 65,530)

Colombia:

Emgesa S.A. ESP

44. José Rodrigo Alvarez and approximately 1,400 other individuals — all of them residents of the municipality of Garzón — filed a class-action lawsuit, currently pending in the Fourth Civil Court of the Circuit of Bogotá, against Emgesa S.A. ESP. It is claimed that, as a consequence of the construction of El Quimbo hydroelectric project, their income from artisanal and business activities was reduced by an average of 30% even though the socioeconomic study of the project had taken this into account. The case has been in the evidentiary stage since 2016. Emgesa S.A. ESP. is waiting for the Court to decide whether this production of evidence is deemed waived, in order to proceed to the closing arguments. The amount of the claim is ThCOP 30,619,930 (ThUS$ 7,523).

45. A class action lawsuit filed against Emgesa S.A. ESP, the Colombian Ministry of Environment and Development and the Colombian Ministry of Mines and Energy, Comepez S.A. and other fish farm and artisanal fishermen companies, is currently under review by the Huila Administrative Court. Fishermen are seeking the protection of collective rights and a healthy environment, public health, and food safety. Furthermore, the plaintiffs are seeking the issuance of an order compelling the entities to immediately take the necessary corrective and preventive measures to halt the imminent danger of massive fish mortality in the Betania reservoir fish farming projects, relating to the filling of the reservoir and the operation of the El Quimbo hydroelectric project. This lawsuit does not have a specified monetary amount because of its nature of protection of collective rights. On February 1, 2021, the Huila Administrative Court, which, while recognizing that the oxygenation system implemented by Emgesa S.A. ESP mitigated the risks associated with the protection of wildlife in the Betania basin, required the company to implement a project to decontaminate the river basin, which will be subject to verification by the Colombian environmental authority, ANLA, as well as to permanently ensure the operation of the oxygenation system already implemented. Emgesa S.A. ESP filed an appeal on March 4, 2021. It is expected that a second instance ruling will be issued in 2025.  

46. An action for nullity and reinstatement of rights filed by Emgesa S.A. ESP against the Corporación Autónoma Regional de Cundinamarca (CAR). CAR by means of Resolutions No. 506 of March 28, 2005 and 1189 of July 8, 2005, ordered Emgesa S.A. ESP, EEB and Empresa de Acueducto y Alcantarillado de Bogotá (EEAB) to carry out works in the El Muña reservoir. Emgesa S.A. ESP filed a lawsuit against the resolution seeking their reversal. Regarding the procedural status, a first instance judgment was issued rejecting the reversal of these resolutions. Appeals were filed by Emgesa S.A. ESP, EEB and EEAB, which are currently pending resolution. There is also a parallel action for nullity and reinstatement of rights brought by Emgesa S.A. ESP against CAR, seeking the nullity of Article 2 of Resolution No. 1318 of 2007 and Article 2 of Resolution No. 2000 of 2009, whereby Emgesa S.A. ESP has been required to implement a "Contingency Plan" and to carry out an "Air Quality" study in case the pumping of water from the reservoir is suspended. The evidentiary stage was completed and closing

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arguments were presented and, as of this date, the ruling of the court of first instance is pending. The amount involved in this litigation is indeterminate.

Codensa S.A.

47. In a class-action lawsuit filed by several residential complexes — including the Sabana Medical Center— against Codensa  S.A. in the First Administrative Court of the Bogotá Capital District, the plaintiffs demand the refund of an alleged tariff cost excess that they were charged due to a failure to apply a tariff benefit to which the plaintiffs argue they are entitled as Voltage Level One users and infrastructure owners, as established in Resolution No. 082 of 2002, modified by Resolution No. 097 of 2008. The proceedings are in the evidentiary stage since May 15, 201. The estimated value of this lawsuit is approximately COP 337 million (ThUS$ 82,800).

48. Henry Andrew Barbosa filed a class-action lawsuit against Codensa S.A. and the Special Public Services Administrative Unit (UAESP) of the Bogotá Capital District before the Tenth Administrative Judge of the Bogotá Capital District. Subsequently, Codensa  S.A. filed an action for nullification and restoration of rights against the UAESP, which is currently pending before the Administrative Court of Cundinamarca. In the class action, the judge ordered Codensa S.A. and the UAESP to reassess the 1997 Public Lighting Agreement signed between them, since it was determined that there were 8,661 fewer street lights than Codensa S.A. had taken into account in its billing. In 2014, the parties agreed to the reassessment and carried out a transaction for the period from 1998 to 2004, resulting in a debt of COP 14,433 million (ThUS$ 3,546) owed by Codensa  S.A. to the UAESP. By an order of June 1, 2017, the Court refused to consider the above-mentioned 2014 agreement and instead ordered the UAESP to carry out a unilateral assessment. In compliance with the order, the UAEPS issued Resolution No. 000730 of December 18, 2017, where it determined that Codensa S.A. should pay COP 113,082 million (ThUS$ 34,426). An action for nullification and reinstatement of rights was filed against the UAESP. On August 21, 2019, the Administrative Court of Cundinamarca determined that no further evidence was needed and ruled against Codensa S.A., subtracting any value from the reassessment agreed by the parties in 2014. An appeal was filed and submitted to the Council of State. The UAESP had begun the collection process, but the collection was suspended with the admission of the nullification action. Codensa  S.A. paid COP 24,400 million (ThUS$ 5,995), which it considers its obligation to pay under the 2014 reassessment agreements. In total, the nullification action has an approximate value of COP 88,698 million (ThUS$ 21,793).

49. The Administrative Court of Cundinamarca notified Carlos Mario Restrepo Molina, as liquidator of Sociedad Luz de Bogotá S.A. (to which Enel Américas is the successor) of a writ of mandamus against him in the amount of COP 35,073 million (ThUSD$8,617). The enforcement process was initiated by the Chamber of Commerce of Bogota against the liquidator because when registering act No. 26 of July 9, 2004, (whereby the final liquidation account and the act of distribution of remainders were approved) no registration tax was generated in favor of the Governor’s Office of Cundinamarca. This led the Revenue Directorate of the Treasury Department of the Department of Cundinamarca to issue Revision Settlement No. 0001 of 2007, whereby it modified the registration tax return filed by the Chamber of Commerce of Bogotá and imposed a penalty for inaccuracy on the latter as the collecting entity. After a nullification proceeding instituted by the Chamber of Commerce of Bogotá against the Government of Cundinamarca for this action, the State Council decided that indeed the registration tax should have been paid and the Chamber of Commerce of Bogotá, through Resolution no. 061 of April 21, 2016, issued an order to pay the registration tax in the amount of COP 35,073 million (ThUSD$ 8,617). Currently, an appeal for reconsideration was filed against the writ that issued the payment order; however, the Court decreed the nullification on the grounds that the liquidator had been improperly notified. Once the notification has been served, the appeal against the writ issuing the payment order will be filed again.

Costa Rica:

P.H. Chucás S.A.

50. On May 19, 2021, P.H. Chucás S.A. initiated an arbitration proceeding filed with the Costa Rican-North American Chamber of Commerce (AMCHAM CICA) against the Instituto Costarricense de Electricidad (ICE) for an approximate amount of US$362 million in order to obtain recognition of the higher costs incurred for the

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construction of the Chucás plant and of the extension of the deadline to complete the construction work, in order to vacate the penalty imposed by ICE on P.H. Chucás S.A. for an alleged delay in the completion of the construction.

On June 23, 2021, ICE filed its response to P.H. Chucás S.A.’s claims, formally objecting to the jurisdiction of the arbitral tribunal. The arbitral tribunal rejected ICE’s objection in a resolution dated August 4, 2020, to which ICE filed a motion for revocation with a subsidiary appeal. The arbitral tribunal once again rejected the appeal for revocation and referred the appeal to the First Chamber of the Supreme Court of Justice, determining the suspension of the arbitration process until the First Chamber resolves ICE’s appeal. The arbitration process is currently suspended.

EGP Costa Rica S.A. and ESSA2 SpA (Chile):

51. On September 30, 2021, in view of the systematic blocking of alternatives by Costa Rican entities, and in the absence of solutions and concrete actions by the Government of Costa Rica that would allow the resumption of operations of the P.H. Don Pedro and P.H. Rio Volcán hydroelectric projects, ESSA2 SpA and EGP Costa Rica S.A. filed a request for arbitration with the International Centre for Settlement of Investment Disputes (ICSID) against the Government of Costa Rica, claiming violation of the provisions of the Treaty regarding (i) expropriation (Article 6 of the Treaty) and (ii) fair and equitable treatment (Article 4 of the Treaty).

On October 13, 2021, ICSID formally and officially registered the request for arbitration, and the parties are currently in the process of appointing the arbitral tribunal.

In relation to the litigation proceedings described above, the Group has established provisions for ThUS$88,973 as of December 31, 2021 (see Note 24). There are other lawsuits that also have associated provisions, but they are not described in this note since they individually represent immaterial amounts. Management believes that the provisions recorded adequately cover the risks of litigation. Therefore, they do not expect additional liabilities to arise from other than those already registered.

34.4 Financial restrictions

Several debt contracts of the Company, and of some of its subsidiaries include the obligation to comply with certain financial ratios, which is common in contracts of this nature. There are also affirmative and negative covenants that require monitoring of these commitments. In addition, there are restrictions in the sections of events of default that must be fulfilled to avoid acceleration of the debt.

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Cross default

Certain financial debt contracts of the Company contain cross default clauses.

Financial restrictions	Enel Américas	Enel Américas	Enel Américas	Enel Américas
Type of restricted instrument	Revolving credit facility	Yankee Bonds	Yankee Bonds	B2 Series Bonds
Restriction to be met by the Reporting Entity or Subsidiary	Any debt held by Enel Américas for any financial debt in default, and where the principal owed leading to cross default exceeds US$150 million in a single debt.	Any financial debt held by Enel Américas or any Significant Subsidiary, for any amount in default, and where the principal owed leading to cross default exceeds US$150 million in a single debt.	Any financial debt held by Enel Américas, for any amount in default, and where the principal owed leading to cross default exceeds US$30 million in a single debt.	Any financial debt held by Enel Américas, for any amount in default, and where the principal owed leading to cross default exceeds 3% of Total Consolidated Assets, at stand-alone or aggregate level.
Creditor	BBVA, S.A. New York Branch	BNY Mellon (representative of bond holders)	BNY Mellon (representative of bond holders)	Banco Santander (representative of bond holders)
Registration number	-	ISIN: US29274FAF18	ISIN: US29274FAC86	BENER-B2 Registration No. 269
Indicator or financial ratio name	Cross default	Cross default	Cross default	Cross default
Frequency of measurement	Quarterly	Quarterly	Quarterly	Quarterly
Mechanism to calculate or define the indicator or ratio	Debt in default exceeding US$150 million in principal owed, individually.	Debt in default exceeding US$150 million in principal owed, individually.	Debt in default exceeding US$30 million in principal owed, individually.	Debt in default exceeding 3% of Total Consolidated Assets, individually or in aggregate.
Restriction must be met (Range, Value, Measurement Unit)	Having no individual debts in default exceeding US$150 million.	Having no individual debts in default exceeding US$150 million.	Having no individual debts in default exceeding US$30 million.	Having no individual debts in default exceeding 3% of Total Consolidated Assets.
Indicator or ratio determined by the Company	There are no individual debts in default exceeding US$150 million.	There are no individual debts in default exceeding US$150 million.	There are no individual debts in default exceeding US$30 million.	There are no debts in default exceeding 3% of Total Consolidated Assets, individually or in aggregate.
Compliance YES/ NO	Yes	Yes	Yes	Yes
Accounts used to calculate the indicator or ratio	-	-	-	-

Financial covenants

Financial covenants are contractual commitments with respect to minimum or maximum financial ratios that the Company is obliged to meet at certain years of time (quarterly, annually, etc.) and in some cases only when certain conditions are met. Most of the financial covenants of the Company limit leverage and track the ability to generate cash flow that will service the companies’ indebtedness. Certain companies are also required to periodically certify these covenants. The types of covenants and their respective limits vary according to the type of debt and contract.

The Series B2 Chilean bonds of the Company include the following financial covenants, whose definitions and calculation formulas are set out in the respective contract. On the other hand, the “Yankee Bonds” and any other debt of Enel Américas at an individual level, are not subject to compliance with financial covenants.

The debts of Enel Américas’ subsidiaries include the following financial covenants. The definitions and calculation formulas of these covenants are established in each relevant contract.

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Financial restrictions	Enel Américas	Enel Américas	Enel Américas	Enel Distribución Perú
Type of restricted instrument	B2 Series Bonds	B2 Series Bonds	B2 Series Bonds	IV Program Bonds
Restriction to be met by the Reporting Entity or Subsidiary	A Minimum Equity of Ch$718,262 million must be maintained, and this limit is updated at the close of each year, as established by contract.	An Indebtedness Ratio, defined as the ratio of Current Liabilities to Equity, must remain lower or equal to 2.24.	Assets that may constitute collateral or Total Free Assets must be kept at a ratio greater or of equal than 1 with respect to Unsecured Current Liabilities.	A Net Indebtedness to Equity ratio must remain of less than or equal to 1.70.
Creditor	Banco Santander Chile (Representative of Bond Holders)	Banco Santander Chile (Representative of Bond Holders)	Banco Santander Chile (Representative of Bond Holders)	Banco Continental S.A. (Representative of Bond Holders)
Registration number	BENER-B2 Registration No. 269	BENER-B2 Registration No. 269	BENER-B2 Registration No. 269	ISIN: PEP70101M498; PEP70101M506; PEP70101M514; PEP70101M522; 'PEP70101M530
Indicator or financial ratio name	Minimum Equity	Indebtedness Ratio	Assets that can Constitute Collateral	Indebtedness Ratio
Frequency of measurement	Quarterly	Quarterly	Quarterly	Quarterly
Mechanism to calculate or define the indicator or ratio	Equity corresponds to Equity attributable to the controller’s owners, which is different from the Minimum Equity level to be adjusted by a percentage, as long as it is positive, of the annual variation in the Consumer Price Index, multiplied by the difference between 1 less than the Non-Monetary Assets in Chile recorded in Chilean pesos and the Equity attributable to the Controlling Company. If the annual variation in the Consumer Price Index is negative or the ratio of Non-Monetary Assets in Chile recorded in Chilean pesos to Equity Attributable to the Controlling Company is greater than one, there will be no adjustment that year.	The Current Liabilities is the sum of of total current liabilities and total non-current liabilities. The Equity is the sum of Equity attributable to the controller’s owners and the Non-controlling interest.	The Total Free Assets is the difference between Total Net Assets and Total Encumbered Assets. Total Net Assets considers the Total Assets minus the sum of cash on hand, bank balances, current accounts receivable from related companies, current prepayments, non-current accounts receivable from related companies, and identifiable gross intangible assets, while Total Encumbered Assets corresponds to assets committed as direct guarantees. The Unsecured Current Liabilities correspond to the sum of total current liabilities and total non-current liabilities, minus Secured Liabilities through direct and indirect guarantees.	The sume of Total Liabilities minus Cash divided by Equity.
Restriction must be met (Range, Value, Measurement Unit)	A Minimum Equity of Ch$718,262 million must be maintained, and this limit is updated at the close of each year, as established by contract.	An Indebtedness Ratio, defined as the ratio of Current Liabilities to Equity, must remain of lower or equal to 2.24.	Assets that may constitute collateral must be kept at a ratio of greater or equal than 1 with respect to Unsecured Current Liabilities.	An Indebtedness Ratio of less than or equal to 1.70 must be kept.
Indicator or ratio determined by the Company	ThCh$12,695,769,256	1.33	1.35	1.01
Compliance YES/ NO	Yes	Yes	Yes	Yes
Accounts used to calculate the indicator or ratio	Equity attributable to the controller’s owners and the Non-controlling interest	Total Current Liabilities; Total Non-Current Liabilities; Equity attributable to the controller’s owners; Non-controlling interest	Total Assets; Cash on Hand; Bank Balances; Current accounts receivable from related companies; Current prepayments; Non-current accounts receivable from related companies; identifiable gross intangible assets; Assets committed through direct guarantees; Total current liabilities; Total non-current liabilities; Secured Liabilities through direct and indirect guarantees.	Total Liabilities; Deferred Liabilities; Cash; Equity

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Financial restrictions	Enel Generación Perú	Enel Distribución Rio	Enel Distribución Rio	Enel Distribución Ceará
Type of restricted instrument	III Program Bonds	Cred. with Fin. Inst.	Cred. with Fin. Inst.	Bonds 5th, 6th and 7th Issues
Restriction to be met by the Reporting Entity or Subsidiary	An Indebtedness Ratio of less than or equal to 1.50 must be kept.	Must maintain a ratio of debt payment capacity to EBITDA of less than or equal to 3.50.	A relationship must be maintained between Debt payment capacity over the sum of debt and Equity of less than or equal to 0.60.	A ratio between Debt payment capacity over EBITDA must be maintained of less than or equal to 3.50.
Creditor	Banco Continental S.A. (Representative of Bond Holders)	Banco de Desarrollo de Brasil	Banco de Desarrollo de Brasil	Oliveira Trust Distribuidora de Títulos E Valores Mobiliarios S.A. (Representative of Bondholders)
Registration number	ISIN: PEP70051M198; PEP70051M354	-	-	ISIN: BRCOCEDBS077; BRCOCEDBS085; BRCOCEDBS0A3; BRCOCEDBS0B1; BRCOCEDBS0C9; BRCOCEDBS0D7
Indicator or financial ratio name	Indebtedness Ratio	Net Financial Debt / EBITDA	Total Financial Debt net of cash / (Total Bank Debt net of cash + Equity)	Net Financial Debt / EBITDA
Frequency of measurement	Quarterly	Annual	Annual	Quarterly
Mechanism to calculate or define the indicator or ratio	The sum of Financial Debt minus Cash is divided by Consolidated Net Equity.	The sum of Bank Debt minus Cash is divided by EBITDA.	Divide the sum of Bank Debt less Cash by the sum of this and Equity.	The sum of Financial Debt minus Cash is divided by EBITDA.
Restriction must be met (Range, Value, Measurement Unit)	An Indebtedness Ratio of less than or equal to 1.50 must be kept.	Must maintain a ratio of debt payment capacity to EBITDA of less than or equal to 3.50.	A relationship must be maintained between Debt payment capacity over the sum of debt and Equity of less than or equal to 0.60.	A ratio between Debt payment capacity over EBITDA must be maintained of less than or equal to 3.50.
Indicator or ratio determined by the Company	0.06	1.16	0.14	2.89
Compliance YES/ NO	Yes	Yes	Yes	Yes
Accounts used to calculate the indicator or ratio	Financial debt; Cash; Consolidated equity	Bank Debt, Cash, EBITDA	Bank Debt, Cash, Equity	Financial Debt, Cash, EBITDA
Financial restrictions	Enel Distribución Ceará	Enel Distribución Ceará	Enel Distribución Ceará	Enel Distribución Sao Paulo
Type of restricted instrument	Cred. with Fin. Inst.	Cred. with Fin. Inst.	Cred. with Fin. Inst.	23rd Issue Bonds
Restriction to be met by the Reporting Entity or Subsidiary	Must maintain a ratio of debt payment capacity to EBITDA of less than or equal to 3.50.	Must maintain a ratio of debt payment capacity to EBITDA of less than or equal to 3.50.	A relationship must be maintained between Debt payment capacity over the sum of debt and Equity of less than or equal to 0.60.	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.
Creditor	Scotiabank, BNP Paribas, SMBC	Banco de Desarrollo de Brasil	Banco de Desarrollo de Brasil	Oliveira Trust Distribuidora de Títulos E Valores Mobiliarios S.A. (Representative of Bondholders)
Registration number	-	-	-	ISIN: BRELPLDBS0V6; BRELPLDBS001

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Indicator or financial ratio name	Net Financial Debt / EBITDA	Net Financial Debt / EBITDA	Total Financial Debt net of cash / (Total Bank Debt net of cash + Equity)	Net Financial Debt / Adjusted EBITDA
Frequency of measurement	Quarterly	Annual	Annual	Quarterly
Mechanism to calculate or define the indicator or ratio	The sum of Financial Debt minus Cash is divided by EBITDA.	The sum of Financial Debt minus Cash is divided by EBITDA.	Divide the sum of Bank Debt less Cash by the sum of this and Equity.	The sum of Financial Debt less Cash is divided by Adjusted EBITDA less Financial Leasing Expenses
Restriction must be met (Range, Value, Measurement Unit)	A ratio between Debt payment capacity over EBITDA must be maintained of less than or equal to 3.50.	A ratio between Debt payment capacity over EBITDA must be maintained of less than or equal to 3.50.	A relationship must be maintained between Debt payment capacity over the sum of debt and Equity of less than or equal to 0.60.	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.
Indicator or ratio determined by the Company	2.89	1.34	0.26	1.38
Compliance YES/ NO	Yes	Yes	Yes	Yes
Accounts used to calculate the indicator or ratio	Financial Debt, Cash, EBITDA	Financial Debt, Cash, EBITDA	Bank Debt, Cash, Equity	Financial Debt, Cash, EBITDA; Finance leases
Financial restrictions	Enel Distribución Sao Paulo	Enel Distribución Sao Paulo	Enel Distribución Sao Paulo	EGP Volta Grande
Type of restricted instrument	24th and 25th Issuance Bonds	Cred. with Fin. Inst.	Cred. with Fin. Inst.	1st Issue Bonds
Restriction to be met by the Reporting Entity or Subsidiary	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.	A ratio between Debt payment capacity over EBITDA must be maintained of less than or equal to 4.00.
Creditor	Oliveira Trust Distribuidora de Títulos E Valores Mobiliarios S.A. (Representative of Bondholders)	BNP Paribas and MUFG	Scotiabank	Oliveira Trust Distribuidora de Títulos E Valores Mobiliarios S.A. (Representative of Bondholders)
Registration number	ISIN: BRELPLDBS0X2; BRELPLDBS0Y0; BRELPLDBS100
Indicator or financial ratio name	Net Financial Debt / Adjusted EBITDA	Net Financial Debt / Adjusted EBITDA	Net Financial Debt / Adjusted EBITDA	Net Financial Debt / EBITDA
Frequency of measurement	Quarterly	Quarterly	Quarterly	Quarterly
Mechanism to calculate or define the indicator or ratio	The sum of Financial Debt minus Cash is divided by Adjusted EBITDA plus Losses due to deactivation of assets and rights	The sum of Financial Debt minus Cash is divided by Adjusted EBITDA plus Losses due to deactivation of assets and rights	The sum of Financial Debt minus Cash is divided by EBITDA plus sectoral adjustments	The sum of Financial Debt minus Cash is divided by EBITDA.
Restriction must be met (Range, Value, Measurement Unit)	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.	A ratio between Debt Payment Capacity over Adjusted EBITDA must be maintained of less than or equal to 3.50.	A ratio between Debt payment capacity over EBITDA must be maintained of less than or equal to 4.00.
Indicator or ratio determined by the Company	1.35	1.36	1.36	1.97
Compliance YES/ NO	Yes	Yes	Yes	Yes
Accounts used to calculate the indicator or ratio	Financial Debt, Cash, EBITDA	Financial Debt, Cash, EBITDA	Financial Debt, Cash, EBITDA	Financial Debt, Cash, EBITDA

The rest of the subsidiaries not mentioned in this Note are not subject to compliance with financial covenants.

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Lastly, in most of the contracts, debt acceleration due to non-compliance with these covenants is not automatic, and certain conditions must be met, such as expiration of the cure period, among other conditions.

As of December 31, 2021, none of the subsidiaries of Enel Américas was in compliance with its financial obligations summarized herein, or other financial obligations whose compliance might result in the early maturity of their financial commitments.  

34.5 COVID-19 contingency

On January 30, 2020, the World Health Organization (WHO) declared the outbreak of the new coronavirus 2019, or COVID-19, to be a "Public Health Emergency of International Concern". On March 11, 2020, the WHO confirmed that the outbreak of COVID-19 had reached the level of a pandemic, which could significantly affect all the countries in which the Group operates, as well as the Group’s trade partners within and outside these countries.  

To address this international public health emergency due to COVID-19, the governments of all the countries in which Group operates, have adopted various measures, essentially designed to restrict free movement of individuals, which include quarantines, social isolation and temporary closure of companies and businesses, among other measures. Governments have also taken measures to preserve access to essential services such as water and electricity during the health emergency, especially directed to residential customers with lower income, small and medium sized companies and institutions that provide other essential services such as health establishments.  

These measures refer basically to the temporary suspension of disruption of electric supply due to customers recording payment defaults and deferral of the payment of electricity bills for a certain number of months, without interest or penalties charged to customers. In this sense, the Group issued guidelines intended to guarantee compliance with the measures introduced by the governments of the countries in which the Group operates and has taken a number of actions to adopt the most adequate procedures to prevent and/or mitigate the effects of COVID-19 infection in the workplace, while guaranteeing business continuity.  

The above has been possible mainly due to:  

• The use of telework for all employees whose jobs can be performed remotely (50% of the staff). This work mode was introduced in the Group a few years ago, which thanks to investment in digitalization, allows work to be performed remotely with the same level of efficiency and effectiveness;  

• Digitalization of processes and infrastructure, which ensures the normal operation of our generation assets, continuity of the electrical service and remote management of all activities related to the market and customer relations.  

All the company’s efforts continue to focus on guaranteeing the correct and safe operation of our businesses, while at the same time safeguarding the health and safety of our collaborators and helping the community with various solidary measures.

In relation to the degree of uncertainty generated in the macroeconomic and financial environment in which the Group operates and their effect on the Company’s income as of December 31, 2021, these are fundamentally related to an increase in the impairment loss on trade accounts regarding the pre COVID 2019 situation (see Notes 2.3, 3.g.3 and 9.c).

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34.6 Other Information

(i) Enel Generación Costanera S.A. – Enel Generación El Chocón S.A. – Central Dock Sud S.A.

Fund for necessary investments to increase the supply of electricity in the MEM “FONINVEMEM”

January 7, 2020 and February 10, 2020 were the ten-year anniversaries of the start of Commercial Operation of Central Térmica Manuel de Belgrano (TMB) and Central Térmica San Martin (TSM), respectively, ending the electric energy supply contracts signed between the respective Trusts and CAMMESA at the time. Likewise, on the indicated dates, the respective Trust Agreements and Contracts for the Operation and Maintenance Management (CO&M) of both power plants came to an end. TMB and TSM, as managing companies, together with their current shareholders (which include the Company as a guarantor) must perform the company actions necessary to allow the entry of the Argentine national government in the equity of both companies. The corresponding ownership interest of the Argentine national government is a controversial matter, since the government claims a higher share percentage of both thermoelectric plants. In order to ensure the operation and maintenance of the power plants, the term of the respective CO&M contracts has been extended, with the corresponding extensions being signed on January 7 and January 9, 2020, respectively.

On May 4 and May 8, 2020 the Extraordinary Shareholders’ Meetings of TMB and TSM were held, respectively, whereby the shareholders agreed to increase the share capital in order for the Argentine national government to be able to subscribe to the capital increase, and in this manner, become the holder of 65.006% and 68.826 % of the shares of TMB and TSM, respectively, thus complying on time and in the proper manner with the condition precedent established in articles 1.01 and 7.03 of the Trust Agreements. Notwithstanding the above, the Company and the rest of the shareholders that participated in the meetings ratified the request (dated April 22, 2020) addressed to the Ministry of Productive Development by the Company together with other shareholders of TMB and TSM for the implementation of the share concentration scheme foreseen in the “Agreement for the Management and Operation of Projects, Increase in Thermoelectric Generation and Adaptation of the 2008-2011 Generation Remuneration”, and established a reserve for the damage claim actions in case such request was not accepted.

During November 2020, BICE, acting as trustee, confirmed fulfillment of the suspensive condition mentioned above, upon valid performance of the corporate acts for the inclusion of the Argentine national government in the equity of TMB and TSM. Consequently, the Group holdings were reduced from 25.6% to 8.59% for the Manuel Belgrano Thermal Power Plant and 25.6% to 7.7% for the San Martín Thermal Power Plant.

Finally, on March 18, 2021, the Ministry of Energy notified TMB and TSM of the subscription of the shares resulting from the capital increase in both companies on behalf of the Argentine government. Consequently, the Trusts must transfer the trust assets to TMB and TSM. This transfer is still in progress.

Central Vuelta Obligado (VOSA)

On March 20, 2018, CAMMESA enabled the commercial operations of the TGs and TV units in the Wholesale Electricity Market, operating as a combined cycle of the Vuelta de Obligado Plant (VOSA), for up to 778.884 MW (net capacity). On February 7, 2019, VOSA entered into a Supply Contract, Operations Contract, and Management Contract, as well as pledge and assignment as collateral contracts, with CAMMESA. From March 2019, the companies have been collecting monthly payments. As of December 31, 2021, the companies have collected 44 of the 120 installments agreed in the contracts.  

The outstanding balance as of December 31, 2021 amounts to ThUS$ 270,945 (ThUS$ 311,875 as of December 31, 2020). The breakdown by company is detailed as follows: (i) Enel Generación El Chocón S.A. amounting to ThUS$ 180,601 (ThUS$ 208,941 as of December 31, 2020), (ii) Central Dock Sud S.A. amounting to ThUS$ 72,566 (ThUS$ 82,438 as of December 31, 2020) and (iii) Enel Generación Costanera S.A. amounting to ThUS$ 17,778 (ThUS$ 20,496 as of December 31, 2020) (See Note 9).

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(ii) Edesur:

2019 Regulatory Agreement

On May 10, 2019, Edesur entered into an Obligations Regularization Agreement with the Secretariat of Energy, on behalf of the Argentine State, which puts an end to the reciprocal claims arising during the transition period between 2006 and January 2017. On one hand, Edesur agrees to: (i) credit penalties to customers within a period of 3 years, adjusted at the prevailing rate of the Bank of the Argentine Nation (BNA); (ii) credit the fines contained in Appendix VIII of the 2006 Memorandum of Agreement, in up to 14 biannual installments, recalculated up to the date of effective payment according to the average increase registered by the own cost of distribution; (iii) based on the provisions of clause 5.4 of the Memorandum of Agreement, allocate the amounts of penalties for regular quality measurements during the transition period, to make additional investments over those established in the Integral Rate Review (RTI), which are intended to contribute to service improvement, reliability, and security. Moreover, new conditions were agreed upon in relation to the consumption loans granted by CAMMESA. Meanwhile, the Argentine State offset, in favor of Edesur, commercial debts with CAMMESA for energy purchases performed in the Wholesale Electricity Market (MEM) prior to the effective date of the resolution issued by the National Electricity Regulatory Body (ENRE) No. 1/2016, and the Argentine State’s debts generated in 2017 and 2018 related to consumption in settlements measured by community meters, between July 2017 and December 31, 2018, in the proportion established in the New Framework Agreement and its successive renewals, and with the differences generated by the application of the maximum limit in the invoices issued to beneficiaries of the social rate. Moreover, the Argentine State forgave the sanctions owed to the Public Administration (see Note 23).

The effects of this agreement generated a reduction in liabilities recorded in operating income for 2019 in the amount of MARS 12,183 (approximately ThUS$ 203,433). As a result of the application of IAS 29 “Financial Reporting in Hyperinflationary Economies,” these amount at the year end of December 2019 amounted to MARS 15,461 (approximately ThUS$ 261,185).  

2020 Framework Agreement

The Province of Buenos Aires requested that the Argentine Ministry of Economy initiate a bid process to correct the situation related to the electricity supply in low income neighborhoods between October 2017 and December 2020. On December 22, 2020, the Argentine national government, through the Ministry of Economy and Secretariat of Energy, the National Electricity Regulatory Body (ENRE), and the companies Edenor and Edesur, entered into an agreement to develop a mechanism to pay off debt corresponding to the Framework Agreement for such period, while the companies assumed the commitment to allocate said funds to improve electric service works and the status of the network supplying these neighborhoods with collective meters and other sensitive zones in the concessions area, without implying that there would be an extension of downstream responsibility for those collective meters, according to the applicable regulations. Through this agreement, during December 2020, ARS 1,500 million (ThUS $ 17,842) were recognized and the related collection was perfected on January 15, 2021. During 2021, the Company advanced with the committed works, while the monitoring and verification by the ENRE. On December 9, 2021, through Resolution SE No. 1199, the second milestone was approved and, on December 29, 2021, MARS 500 (ThUS$ 4,869) were collected, which is disclosed in “Revenue from the sale of energy”. As of the date of these financial statements, the amount related to the last milestone remains pending receipt.

Economic-financial situation

The Covid-19 pandemic and the extension of compulsory social isolation have triggered an economic recession in Argentina, which, together with the continuity of the rate freeze and the fact that no economic compensation has been implemented for electricity distributors through the present date, has led Edesur to negative working capital of ThARS$64,762,256 (ThUS$630,680), as of December 31, 2021. Based on an analysis of projected cash flow, the Company’s Management believes that Edesur will not have difficulty in meeting its financial obligations as of December 31, 2021 and thereafter. The key assumptions used for this cash flow projection are based on operating variables such as electricity demand, tariffs/subsidies, costs, collectability, debt renegotiation and macroeconomic assumptions such as inflation, exchange and interest rates, and the probable results of negotiations with the authorities.

F-181

Edesur’s Management believes that actions taken by the Special Regime for Regularization of Obligations (DNU No. 40/2021), Resolution No. 371/2021, the Transition Tariff Regime (2021 Budget Law and PEN Decree No.1020/2020) and the Final Renegotiation Agreement will allow it to rebuild the economic and financial equation provided by the law and by the Concession Agreement, thanks to joint work with the Argentine authorities that will allow companies to continue to provide essential services such as electric energy distribution. For further details see Note 4.i.a, where the Argentine regulatory framework is established (in the subheadings “Tariff reviews” and “Other regulatory aspects”).

35. HEADCOUNT

The Group personnel, including that of subsidiaries in the eight Latin American countries where the Group operates, is distributed as follows as of December 31, 2021 and 2020:

	12-31-2021
	Managers	Professionals
	and key	and	Staff and
Country	executives	Technicians	others	Total
Argentina	31	1,883	2,150	4,064
Brazil	65	5,613	3,192	8,870
Colombia	41	2,218	—	2,259
Costa Rica	5	18	11	34
Chile	8	46	3	57
Guatemala	9	85	—	94
Panama	21	35	38	94
Peru	29	960	—	989
Total	209	10,858	5,394	16,461
Average	199	10,943	5,638	16,780
	12-31-2020
	Managers	Professionals
	and key	and	Staff and
Country	executives	Technicians	others	Total
Chile	8	39	4	51
Argentina	35	1,850	2,179	4,064
Brazil	51	5,726	3,746	9,523
Peru	35	908	—	943
Colombia	39	2,111	—	2,150
Total	168	10,634	5,929	16,731
Average	170	10,679	6,120	16,969

36. SANCTIONS

The main sanctions received by Group companies are described below:

Subsidiaries

1. Enel Distribución Río S.A. (Formerly Ampla Energia e Serviços S.A. or “Ampla”)

Tax sanctions

- The Brazilian Tax Authority imposed a fine on Enel Distribución Rio after denying the authorization to offset federal taxes. Individual fines have been imposed on the company for 50% of the compensation requested and

F-182

denied by the Brazilian Tax Authority. The company filed its administrative defenses against the fines and is awaiting a ruling. There are also late penalties on federal tax offsets. The principal of the offset was accepted by the Brazilian Tax Authority, but it asserted that there was a payment delay, resulting in the imposition of the fines. In December 2021 the company was successful in overturning two of the fines, having paid the total amount of ThBRL 1,204 (ThUS$216). As of December 31, 2021, the total amount involved in all other fines was ThBRL 12,337 (ThUS$ 2,215).

2. Enel Distribución Ceará S.A. (Formerly Companhia Energetica do Ceará or Coelce)

Tax sanctions

- The Brazilian Tax Authority imposed a fine on Enel Distribución Ceará after denying the authorization to offset federal taxes. Individual fines have been imposed on the company for 50% of the compensation requested. The company filed its administrative defenses against the fines and is awaiting a ruling.  There are also late penalties on federal tax offsets. The principal of the offset was accepted by the Brazilian Tax Authority, but it asserted that there was a payment delay, resulting in the imposition of the fines. In December 2021 the company received two more fines for delay in the payment of service tax (Imposto sobre Serviços de Qualquer Natureza – ISS) from the Municipalities of Iguatu and Pereiro. As of December 31, 2021, the total amount involved in all fines was ThBRL 1,958 (ThUS$ 351).

- In 2018, the Tax Authority of the State Treasury of Ceará imposed a fine of ThBRL 1,029 (ThUS$ 185) on Enel Distribución Ceará for alleged non-compliance with tax rules related to obligations to issue and register transit invoices. The company filed its administrative defenses against the fine and is awaiting a ruling.

Regulatory sanctions

- In 2021, the Brazilian National Electricity Regulatory Agency (ANEEL) imposed a fine of BRL 35.9 million on Enel Distribución Ceará for non-compliances with maintenance and violations of quality indicators (SAIDI/SAIFI) for the year of 2020. The company filed an appeal against the fine, which was accepted by ANEEL, reducing the value of the fine to the ThBRL 31,800 (ThUS$ 5,709). On November 23, 2021, the company’s administrative appeal was judged, and the fine was reduced. As of December 31, 2021 the amount involved in the fine was ThBRL 26,500 (ThUS$ 4,759).

3. Enel Distribución Goiás (Formerly CELG Distribuição S.A)

Regulatory sanctions

- In 2016, the Brazilian National Electricity Regulatory Agency (ANEEL) imposed a fine of BRL 62 million on Enel Distribución Goiás for failure to fulfill a sector obligation linked to the Account for the Development of Energy (Conta de Desenvolvimento Energético or CDE). The company filed an appeal to reduce the fine to BRL 25 million. The company also posted a bond and filed a lawsuit for the fine’s total nullification, which is still pending resolution. As of December 31, 2021, the amount involved in the fine was ThBRL 41,645 (ThUS$ 7,476).

- In 2019, ANEEL imposed a fine of BRL 61 million on Enel Distribución Goiás for breaches of customer service and energy supply quality indicators. The company filed an appeal against the fine, which was accepted by ANEEL, reducing the fine from BRL 62 million to BRL 45 million. A new motion for reconsideration was filed, as a result of which ANEEL reduced the fine amount to BRL 31 million. As of December 31, 2021, the amount involved in the fine was ThBRL 34,180 (ThUS$ 6,136).

- In 2020, the Agência Goiana de Regulação (AGR) imposed a fine of BRL 44 million (ThUS$ 7,899) on Enel Distribución Goiás for breaches of maintenance and quality indicators (SAIDI/SAIFI). The company filed an appeal against the fine with ANEEL, which was accepted by ANEEL, reducing the amount of the fine by BRL 1 million. A new motion for reconsideration was filed, which is pending resolution. As of December 31, 2021, the amount involved in the fine was ThBRL 45,750 (ThUS$ 8,214).

F-183

4. Enel Distribución Sao Paulo (Formerly Eletropaulo)

Regulatory sanctions

- The Brazilian National Electricity Regulatory Agency (ANEEL) imposed a fine on Enel Distribución São Paulo for alleged errors in the records of the company’s asset base. The company filed an appeal which was dismissed. The company filed a lawsuit seeking the total nullification of the fine. The judge in the court of first instance issued a decision dismissing the company’s claims. The company has filed an appeal with the Court of Justice (court of second instance), which is pending resolution. There is an injunction in place, suspending all the effects of the fines. As of December 31, 2021 the amount involved in the fines was ThBRL 190,120 (ThUS$ 34,132).

- ANEEL imposed a fine on Enel Distribución São Paulo for alleged formal inconsistencies of asset accounting records. The company asserted that the errors have not generated any negative practical consequences for tariffs, and even less for the service provided by the company. The company’s administrative appeal was dismissed, and the company filed a lawsuit for the total nullification of the fine. On May 29, 2019, the judge in the court of first instance issued a decision dismissing the company’s claims. The company filed an appeal with the Court of Justice (court of second instance) which is pending resolution. As of December 31, 2021, the amount involved in the fines was ThBRL 94,200 (ThUS$ 16,912).

- In 2012, ANEEL imposed a fine on Enel Distribución São Paulo for alleged formal inconsistencies of records of consumer supply quality indices, as well as the payment of compensation to customers for non-compliance with these indices. The company filed its administrative defenses. In April 2020, the company filed a lawsuit with the court seeking nullification of the fine and a decision was issued suspending all the effects of the fines. As of December 31, 2021 the amount involved in the fines was ThBRL 30,770 (ThUS$ 5,524).

- ANEEL imposed a fine on Enel Distribución São Paulo for non-compliance with consumer supply quality indices during 2013. The company filed its administrative defenses against the fine, which was decided unfavorably to the company. On July 24, 2018, the company filed a lawsuit seeking the nullification of the fine. On October 8, 2021 the judge in the court of first instance issued a decision dismissing the company’s claim. The company filed an appeal with the Court of Justice (court of second instance) against such decision, which is pending resolution. There is an injunction in place suspending all effects of the sanctions. As of December 31, 2021, the amount involved in the fines was ThBRL 70,530 (ThUS$ 12,662).

- ANEEL imposed a fine on Enel Distribución São Paulo for non-compliance with consumer supply quality indices during 2014. The company filed its administrative defenses against the fine, which was decided unfavorably to the company. On July 31, 2018, the company filed a lawsuit seeking the nullification or reduction of the fine. On October 17, 2019, the judge in the court of first instance denied the company’s request for nullification. The company filed an appeal with the Court of Justice (court of second instance) against such decision, which is pending resolution. As of December 31, 2021, the amount involved in the fines was ThBRL 35,970 (ThUS$ 6,457).

- ANEEL imposed a fine on Enel Distribución São Paulo for nonconformity in the Budgetary Liquidation process. The company filed its administrative defenses against the fine, which was decided unfavorably to the company. The company filed a lawsuit seeking the nullification or reduction of the fine. The first instance ruling was unfavorable to the company, which filed an appeal with the Court of Justice (court of second instance) against such decision, which is pending resolution. As of December 31, 2021, the amount involved in the fines was ThBRL 28,350 (ThUS$ 5,089).

- ANEEL imposed a fine on Enel Distribución São Paulo for nonconformity in the Budgetary Liquidation process. The company filed its administrative defenses against the fine, which was decided unfavorably to the company. The company filed a lawsuit seeking the nullification or reduction of the fine. The first instance ruling was favorable to the company. ANEEL filed an appeal which is pending resolution. As of December 31, 2021, the amount involved in the fines was ThBRL 89,654 (ThUS$ 16,095).

F-184

- In July 2002, the Municipality of Jandira imposed a fine on Enel Distribución São Paulo for violation of municipal laws with respect to the road network in the municipality. The company’s administrative defenses against the fines were decided unfavorably to the company. The company filed a lawsuit seeking the nullification of the fine. The first instance ruling was unfavorable to the company, which filed an appeal against it and succeeded having the decision reversed in its favor. The Municipality of Jandira filed appeals with the Superior Court of Justice and the Federal Court of Justice. The Superior Court of Justice dismissed the Municipality’s appeal. The Municipality of Jandira filed a subsequent appeal for review by the panel of judges, who dismissed the appeal. The Municipality of Jandira filed a subsequent appeal to standardize the internal ruling of the Superior Court of Justice. The reporting judge determined the suspension of the appeal until the Superior Court of Justice decides the leading cases about the same matter. As of December 31, 2021 the amount involved in the fines was ThBRL 30,100 (ThUS$ 5,404).

- The Municipality of Sao Paulo imposed a fine on Enel Distribución São Paulo for violation of municipal traffic laws involving a restricted area of circulation. The company’s administrative defenses against the fines were decided unfavorably to the company. In 2011, the company filed a lawsuit seeking the nullification of the fine. The first instance ruling was unfavorable to the company, which filed an appeal, which is pending. As of December 31, 2021, the amount involved in the fines was ThBRL 41,370 (ThUS$ 7,428).

- In February 2012, the Municipality of Itapevi imposed a fine on Enel Distribución São Paulo for violation of municipal laws with respect to the road network in the municipality. The company’s administrative defenses against the fines were decided unfavorably to the company. The company filed a lawsuit seeking the nullification of the fine. The first and second instance rulings were unfavorable to the company, which filed appeals with the Superior Court of Justice and the Federal Supreme Court, both of which were dismissed in August 2021. The City Council of the Municipality of Itapevi has filed a request for payment of the amounts. In parallel, the Brazilian Association of Electric Energy Distributors (ABRADEE) filed a direct action of unconstitutionality (ADIN) against the municipal legislation that created the fines and the Court of Justice of the State of São Paulo suspended the effects of the municipal legislation by means of a preliminary injunction. The lawsuit is suspended until a final decision on the ADIN. As of December 31, 2021, the amount involved in the fines was ThBRL 31,300 (ThUS$ 5,619).

Tax sanctions

- The Brazilian Tax Authority imposed a fine on Enel Distribución São Paulo after denying the authorization to offset federal taxes. Individual fines have been imposed on the company for 50% of the compensation requested. The company filed its administrative defense against the fines and is awaiting a ruling. As of December 31, 2021, the amount involved in the fines was ThBRL 71,397 (ThUS$ 12,818).

5. Apiacás Energia S.A.

Environmental sanctions

- On October 1, 2020, Apiacás Energia S.A. was notified of 2 sanctions imposed by the municipal environmental body of Chapada dos Guimarães, in the State of Mato Grosso for alleged non-compliance with the obligation to release and repopulate fry from the Casca II and Casca III hydroelectric plants. On October 21, 2020, the company filed its administrative defense. In November 2021, the judicial collection of the fine was initiated before the settlement received by the Casca III hydroelectric plant in the amount of ThBRL 53,810 (ThUS$9,661). As of December 31, 2021, the amount involved on the two fines was ThBRL 92,250 (ThUS$16,562).

6. Enel Generación Perú S.A.A. (Formerly Edegel S.A.A.)

Tax sanctions

As of December 31, 2021, Enel Generación Perú S.A.A. has incurred the following tax fines:

F-185

- As part of a corporate tax audit procedure for the 1999 fiscal year, SUNAT issued Fine Resolution No. 0120020004919 to the company by means of which it imposed a fine of ThPEN 2,077 (ThUS$520) by way of annual corporate income tax, whose default interest as of the payment date amounted to ThPEN 10,502 (ThUS$ 2,629). The imposition of this penalty is being challenged in the judicial courts.

- As part of a corporate tax audit procedure for the 2000 and 2001 fiscal years, SUNAT issued Fine Resolution No. 0120020008723 to the company by means of which it imposed a fine by way of annual corporate income tax for the year 2000. Considering several payments made and the reassessment made by SUNAT, to date, this penalty qualifies as probable and amounts to ThPEN 3,915 (ThUS$ 980), and the default interest to date amounts to ThPEN 5,710 (ThUS$ 1,429). The company is currently waiting for SUNAT to offset the amount of this tax debt against the credits recognized by the Tax Court.

- As part of an audit procedure for the Ad Valorem General Sales Tax (IGV) and Municipal Promotion Tax (IPM) on imports for 2008 and 2009, SUNAT issued Division Resolution No. 0003X4100/2013-000440 to Banco Scotiabank del Perú (legal owner of Central Santa Rosa under a finance lease agreement, whereby the company is responsible for all contingencies arising therefrom), whereby a fine amounting to ThUS$ 2,974 was imposed (the customs fines were paid in U.S. dollars). The imposition of this fine is being challenged in the judicial courts, for which ThPEN 5,832 (ThUS$ 1,459) had to be paid, the default interest of which, to date, amounted to ThPEN 3,395 (ThUS$ 850). The full amount of the tax debt related to the aforementioned fine was not paid, since part of it was barred by the statute of limitations.

7. Enel Perú S.A.C. (Formerly Generandes Perú)

Tax sanctions

As of December 31, 2021, Enel Perú had incurred the following tax fine:

- As part of an audit procedure for corporate tax and IGV for fiscal year 2000, SUNAT issued a Fine Resolution to the company by means of which it imposed a fine of PEN 2,920,104 (ThUS$ 731) by way of annual corporate income tax and whose default interest as of the payment date amounted to PEN 14,053,695 (ThUS$ 3,885). Similarly, SUNAT issued a Fine Resolution to the company by means of which it imposed fines of ThPEN 1,772 (ThUS$ 518) for the improper application of the IGV for the periods of April, June and October 2000, which total ThPEN 1,772 (ThUS$444), whose default interest as of the payment date amounted to ThPEN 10,231 (ThUS$ 2,561). The imposition of these penalties is being challenged in the judicial courts.

8. Enel Generación Piura (Formerly EEPSA)

Tax sanctions

As of December 31, 2021, Enel Generación Piura has incurred the following tax fine:

- As part of a tax audit procedure for the IGV and IPM on imports for the 2011 fiscal year, SUNAT issued a Fine Resolution to the company by means of which it imposed a penalty of ThPEN 6,868 (ThUS$ 1,719), whose current default interest to date amounts to ThPEN 4,844 (ThUS$ 1,212). Note that the imposition of this penalty is being challenged in the judicial courts.

- As part of the audit procedure for the IGV and IPM on imports for 2016, SUNAT issued Division Resolution No. 253-2020-SUNAT-323100 to Banco Scotiabank del Perú (legal owner of the Power Replacement Project of the Malacas Power Station - Unit TG6, under a finance lease agreement, whereby the company is responsible for all contingencies arising therefrom), whereby it imposed a fine amounting to ThPEN 4,552 (ThUS$ 1,140), which was paid with a 60% reduction: (i) fine of ThPEN 1,821 (ThUS$ 456) ; and (ii) default interest of PEN 1,165,075 (ThUS$ 292), as of the date of payment. The imposition of the aforementioned fine is being challenged before the Tax Court.

F-186

In relation to the sanctions described above, the Group has established provisions for ThUS$ 43,887 as of December 31, 2021 (see Note 24). There are other sanctions that also have associated provisions but they are not described in this note, since they individually represent immaterial amounts. Management believes that the provisions recorded adequately cover the risks due to penalties, Therefore, they do not expect additional liabilities to arise from those already registered.

F-187

37. ENVIRONMENT

Environmental expenses for the years ended December 31, 2021, 2020 and 2019 are as follows:

				12-31-2021						12-31-2020
Disbursing Company	Project Name	Environmental Description	Project Status [Finished, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements	Amount of prior period disbursement
Emgesa S.A. E.S.P.	El Quimbo Hydroelectric Power Plant Project	Monitoring & hydrometeorological studies	In progress	343	—	343	—	12-31-2022	343	480
		Law 99	In progress	—	—	—	4,268	12-31-2022	4,268	4,221
Empresa Distribuidora Sur S.A.	Polluting material	Handling of Polluting Material	In progress	87	—	87	—		87	74
	Pcbs Decommissioning	Under Law 1196 of 2008, Colombia adopted the Stockholm Convention and this was regulated with the Ministry of the Environment’s Resolution 222 of December 15, 2011, recognizing the provision for the decommissioning of transformers contaminated with PCBs.	In progress	272	267	5	5,623	12-31-2027	5,896	7,716
Compañía Distribuidora y Comercializadora de Energía S.A.	Nueva Esperanza Environmental Compensation	Compensations included in Resolution 1061 and Agreement 017 of  2013 issued by the Ministry of the Environment and the Autonomous Regional Corporation of  Cundinamarca, respectively, which approves the substitution of the protecting and producing forestry reserve of the upper basin of the Bogota River, committing the Company to undertaking a compensation and reforestation plan in the construction zone of the Nueva Esperanza, Gran Sabana and Compartir substations	In progress	84	82	2	240	12-31-2022	324	391
	Prevention Activities	Protection of environmental biodiversity, treatment of waste waters Studies of environmental aspects	Finished	334	—	334	—		334	223
	Environmental Studies	Studies of environmental aspects	Finished	52	—	52	—		52	103
Enel Generación Perú S.A.	Waste Management	Handling of hazardous waste	Finished	189	—	189	—		189	204
	Environmental Monitoring	Protection of the air and climate, noise reduction, protection against radiation	Finished	172	—	172	—		172	111
	Landscaping and Green Areas	Maintaining green areas and small fauna	Finished	79	—	79	—		79	89
	Legal Services	Legal Services	Finished	3	—	3	—		3	—
	Mitigation and Restoration	Protection and recovery of soil and water	Finished	—	—	-	—		—	—
	Prevention Activities	Protection of environmental biodiversity, treatment of waste waters	Finished	38	—	38	—		38	55
	Environmental Studies	Environmental aspect studies	Finished	40	—	40	—		40	22
Enel Generación Piura S.A.	Waste Management	Handling of hazardous waste	Finished	31	—	31	—		31	37
	Environmental Monitoring	Protection of the air and climate, noise reduction	Finished	52	—	52	—		52	28
	Landscaping and Green Areas	Maintaining green areas and small fauna	Finished	43	—	43	—		43	42
	Prevention Activities	Protection of the air and climate, noise reduction, protection against radiation	Finished	33	—	33	—		33	72
	Environmental Studies	Environmental aspect studies	Finished	5	—	5	—		5	31
Chinango S.A.C.	Waste Management	Handling of hazardous waste	Finished	17	—	17	—		17	115
	Environmental Monitoring	Protection of the air and climate, noise reduction, protection against radiation	Finished	265	—	265	—		265	108
Total				2,139	349	1,790	10,131		12,271	14,122

F-188

				12-31-2020
Disbursing Company	Project Name	Environmental Description	Project Status [Finished, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements
		Monitoring & hydrometeorological studies	In progress	480	—	480	—		480
Emgesa S.A. E.S.P.	El Quimbo Hydroelectric Power Plant Project	Others	In progress	276	—	276	—		276
		Law 99	In progress	—	—	—	4,221	12-31-2022	4,221
Empresa Distribuidora Sur S.A.	Polluting material	Handling of Polluting Material	In progress	74	—	74	—		74
	Pcbs Decommissioning	Under Law 1196 of 2008, Colombia adopted the Stockholm Convention and this was regulated with the Ministry of the Environment’s Resolution 222 of December 15, 2011, recognizing the provision for the decommissioning of transformers contaminated with PCBs.	In progress	2,341	2,180	161	5,375	12-31-2027	7,716
Compañía Distribuidora y Comercializadora de Energía S.A.	Nueva Esperanza Environmental Compensation	Compensations included in Resolution 1061 and Agreement 017 of  2013 issued by the Ministry of the Environment and the Autonomous Regional Corporation of  Cundinamarca, respectively, which approves the substitution of the protecting and producing forestry reserve of the upper basin of the Bogota River, committing the Company to undertaking a compensation and reforestation plan in the construction zone of the Nueva Esperanza, Gran Sabana and Compartir substations	In progress	83	83	—	309	12-31-2022	392
	Prevention Activities	Protection of environmental biodiversity, treatment of waste waters Studies of environmental aspects	Finished	223	—	223	—		222
	Environmental Studies	Studies of environmental aspects	Finished	103	—	103	—		103
Enel Generación Perú S.A.	Waste Management	Handling of hazardous waste	Finished	204	—	204	—		204
	Mitigation and Restoration	Protection and recovery of soil and water	Finished	6	—	6	—		6
	Environmental Monitoring	Protection of the air and climate, noise reduction, protection against radiation	Finished	111	—	111	—		111
	Landscaping and Green Areas	Maintaining green areas and small fauna	Finished	89	—	89	—		89
	Prevention Activities	Protection of environmental biodiversity, treatment of waste waters	Finished	55	—	55	—		55
	Environmental Studies	Environmental aspect studies	Finished	22	—	22	—		22
Enel Generación Piura S.A.	Waste Management	Handling of hazardous waste	Finished	37	—	37	—		37
	Environmental Monitoring	Protection of the air and climate, noise reduction	Finished	28	—	28	—		28
	Landscaping and Green Areas	Maintaining green areas and small fauna	Finished	42	—	42	—		42
	Environmental Studies	Environmental aspect studies	Finished	72	—	72	—		72
	Waste Management	Handling of hazardous waste	Finished	31	—	31	—		31
Chinango S.A.C.	Environmental Monitoring	Protection of the air and climate, noise reduction, protection against radiation	Finished	115	—	115	—		115
	Mitigations & Restorations	Protection and Recovery of Soil and Water	Finished	7	—	7	—		7
	Environmental monitoring	Air and climate protection, noise reduction, radiation protection	Finished	108	—	108	—		108
Total				4,506	2,263	2,243	9,904		14,411

F-189

				12-31-2019
Disbursing Company	Project Name	Environmental Description	Project Status [Finished, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements
		Monitoring & hydrometeorological studies	In progress	522	—	522	—		522
Emgesa S.A. E.S.P.	Central Hidroelectrica El Quimbo	Other	In progress	208	—	208	—		208
	Project	Law 99	In progress	—	—	—	4,588	12-31-2021	4,588
Empresa Distribuidora Sur S.A.	Polluting material	Handling of Polluting Material	In progress	133	—	133	—		133
	Pcbs Decommissioning	Under Law 1196 of 2008, Colombia adopted the Stockholm Convention and this was regulated with the Ministry of the Environment’s Resolution 222 of December 15, 2011, recognizing the provision for the decommissioning of transformers contaminated with PCBs.	In progress	1,693	1,399	294	6,145	12-31-2027	7,838
Compañía Distribuidora y Comercializadora de Energía S.A.	Nueva Esperanza Environmental Compensation	Compensations included in Resolution 1061 and Agreement 017 of  2013 issued by the Ministry of the Environment and the Autonomous Regional Corporation of  Cundinamarca, respectively, which approves the substitution of the protecting and producing forestry reserve of the upper basin of the Bogota River, committing the Company to undertaking a compensation and reforestation plan in the construction zone of the Nueva Esperanza, Gran Sabana and Compartir substations	In progress	203	189	15	105	12-31-2019	308
	Prevention Activities	Protection of environmental biodiversity, treatment of waste waters	In progress	78	—	78	—		78
	Environmental Studies	Environmental aspect studies	In progress	116	—	116	—		116
	Waste Management	Handling of hazardous waste	In progress	342	—	342	—		342
Enel Generación Perú S.A.	Mitigation and Restoration	Protection and recovery of soil and water	In progress	29	—	29	—		29
	Environmental Monitoring	Protection of the air and climate, noise reduction, protection against radiation	In progress	86	—	86	—		86
	Landscaping and Green Areas	Maintaining green areas and small fauna	In progress	90	—	90	—		90
	Prevention Activities	Protection of environmental biodiversity, treatment of waste waters	In progress	35	—	35	—		35
	Environmental Studies	Environmental aspect studies	In progress	29	—	29	—		29
Enel Generación Piura S.A.	Waste Management	Handling of hazardous waste	In progress	76	—	76	—		76
	Environmental Monitoring	Protection of the air and climate, noise reduction.	In progress	42	—	42	—		42
	Landscaping and Green Areas	Maintaining green areas and small fauna	In progress	49	—	49	—		49
	Environmental Studies	Environmental aspect studies	In progress	24	—	24	—		24
	Waste Management	Handling of hazardous waste	In progress	53	—	53	—		53
Chinango S.A.C.	Mitigation and Restoration	Protection and recovery of soil and water	In progress	19	—	19	—		19
	Environmental Monitoring	Protection of the air and climate, noise reduction, protection against radiation	In progress	277	—	277	—		277
Enel Distribución S.A.	Waste Management	Elimination of particles and other special waste	Completed	243	—	243	—		243
Total				4,347	1,588	2,760	10,838		15,185

F-190

38. FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED

As of and December 31, 2021, 2020 and 2019, summarized financial information of our main subsidiaries prepared under IFRS is as follows:

	12-31-2021
	Financial Statements	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non- Current Liabilities	Equity	Total Liabilities and Equity	Revenue	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income Before Taxes		Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
Enel Argentina S.A.	Separate	6,684	464,053	470,737	234	—	470,503	470,737	—	(481)	(481)	(2,321)	(2,376)	(7,959)	40,593		(1,167)	39,426	2,367	41,793
Enel Generación Costanera S.A.	Separate	98,322	214,098	312,420	103,366	48,267	160,787	312,420	105,074	(4,698)	100,376	53,487	(85,458)	8,782	(75,119)		14,352	(60,767)	(32,536)	(93,303)
Enel Generación El Chocón S.A.	Separate	90,473	227,094	317,567	15,831	54,753	246,983	317,567	41,540	(3,787)	37,753	27,188	10,081	(26,108)	(15,000)		(5,414)	(20,414)	(44,420)	(64,834)
Empresa Distribuidora Sur S.A.	Separate	272,120	1,887,184	2,159,304	902,066	558,266	698,972	2,159,304	793,771	(528,448)	265,323	22,631	(68,632)	28,590	(40,010)		(138,481)	(178,491)	(128,698)	(307,189)
Enel Trading Argentina S.R.L ​	Separate	15,049	1,585	16,634	13,676	—	2,958	16,634	1,613	(60)	1,553	(721)	(902)	(555)	(1,456)		—	(1,456)	(647)	(2,103)
Dock Sud S.A.	Separate	134,881	165,382	300,263	15,407	26,196	258,660	300,263	79,637	(8,783)	70,854	55,096	23,190	(27,150)	(3,960)		(3,078)	(7,038)	(37,686)	(44,724)
Grupo Enel Argentina	Consolidated	258,643	751,345	1,009,988	117,486	103,021	789,481	1,009,988	146,282	(10,581)	135,701	76,676	(85,023)	(47,245)	(207,280)		6,960	(200,320)	(133,351)	(333,671)
Grupo EGP Brasil	Consolidated	317,994	3,656,821	3,974,815	627,146	592,180	2,755,489	3,974,815	538,380	(293,468)	244,912	199,332	134,891	(44,388)	90,507		(23,533)	66,974	367,175	434,149
Enel Generación Fortaleza S.A.	Separate	107,101	118,995	226,096	63,916	254	161,926	226,096	326,889	(209,590)	117,299	107,714	97,079	1,848	98,927		(32,524)	66,403	(7,431)	58,972
EGP Cachoeira Dourada S.A.	Separate	262,713	112,859	375,572	247,881	47,416	80,275	375,572	1,428,553	(1,351,052)	77,501	64,205	51,686	(43,147)	8,539		(3,077)	5,462	(4,088)	1,374
EGP Volta Grande	Separate	27,698	275,045	302,743	28,297	134,477	139,969	302,743	81,056	(13,624)	67,432	63,608	63,458	(19,344)	44,114		(14,116)	29,998	(8,874)	21,124
Enel Cien S.A.	Separate	27,289	126,169	153,458	15,518	239	137,701	153,458	54,619	(14)	54,605	47,255	41,826	926	42,752		(14,113)	28,639	(8,636)	20,003
Compañía de Transmisión del Mercosur S.A.	Separate	2,554	3,857	6,411	170	4,605	1,636	6,411	481	—	481	(56)	(560)	3,838	3,277		(4,373)	(1,096)	(399)	(1,495)
Transportadora de Energía S.A.	Separate	1,984	5,955	7,939	273	149	7,517	7,939	487	—	487	(109)	(1,980)	2,818	838		751	1,589	(884)	705
Enel Distribución Ceará S.A.	Separate	709,815	1,396,726	2,106,541	649,178	805,148	652,215	2,106,541	1,511,849	(1,099,328)	412,521	280,045	168,549	(49,867)	119,092		(27,906)	91,186	(41,696)	49,490
Enel Distribución Rio S.A.	Separate	780,471	2,205,682	2,986,153	1,045,797	1,255,747	684,609	2,986,153	1,581,080	(1,147,521)	433,559	282,304	98,040	(78,981)	19,179		(3,027)	16,152	(37,703)	(21,551)
Enel Distribución Goiás S.A.	Separate	870,735	2,613,350	3,484,085	1,182,729	1,239,900	1,061,456	3,484,085	1,820,216	(1,468,987)	351,229	162,818	55,439	(83,657)	(27,959)		5,999	(21,960)	(71,438)	(93,398)
Enel X Brasil S.A.	Separate	41,242	36,962	78,204	32,759	771	44,674	78,204	17,471	(5,925)	11,546	(2,806)	(2,920)	51	(2,869)		3,427	558	(2,239)	(1,681)
Enel Distribuicao Sao Paulo S.A.	Separate	1,680,174	4,994,713	6,674,887	1,604,168	3,972,867	1,097,852	6,674,887	3,848,367	(2,857,634)	990,733	706,896	431,456	(156,850)	274,607		(77,987)	196,620	(107,521)	89,099
Grupo Enel Brasil	Consolidated	4,810,195	16,362,724	21,172,919	4,981,114	8,554,845	7,636,960	21,172,919	10,970,586	(8,316,744)	2,653,842	1,791,111	1,061,569	(430,128)	631,964		(167,187)	464,777	(459,066)	5,711
Emgesa S.A. E.S.P.	Separate	163,479	2,056,524	2,220,003	371,669	595,042	1,253,292	2,220,003	1,262,495	(409,074)	853,421	788,778	721,673	(47,100)	674,639	��	(217,507)	457,132	(228,708)	228,424
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	420,427	1,811,019	2,231,446	550,502	887,338	793,606	2,231,446	1,706,529	(1,011,914)	694,615	554,576	418,138	(54,584)	364,128		(107,270)	256,858	(136,905)	119,953
Enel Perú S.A.C.	Separate	38,474	1,074,700	1,113,174	160,808	—	952,366	1,113,174	—	—	—	(547)	(2,505)	(2,646)	208,633		(161)	208,472	(73,523)	134,949
Enel Generación Perú S.A.	Separate	193,318	836,620	1,029,938	202,454	212,314	615,170	1,029,938	430,578	(150,735)	279,843	223,756	185,249	5,025	205,952		(58,121)	147,831	(56,161)	91,670
Chinango S.A.C.	Separate	11,011	131,687	142,698	5,229	36,288	101,181	142,698	46,927	(4,837)	42,090	37,273	33,863	86	33,949		(9,990)	23,959	(7,626)	16,333
Enel Generación Piura S.A.	Separate	41,703	149,223	190,926	23,527	60,834	106,565	190,926	74,242	(23,569)	50,673	41,269	31,196	(5,315)	25,881		(8,109)	17,772	(8,218)	9,554
Enel Distribución Perú S.A.	Separate	208,451	1,237,600	1,446,051	315,498	435,640	694,913	1,446,051	895,367	(604,987)	290,380	218,993	154,164	(21,604)	132,586		(47,413)	85,173	(64,160)	21,013
Grupo Enel Perú	Consolidated	457,824	2,284,464	2,742,288	679,706	732,624	1,329,958	2,742,288	1,286,952	(651,370)	635,582	500,382	381,992	(24,677)	357,340		(117,996)	239,344	(112,424)	126,920
Enel Green Power Colombia S.A.S Esp	Separate	28,486	381,808	410,294	77,666	18,672	313,956	410,294	27,902	(23,733)	4,169	(1,721)	(4,324)	2,393	(1,932)		1,272	(659)	(6,118)	(6,778)
Enel Green Power Costa Rica S.A.	Separate	44,186	108,554	152,740	6,100	—	146,640	152,740	2,955	—	2,955	426	268	1,045	1,313		(67)	1,246	—	1,246
PH Chucas S.A.	Separate	6,621	167,709	174,330	83,123	55,985	35,222	174,330	14,513	—	14,513	10,507	6,455	(2,974)	3,481		(56)	3,425	—	3,425
Enel Green Power Guatemala S.A.	Separate	9,331	2,225	11,556	12,253	254	(951)	11,556	48,821	(41,766)	7,055	1,088	833	(149)	732		(207)	525	—	525
Generadora de Occidente Ltda.	Separate	47,367	36,068	83,435	1,380	3,056	78,999	83,435	12,300	(1,345)	10,955	8,034	7,072	(191)	6,888		(906)	5,982	—	5,982
Generadora Montecristo S.A.	Separate	92,338	19,720	112,058	80,495	9,287	22,276	112,058	1,300	70	1,370	(139)	(576)	(76)	(645)		(238)	(883)	—	(883)
Renovables de Guatemala S.A.	Separate	46,489	326,025	372,514	3,688	—	368,826	372,514	39,604	(6,986)	32,618	25,188	18,715	(2)	18,743		(543)	18,200	—	18,200
Tecnoguat S.A.	Separate	1,071	16,460	17,531	429	—	17,102	17,531	3,388	(361)	3,027	1,776	1,250	21	1,284		(223)	1,061	—	1,061
Transmisora de Energia Renovable S.A.	Separate	15,522	22,005	37,527	640	—	36,887	37,527	2,196	(51)	2,145	1,693	1,112	(7)	1,104		(158)	946	—	946
Enel Green Power Panama S.A.	Separate	181,759	216,064	397,823	138,733	33,765	225,325	397,823	4,921	(484)	4,437	1,756	1,409	529	33,162		(3,259)	29,903	—	29,903
Enel Fortuna S.A.	Separate	176,198	367,868	544,066	17,879	39,805	486,382	544,066	135,202	(19,318)	115,884	102,333	92,745	967	93,712		(27,055)	66,657	—	66,657
Enel Solar S.R.L	Separate	2,732	68,919	71,651	53,048	3,230	15,373	71,651	7,461	(734)	6,727	5,389	2,487	(1,383)	1,104		(309)	795	—	795
Enel Green Power Peru S.A.	Separate	123,483	380,781	504,264	71,765	176,945	255,554	504,264	33,000	(2,906)	30,093	21,361	12,338	(5,151)	7,187		(7,755)	(568)	(810)	(1,377)

	12-31-2020
	Financial Statements	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non- Current Liabilities	Equity	Total Liabilities and Equity	Revenue	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income Before Taxes	Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
Enel Argentina S.A.	Separate	40,432	65,563	105,995	1,293	—	104,702	105,995	—	(600)	(600)	(2,459)	(2,459)	11,264	12,146	874	13,020	(37,029)	(24,009)
Enel Generación Costanera S.A.	Separate	96,321	253,484	349,805	96,132	74,375	179,298	349,805	112,931	(4,963)	107,968	60,965	18,811	(9,445)	9,497	7,928	17,425	(47,631)	(30,206)
Enel Generación El Chocón S.A.	Separate	91,441	268,572	360,013	30,857	43,537	285,619	360,013	48,505	(4,543)	43,962	35,964	21,800	37,910	62,211	(9,332)	52,879	(66,592)	(13,713)
Empresa Distribuidora Sur S.A.	Separate	274,169	1,442,360	1,716,529	591,523	415,191	709,815	1,716,529	801,229	(530,338)	270,891	49,912	(68,276)	22,605	(45,636)	(22,866)	(68,502)	(230,171)	(298,673)
Enel Trading Argentina S.R.L.	Separate	12,882	1,263	14,145	10,573	—	3,572	14,145	3,086	(189)	2,897	706	414	(130)	284	(103)	181	(1,006)	(825)
Dock Sud S.A.	Separate	97,880	172,641	270,521	10,749	28,575	231,197	270,521	66,334	(10,025)	56,309	42,590	14,445	3,472	17,968	(13,426)	4,542	(68,182)	(63,640)
Grupo Enel Argentina	Consolidated	312,760	841,974	1,154,734	124,270	115,750	914,714	1,154,734	161,093	(11,572)	149,521	92,860	36,542	61,778	71,522	1,130	72,652	(258,557)	(185,905)
Enel Brasil S.A.	Separate	567,492	4,484,221	5,051,713	344,060	225,338	4,482,315	5,051,713	502	(139)	363	(41,809)	(42,724)	(127,544)	168,090	36,441	204,531	(1,088,424)	(883,893)
Enel Generación Fortaleza S.A.	Separate	76,390	133,672	210,062	52,283	19,535	138,244	210,062	187,227	(118,673)	68,554	61,986	51,176	(521)	50,655	(19,628)	31,027	(31,881)	(854)
EGP Cachoeira Dourada S.A.	Separate	584,030	130,285	714,315	563,242	20,520	130,553	714,315	812,275	(666,295)	145,980	134,715	129,601	(6,103)	123,498	(41,504)	81,994	(15,502)	66,492
EGP Volta Grande	Separate	31,525	274,019	305,544	31,433	138,557	135,554	305,544	62,398	(10,548)	51,850	48,505	48,484	(11,785)	36,700	(12,486)	24,214	(32,034)	(7,820)
Enel Cien S.A.	Separate	31,496	141,069	172,565	17,527	407	154,631	172,565	52,705	(83,694)	(30,989)	(37,406)	(45,046)	23,435	(21,612)	7,275	(14,337)	(48,724)	(63,061)
Compañía de Transmisión del Mercosur S.A.	Separate	2,554	10,089	12,643	10,443	—	2,200	12,643	45,439	—	45,439	44,911	44,472	(17,275)	27,197	(996)	26,201	14,795	40,996
Transportadora de Energía S.A.	Separate	2,144	11,705	13,849	8,490	482	4,877	13,849	37,973	—	37,973	37,284	35,806	(13,356)	22,450	801	23,251	15,236	38,487
Enel Distribución Ceará S.A.	Separate	575,851	1,322,709	1,898,560	589,631	651,669	657,260	1,898,560	1,166,240	(835,325)	330,915	191,873	98,900	(29,125)	70,014	(18,464)	51,550	(178,829)	(127,279)
Enel Distribución Rio S.A.	Separate	705,578	1,588,563	2,294,141	574,409	1,011,309	708,423	2,294,141	1,253,027	(869,354)	383,673	231,938	94,515	(78,528)	16,145	(5,706)	10,439	(229,670)	(219,231)
Enel Distribución Goiás S.A.	Separate	566,168	2,032,002	2,598,170	925,334	517,983	1,154,853	2,598,170	1,394,049	(1,026,859)	367,190	169,277	85,106	(42,774)	42,806	(16,729)	26,077	(306,258)	(280,181)
Enel X Brasil S.A.	Separate	19,617	22,477	42,094	20,560	583	20,951	42,094	13,357	(4,454)	8,903	(3,705)	(6,711)	(2,009)	(8,720)	973	(7,747)	(4,323)	(12,070)
Enel Distribuicao Sao Paulo S.A.	Separate	1,515,162	5,198,704	6,713,866	1,614,149	3,852,132	1,247,585	6,713,866	3,020,740	(2,206,107)	814,633	592,998	374,091	(116,943)	257,148	(77,974)	179,174	(677,886)	(498,712)
Grupo Enel Brasil	Consolidated	4,143,213	11,396,553	15,539,766	4,211,671	6,169,465	5,158,630	15,539,766	7,680,106	(5,450,909)	2,229,197	1,436,985	873,753	(420,461)	454,162	(148,157)	306,005	(1,678,028)	(1,372,023)
Emgesa S.A. E.S.P.	Separate	353,946	2,420,483	2,774,429	570,718	697,179	1,506,532	2,774,429	1,159,134	(412,530)	746,604	673,446	606,868	(70,522)	536,449	(188,883)	347,566	(19,348)	328,218
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	499,983	1,973,507	2,473,490	640,774	840,051	992,665	2,473,490	1,546,963	(886,155)	660,808	506,794	375,127	(49,171)	325,977	(97,881)	228,096	(14,970)	213,126
Enel Perú, S.A.C.	Separate	34,757	1,288,805	1,323,562	180,490	10,990	1,132,082	1,323,562	—	—	—	(215)	(215)	(6,072)	156,138	—	156,138	(96,339)	59,799
Enel Generación Perú S.A.A.	Separate	315,244	880,207	1,195,451	191,039	208,495	795,917	1,195,451	408,604	(140,350)	268,254	210,702	162,140	10,361	186,817	(42,052)	144,765	(66,777)	77,988
Chinango S.A.C.	Separate	8,892	131,158	140,050	7,061	26,392	106,597	140,050	41,000	(4,496)	36,504	31,273	27,319	(87)	27,232	(8,152)	19,080	(8,334)	10,746
Enel Generación Piura S.A.	Separate	60,425	164,399	224,824	58,135	24,746	141,943	224,824	63,874	(23,435)	40,439	30,016	18,512	(4,873)	17,249	(5,852)	11,397	(12,361)	(964)
Enel Distribución Perú S.A.A.	Separate	191,178	1,263,496	1,454,674	249,068	471,377	734,229	1,454,674	886,663	(598,157)	288,506	213,898	141,464	(25,042)	116,427	(38,488)	77,939	(62,468)	15,471
Grupo Enel Perú	Consolidated	546,260	2,382,886	2,929,146	627,532	734,466	1,567,148	2,929,146	1,243,994	(621,907)	622,087	475,905	339,421	(26,007)	317,029	(91,896)	225,133	(246,279)	(21,146)

F-191

	12-31-2019
	Financial Statements	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non- Current Liabilities	Equity	Total Liabilities and Equity	Revenue	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income Before Taxes	Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
Enel Argentina S.A.	Separate	43,219	87,644	130,863	2,152	—	128,711	130,863	—	—	—	(463)	(463)	8,963	39,714	(2,453)	37,261	(53,938)	(16,677)
Enel Generación Costanera S.A.	Separate	113,909	270,423	384,332	112,412	105,047	166,873	384,332	213,606	(68,969)	144,637	100,244	59,860	22,628	82,582	(24,642)	57,940	(41,288)	16,652
Enel Generación El Chocón S.A.	Separate	101,114	315,842	416,956	75,003	56,983	284,970	416,956	71,807	(5,957)	65,850	58,055	42,906	59,477	103,800	(21,770)	82,030	(70,096)	11,934
Empresa Distribuidora Sur S.A.	Separate	284,126	1,456,918	1,741,044	509,223	429,766	802,055	1,741,044	1,346,888	(773,693)	573,195	307,066	211,031	54,470	265,560	(76,548)	189,012	(237,185)	(48,173)
Enel Trading Argentina S.R.L.	Separate	23,432	1,551	24,983	21,486	—	3,497	24,983	7,497	(950)	6,547	3,599	3,321	(92)	3,229	(1,295)	1,934	(600)	1,334
Dock Sud S.A.	Separate	105,726	256,881	362,607	52,678	52,732	257,197	362,607	146,958	(54,326)	92,632	81,806	50,775	12,036	63,132	(1,007)	62,125	(74,649)	(12,524)
Grupo Enel Argentina	Consolidated	326,191	927,948	1,254,139	185,096	151,167	917,876	1,254,139	285,277	(74,927)	210,350	157,774	102,242	112,784	299,022	(54,044)	244,978	(270,493)	(25,515)
Enel Brasil S.A.	Separate	371,174	5,186,673	5,557,847	145,721	376,140	5,035,986	5,557,847	977	(85)	892	(57,320)	(58,076)	(85,784)	88,858	15,025	103,883	(149,216)	(45,333)
Enel Generación Fortaleza S.A.	Separate	119,719	193,438	313,157	108,806	737	203,614	313,157	309,525	(183,394)	126,131	114,170	99,940	13,389	113,329	(36,130)	77,199	(5,465)	71,734
EGP Cachoeira Dourada S.A.	Separate	213,201	98,107	311,308	193,295	3,280	114,733	311,308	494,303	(394,776)	99,527	85,746	79,065	(100)	78,965	(25,671)	53,294	2,285	55,579
EGP Volta Grande	Separate	42,230	345,708	387,938	29,751	185,505	172,682	387,938	106,792	(42,895)	63,897	59,632	59,607	(13,583)	46,024	(15,173)	30,851	(844)	30,007
Enel Cien S.A.	Separate	113,996	151,707	265,703	13,358	16,240	236,105	265,703	70,295	(967)	69,328	61,376	49,598	19,722	69,320	(39,773)	29,547	(4,600)	24,947
Compañía de Transmisión del Mercosur S.A.	Separate	6,856	701	7,557	50,954	8,030	(51,427)	7,557	1,142	—	1,142	789	(530)	(10,469)	(10,999)	296	(10,703)	15,634	4,931
Transportadora de Energía S.A.	Separate	4,914	3,924	8,838	52,590	9,207	(52,959)	8,838	1,112	—	1,112	601	(923)	(10,288)	(11,212)	333	(10,879)	16,154	5,275
Enel Distribución Ceará S.A.	Separate	629,655	1,624,665	2,254,320	525,921	902,000	826,399	2,254,320	1,397,853	(991,979)	405,874	248,917	165,346	(42,897)	122,937	(19,875)	103,062	(26,723)	76,339
Enel Distribución Rio S.A.	Separate	722,394	1,962,608	2,685,002	910,507	830,069	944,426	2,685,002	1,526,019	(1,029,220)	496,799	310,962	175,012	(67,167)	109,105	(37,009)	72,096	(46,182)	25,914
Enel Distribución Goiás S.A.	Separate	665,187	2,355,246	3,020,433	795,562	903,997	1,320,874	3,020,433	1,546,302	(1,100,077)	446,225	221,433	23,971	(61,111)	(36,744)	11,462	(25,282)	(59,597)	(84,879)
Enel X Brasil S.A.	Separate	17,886	15,089	32,975	13,676	307	18,992	32,975	19,359	(6,434)	12,925	(1,373)	(4,677)	(311)	(4,988)	539	(4,449)	(679)	(5,128)
Enel Distribuicao Sao Paulo S.A.	Separate	1,701,300	6,062,310	7,763,610	1,474,482	4,310,495	1,978,633	7,763,610	3,756,890	(2,699,108)	1,057,782	674,604	414,699	(136,943)	277,756	460,335	738,091	(412,571)	325,520
Grupo Enel Brasil	Consolidated	4,211,380	13,471,236	17,682,616	3,919,122	7,528,800	6,234,694	17,682,616	8,684,491	(5,906,735)	2,777,756	1,718,861	1,002,297	(430,285)	574,154	314,359	888,513	(559,512)	329,001
Emgesa S.A. E.S.P.	Separate	251,413	2,524,074	2,775,487	387,804	943,882	1,443,801	2,775,487	1,246,989	(465,768)	781,221	710,320	637,221	(81,785)	555,672	(180,207)	375,465	7,209	382,674
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	363,838	1,842,861	2,206,699	545,689	704,527	956,483	2,206,699	1,665,318	(962,174)	703,144	556,513	431,004	(58,397)	372,680	(122,066)	250,614	(615)	249,999
Enel Perú, S.A.C.	Separate	37,589	1,403,189	1,440,778	41,359	10,868	1,388,551	1,440,778	11	—	11	(1,155)	(1,155)	(1,473)	127,289	(8)	127,281	27,105	154,386
Enel Generación Perú S.A.A.	Separate	361,697	974,784	1,336,481	172,150	259,367	904,964	1,336,481	478,155	(178,102)	300,053	243,359	191,690	(4,886)	200,977	(56,340)	144,637	18,483	163,120
Chinango S.A.C.	Separate	6,346	153,370	159,716	6,349	38,766	114,601	159,716	45,030	(5,081)	39,949	34,113	29,868	(723)	29,145	(8,685)	20,460	2,791	23,251
Enel Generación Piura S.A.	Separate	75,118	180,365	255,483	64,559	33,669	157,255	255,483	82,155	(27,861)	54,294	44,074	32,902	(317)	32,595	(9,275)	23,320	2,948	26,268
Enel Distribución Perú S.A.A.	Separate	153,382	1,305,567	1,458,949	272,268	467,924	718,757	1,458,949	950,350	(619,181)	331,169	257,473	196,436	(22,938)	184,153	(55,649)	128,504	13,065	141,569
Grupo Enel Perú	Consolidated	551,844	2,562,083	3,113,927	482,477	805,168	1,826,282	3,113,927	1,382,941	(676,173)	706,768	561,494	433,368	(30,553)	413,480	(125,187)	288,293	64,392	352,685

F-192

39. SUBSEQUENT EVENTS

1. Edesur

On February 22, 2022, the National Executive Power issued Decree No. 88/2022, which, in its Article 16, extends until December 31, 2022 the implementation of the “Special Regime for Regularization of Obligations” for the debts held with Compañía Administradora del Mercado Mayorista Eléctrico S.A. (CAMMESA) of the electricity distributors agents of the Wholesale Electricity Market (MEM, in its Spanish acronym) and of the “Special Credit Regime” established by the Secretariat of Energy (SE) under Article 87 of Law No. 27,591 and in resolutions SE No. 40/2021 and No. 371/2021. The Secretariat of Energy, in its capacity as enforcement authority, may establish for the obligations pending payment generated after April 30, 2021 and until December 31, 2021, a special regime for the regularization of obligations under terms and conditions similar to those set forth in the “Special Regime for the Regularization of Obligations”, providing, in particular for the remaining debts, a payment plan with a term of up to 96 monthly installments, up to 6 months of grace and an interest rate equivalent to up to 50% of the rate in force in the MEM. Distributors that adhere to this regime will have to keep their payments up to date with CAMMESA’s current invoicing beginning on the date established by the Secretariat of Energy for each case.

Finally, as a result of the public hearing mentioned above, on February 22, 2022, the Secretariat of Energy and the ENRE issued Joint Resolution No. 1/2022, approving the final report and, on February 23, 2022, the Secretariat of Energy issued Resolution No. 105/2022, updating the stabilized seasonal prices of energy and transportation that will be applicable beginning on March 1, 2022 (See Note 4.i.a).

2. Enel Américas S.A.

On March 1, 2022 Enel Américas S.A. announced in a significant event filing that on February 28, 2022 the Superintendency of Companies of the Republic of Colombia authorized the statutory reorganization consisting of the merger by absorption (“the Merger”) of the subsidiaries of Enel Américas: Emgesa S.A. ESP (absorbing company), Codensa S.A. ESP, Enel Green Power Colombia S.A.S. ESP, and ESSA2 SpA (absorbed companies).

Also, on March 1, 2022, Notary 11 of Bogota issued the related public deed through which the Merger commitment, its annexes, and other necessary documents were registered. As of March 1, 2022, the Merger between the companies Emgesa S.A. ESP (absorbing company), Codensa S.A. ESP, Enel Green Power Colombia S.A.S. ESP, and ESSA2 SpA (absorbed companies) has been completed. The public deed was also registered on March 1, 2022 with the Bogota Chamber of Commerce, finalizing the Merger.

The new corporate name of the merged companies is Enel Colombia S. A. ESP.

The resulting distribution of shares of the Colombian subsidiary Enel Colombia S.A. ESP is as follows: (i) Enel Américas S.A. holds an interest of 57.345%; ii) Grupo Energía Bogotá S.A. ESP holds and interest of 42.515%; and iii) other minority shareholders hold an interest of 0.140%.

Between January 1, 2022 and the date of issuance of these consolidated financial statements, we are not aware of other events of a financial or any other nature that could significantly affect the financial position and the results presented herein.

F-193

APPENDIX No. 1 COMPANIES FROM THE ENEL AMERICAS GROUP

This appendix is part of Note 2.4 "Subsidiaries".

Taxpayer ID No.	Company	Country	Functional Currency	12/31/2021			12/31/2020
				Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Central Dock Sud S.A.	Argentina	Argentine peso	-	70.24%	70.24%	-	70.24%	70.24%
Foreign	Compañía de Transmisión del Mercosur S.A. - CTM	Argentina	Argentine peso	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Distrilec Inversora S.A.	Argentina	Argentine peso	51.50%	-	51.50%	51.50%	-	51.50%
Foreign	Empresa Distribuidora Sur S.A. - Edesur	Argentina	Argentine peso	-	99.45%	99.45%	-	99.45%	99.45%
Foreign	Enel Argentina S.A.	Argentina	Argentine peso	99.92%	-	99.92%	99.92%	-	99.92%
Foreign	Enel Trading Argentina S.R.L.	Argentina	Argentine peso	55.00%	45.00%	100.00%	55.00%	45.00%	100.00%
Foreign	Enel Generación Costanera S.A.	Argentina	Argentine peso	-	75.68%	75.68%	-	75.68%	75.68%
Foreign	Enel Generación El Chocón S.A.	Argentina	Argentine peso	-	67.67%	67.67%	-	67.67%	67.67%
Foreign	Hidroinvest S.A.	Argentina	Argentine peso	41.94%	54.76%	96.70%	41.94%	54.76%	96.70%
Foreign	Inversora Dock Sud S.A.	Argentina	Argentine peso	57.14%	-	57.14%	57.14%	-	57.14%
Foreign	Transportadora de Energía S.A. - TESA	Argentina	Argentine peso	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Green Power Argentina S.A.	Argentina	Argentine peso	99.24%	0.76%	100.00%	-	-	-
77.333.234-7	ESSA2 S.P.A.	Chile	U.S. Dollar	100.00%	-	100.00%	-	-	-
76.802.942-3	Energia y Servicios South America S.P.A.	Chile	U.S. Dollar	100.00%	-	100.00%	-	-	-
Foreign	Compañía Distribuidora y Comercializadora de Energía S.A. - Codensa	Colombia	Colombian Peso	48.30%	-	48.30%	48.30%	-	48.30%
Foreign	Emgesa S.A. E.S.P.	Colombia	Colombian Peso	48.48%	-	48.48%	48.48%	-	48.48%
Foreign	Inversora Codensa S.A.S.	Colombia	Colombian Peso	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Sociedad Portuaria Central Cartagena S.A.	Colombia	Colombian Peso	-	99.99%	99.99%	-	99.99%	99.99%
Foreign	Enel X Colombia S.A.S	Colombia	Colombian Peso	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Bogotá ZE S.A.S.	Colombia	Colombian Peso	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Fontibon ZE S.A.S.	Colombia	Colombian Peso	-	100.00%	100.00%	-	-	-
Foreign	USME ZE S.A.S	Colombia	Colombian Peso	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Colombia S.A.S E.S.P.	Colombia	Colombian Peso	100.00%	-	100.00%	-	-	-
Foreign	EGP Fotovoltaica La Loma S.A.S under liquidation	Colombia	Colombian Peso	-	100.00%	100.00%	-	-	-
Foreign	Guayepo Solar S.A.S.	Colombia	Colombian Peso	-	100.00%	100.00%	-	-	-
Foreign	Latamsolar Fotovoltaica Fundación S.A.S.	Colombia	Colombian Peso	-	100.00%	100.00%	-	-	-
Foreign	Atlantico Photovoltaic S.A.S. ESP	Colombia	Colombian Peso	-	100.00%	100.00%	-	-	-
Foreign	Enel Peru S.A.C.	Peru	Peruvian Sol	100.00%	-	100.00%	100.00%	-	100.00%
Foreign	Chinango S.A.C.	Peru	Peruvian Sol	-	80.00%	80.00%	-	80.00%	80.00%
Foreign	Enel Generación Peru S.A.A.	Peru	Peruvian Sol	-	83.60%	83.60%	-	83.60%	83.60%
Foreign	Enel Distribución Peru S.A.A.	Peru	Peruvian Sol	-	83.15%	83.15%	-	83.15%	83.15%
Foreign	Enel Generación Piura S.A.	Peru	Peruvian Sol	-	96.50%	96.50%	-	96.50%	96.50%
Foreign	Enel X Peru S.A.C.	Peru	Peruvian Sol	-	99.99%	99.99%	-	99.99%	99.99%
Foreign	Compañía Energética Veracruz S.A.C.	Peru	Peruvian Sol	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Green Power Peru S.A. (USD)	Peru	U.S. Dollar	100.00%	-	100.00%	-	-	-
Foreign	Empresa de Generación Eléctrica Los Pinos S.A.	Peru	Peruvian Sol	-	100.00%	100.00%	-	-	-
Foreign	Empresa De Generacion Electrica Marcona S.A.C.	Peru	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Energetica Monzón S.A.C.	Peru	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Guatemala, S.A.	Guatemala	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Generadora de Occidente, Ltda.	Guatemala	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Generadora Montecristo, S.A.	Guatemala	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Renovables de Guatemala, S.A.	Guatemala	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Transmisora de Energia Renovable, S.A.	Guatemala	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Tecnoguat, S.A.	Guatemala	U.S. Dollar	-	75.00%	75.00%	-	-	-
Foreign	Enel Green Power Panamá, S.R.L.	Panama	U.S. Dollar	0.03%	99.97%	100.00%	-	-	-
Foreign	Enel Fortuna S.A.	Panama	U.S. Dollar	-	50.06%	50.06%	-	-	-
Foreign	Enel Solar, S.R.L.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Generadora Eolica Alto Pacora, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Generadora Solar Tole, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Llano Sanchez Solar Power One, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Generadora Solar Austral, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Jaguito Solar 10MW, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Progreso Solar 20MW, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Generadora Solar El Puerto, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Generadora Solar de Occidente, S.A.	Panama	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Costa Rica S.A.	Costa Rica	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	Energia Global Operaciones S.A.	Costa Rica	U.S. Dollar	-	100.00%	100.00%	-	-	-
Foreign	PH Chucás S.A. (2)	Costa Rica	U.S. Dollar	-	65.00%	65.00%	-	-	-
Foreign	PH Don Pedro S.A. (2)	Costa Rica	U.S. Dollar	-	33.44%	33.44%	-	-	-
Foreign	PH Rio Volcan S.A. (2)	Costa Rica	U.S. Dollar	-	34.32%	34.32%	-	-	-
Foreign	Enel Uruguay S.A. (1)	Uruguay	U.S. Dollar	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Distribución Río S.A.	Brazil	Brazilian Real	-	99.73%	99.73%	-	99.73%	99.73%
Foreign	EGP Cachoeira Dourada S.A.	Brazil	Brazilian Real	-	99.75%	99.75%	-	99.75%	99.75%

(1) In 2020, Nuxer Trading S.A. changed its name to Enel Uruguay S.A.

(2) As a result of its distribution of shares and structure, Enel Américas has a controlling interest in the companies PH Chucás S.A. of 99.50%, PH Don Pedro S.A. of 99.46% and PH Volcán S.A. of 99.15%.

F-194

Taxpayer ID No.	Company	Country	Functional Currency	12-31-2021			12-31-2020
				Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Enel Generación Fortaleza S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Cien S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Distribución Ceará S.A.	Brazil	Brazilian Real	-	74.05%	74.05%	-	74.05%	74.05%
Foreign	Enel Brazil S.A.	Brazil	Brazilian Real	100.00%	-	100.00%	100.00%	-	100.00%
Foreign	Enel X Brazil S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Distribución Goias S.A.	Brazil	Brazilian Real	-	99.96%	99.96%	-	99.96%	99.96%
Foreign	Enel Distribución Sao Paulo S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Green Power Proyectos I (Volta Grande) S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Luz de Angra Energía S.A.	Brazil	Brazilian Real	-	51.00%	51.00%	-	51.00%	51.00%
Foreign	Central Generadora Fotovoltaica Sao Francisco Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Tecnología de Redes S.A.	Brazil	Brazilian Real	-	-	-	-	100.00%	100.00%
Foreign	Enel Trading Brazil S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	100.00%	100.00%
Foreign	Enel Green Power Desenvolvimento Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Alvorada Energia S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Apiacas Energia S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Alba Energia Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Bondia Energia Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 4 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 2 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Gonçalo 22 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 5 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 1 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 21 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 10 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 3 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 4 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 19 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 13 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 5 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 8 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 3 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 11 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 7 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 6 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 15 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 14 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 9 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 17 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 21 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Angela 1 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Angela 2 S.A	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 10 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela 20 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Zeus II - Delfina 8 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperanca 15 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 17 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Central Geradora Fotovoltaica Bom Nome Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Parque Eolico Palmas Dos Ventos Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Boa Vista 01 Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Zeus Sul 1 Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enelpower do Brazil Ltda.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 6 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela Energias Renováveis S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru 01 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru 02 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru 03 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru 04 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru 05 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 07 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-

F-195

Taxpayer ID No.	Company	Country	Functional Currency	12-31-2021			12-31-2020
				Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Enel Green Power São Gonçalo 08 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 11 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 12 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 08 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 16 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 21 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 22 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 25 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 26 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Ângela ACL 12 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Angela Acl 13 S.A	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Angela Acl 16 S.A	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Angela Acl 18 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Isamu Ikeda Energia S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru Participacoes S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa Participações S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 09 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança Participações S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Primavera Energia S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Quatiara Energia S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 01 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 02 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 04 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 08 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 11 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 16 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 17 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 18 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Goncalo 14 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Goncalo 15 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Goncalo 19 S.A	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Gonçalo 18 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Goncalo 17 S.A	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Fontes dos Ventos 2 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Socibe Energia S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Fontes Dos Ventos 3 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 22 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 26 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 29 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 13 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de São Roque 19 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Micael 04 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança 1 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos De Santa Esperança Energias Renováveis ​​S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Micael 02 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de Santa Esperança 7 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Micael 03 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power São Micael 01 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru Solar 01 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cumaru Solar 02 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de Santa Esperanca 3 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cristal Eolica S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Ventos de Sao Roque Energias Renovaveis S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Judas Eolica S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Fotons de Santo Anchieta Energias Renovaveis S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Primavera Eolica S.A	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de Santo Orestes 1 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de Santo Orestes 2 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Zeus Sul 2 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa Do Sol 01 S.A.	Brazil	Brazilian Real	-	100.00%	100.00%	-	-	-

F-196

Taxpayer ID No.	Company	Country		Functional Currency	12-31-2021			12-31-2020
					Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Enel Green Power Ventos de Sao Roque 03 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa Do Sol 03 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de Sao Roque 05 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa Do Sol 04 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Emiliana Eolica S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de Sao Roque 07 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Joana Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Micael 05 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Pau Ferro Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Pedra Do Geronimo Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Tacaico Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Jade Energia Ltda.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa Do Sol 02 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cerrado Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Brejolandia Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Esperanca Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Fontes Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ventos de Sao Roque 06 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa II Participacoes S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Morro do Chapéu Solar 01 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa III Participacoes S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa do Sol 05 S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa do Sol 06 S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa do Sol 07 S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Ventos De Santo Orestes Energias Renovaveis S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Modelo I Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Modelo II Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 04 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 03 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 08 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Fontes II Participacoes S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Cabeca De Boi S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Dois Riachos Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Fazenda S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Salto Apiacás S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 07 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 06 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 05 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 01 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Aroeira 02 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Damascena Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Esperanca Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Manicoba Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Solucoes Energeticas Ltda.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Delfina A Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Delfina B Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Delfina C Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Delfina D Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Delfina E Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ituverava Norte Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ituverava Sul Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Ituverava Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Boa Vista Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Morro Do Chapeu I Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Morro Do Chapeu II Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Sao Abraao Eolica S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Mourao S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Paranapanema S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Horizonte MP Solar S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 03 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 06 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 07 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 08 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 01 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 02 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 04 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Novo Lapa 05 S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa do Sol 08 S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Lagoa do Sol 09 S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Fazenda Aroeira Empreendimento de Energia Ltda.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 01 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 07 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 05 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 09 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 04 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 02 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 03 S.A.	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 06 S.A	Brazil		Brazilian Real	-	100.00%	100.00%	-	-	-
Foreign	Enel Green Power Nova Olinda 08 S.A	Brazil	���	Brazilian Real	-	100.00%	100.00%	-	-	-

F-197

APPENDIX No. 2 DETAIL OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY

This appendix forms an integral part of these consolidated financial statements.

The detail of assets and liabilities denominated in foreign currency is as follows:

	12-31-2021
ASSETS	UF	Chilean Peso	Dollar	Euro	Colombian Peso	Peruvian Sol	Argentine Peso	Brazilian Real	Other Currency	Total
Current Assets
Cash and cash equivalents	—	1,588	348,413	162	150,799	129,607	8,025	757,659	—	1,396,253
Other current financial assets	—	121	1,532	—	76,750	61	143,685	89,881	—	312,030
Other current non-financial assets	—	4,481	89,825	—	13,731	37,715	27,748	654,913	347	828,760
Trade and other current receivables	—	1,521	71,132	—	328,825	175,163	312,025	2,822,475	—	3,711,141
Current accounts receivable from related parties	—	3,692	64,787	3,693	503	273	27	784	—	73,759
Inventories	—	—	8,131	—	76,415	55,296	55,911	342,523	—	538,276
Current tax assets	—	9,483	1,765	—	2,628	50,899	8,246	128,719	—	201,740
Current assets other than assets or groups of assets for disposal classified as held for sale	—	—	—	—	520	—	—	—	—	520
Total Current Assets	—	20,886	585,585	3,855	650,171	449,014	555,667	4,796,954	347	7,062,479
Non-Current Assets
Other non-current financial assets	—	—	195,661	—	6,717	12	26,193	3,244,593	—	3,473,176
Other non-current non-financial assets	—	5,157	33,645	—	27,954	36,068	830	3,041,767	—	3,145,421
Trade and other non-current receivables	—	43	211,205	—	20,201	—	23,097	470,305	—	724,851
Non-current accounts receivable from related parties	—	—	—	—	—	—	26	—	—	26
Investments accounted for using the equity method	—	—	—	—	—	—	2,369	—	—	2,369
Intangible assets other than goodwill	—	—	105,554	—	165,571	75,592	86,948	4,322,605	—	4,756,270
Goodwill	—	—	28,215	—	66,068	263,426	2,015	1,110,501	—	1,470,225
Property, plant and equipment	—	—	1,187,248	—	3,962,716	2,033,436	2,143,756	3,670,372	—	12,997,528
Investment property	—	—	—	—	—	—	—	6,272	—	6,272
Right-of-use asset	—	—	11,109	—	60,872	138,163	49	117,760	—	327,953
Deferred tax assets	—	726	196,941	—	4,322	29,124	15,928	745,291	36	992,368
Total Non-Current Assets	—	5,926	1,969,578	—	4,314,421	2,575,821	2,301,211	16,729,466	36	27,896,459
		���
Total Assets	—	26,812	2,555,163	3,855	4,964,592	3,024,835	2,856,878	21,526,420	383	34,958,938
	12-31-2020
ASSETS	UF	Chilean Peso	Dollar	Euro	Colombian Peso	Peruvian Sol	Argentine Peso	Brazilian Real	Other Currency	Total
Current Assets
Cash and cash equivalents	—	637	170,335	47	381,754	147,458	65,480	741,282	—	1,506,993
Other current financial assets	—	116	95	—	4,047	—	65,287	160,734	—	230,279
Other current non-financial assets	—	16,730	2,177	36	27,088	62,864	40,572	411,220	99	560,786
Trade and other current receivables	—	1,587	22,201	81	330,871	165,342	306,606	2,408,247	—	3,234,935
Current accounts receivable from related parties	—	3,271	547	3,566	716	2,480	29	36,341	—	46,950
Inventories	—	—	1,035	987	102,781	53,015	40,892	272,723	—	471,433
Current tax assets	—	9,546	11,457	—	31	10,069	2,628	94,149	—	127,880
Total Current Assets	—	31,887	207,847	4,717	847,288	441,228	521,494	4,124,696	99	6,179,256
Non-Current Assets
Other non-current financial assets	—	—	—	—	153	55	25,461	2,765,194	—	2,790,863
Other non-current non-financial assets	—	2,980	—	—	33,029	23,092	898	2,272,857	—	2,332,856
Trade and other non-current receivables	—	77	244,126	—	33,565	—	24,410	276,346	—	578,524
Non-current accounts receivable from related parties	—	—	—	—	—	—	32	—	—	32
Investments accounted for using the equity method	—	—	—	—	—	—	2,273	—	—	2,273
Intangible assets other than goodwill	—	—	—	—	135,881	70,955	61,160	4,256,830	—	4,524,826
Goodwill	—	—	—	—	18,264	184,037	24,603	718,608	—	945,512
Property, plant and equipment	—	—	176	—	4,158,620	2,128,830	1,762,799	304,247	—	8,354,672
Investment property	—	—	—	—	—	—	—	7,942	—	7,942
Right-of-use asset	24	—	—	—	19,639	159,534	124	43,099	—	222,420
Deferred tax assets	—	—	192,057	—	11,277	253	28,746	762,049	—	994,382
Total Non-Current Assets	24	3,057	436,359	—	4,410,428	2,566,756	1,930,506	11,407,172	—	20,754,302
Total Assets	24	34,944	644,206	4,717	5,257,716	3,007,984	2,452,000	15,531,868	99	26,933,558

F-198

	12-31-2021
LIABILITIES	UF	Chilean Peso	Dollar	Euro	Colombian Peso	Peruvian Sol	Argentine Peso	Brazilian Real	Other Currency	Total
Current Liabilities
Other current financial liabilities	3,305	—	191,159	7,414	371,171	277,357	8	382,294	126	1,232,834
Current lease liability	—	—	11,038	—	9,246	16,996	14	23,393	—	60,687
Trade and other current payables	6	24,991	187,299	8,172	422,272	240,035	857,048	3,172,285	22	4,912,130
Current accounts payable to related parties	—	189,421	46,878	518,069	2,148	2,001	207	196,983	—	955,707
Other current provisions	—	54	2	—	30,974	7,666	49,900	76,248	—	164,844
Current tax liabilities	—	—	14,558	—	87,275	53,643	13,881	13,703	—	183,060
Other current non-financial liabilities	—	916	17,340	—	31,874	24,132	26,096	185,408	506	286,272
Total Current Liabilities	3,311	215,382	468,274	533,655	954,960	621,830	947,154	4,050,314	654	7,795,534
Non-Current Liabilities
Other non-current financial liabilities	—	—	1,748,465	87,003	1,213,912	379,487	—	1,488,716	—	4,917,583
Non-current lease liability	—	—	31,200	—	53,588	3,135	24	99,944	—	187,891
Trade and other non-current payables	—	—	—	—	874	591	53,914	2,633,688	—	2,689,067
Non-current accounts payable from related parties	—	—	96,643	—	7,804	—	—	958,051	—	1,062,498
Other long-term provisions	—	—	11,756	—	74,773	47,505	19,116	685,669	—	838,819
Deferred tax liabilities	—	2,057	44,008	—	223,420	110,465	459,883	39,567	—	879,400
Non-current provisions for employee benefits	—	2,422	1,723	—	87,419	3,031	17,231	1,311,655	—	1,423,481
Other non-current non-financial liabilities	—	-	26,305	—	15,679	3,199	39,149	50,240	—	134,572
Total Non-Current Liabilities	—	4,479	1,960,100	87,003	1,677,469	547,413	589,317	7,267,530	—	12,133,311
Total Liabilities	3,311	219,861	2,428,374	620,658	2,632,429	1,169,243	1,536,471	11,317,844	654	19,928,845
	12-31-2020
LIABILITIES	UF	Chilean Peso	Dollar	Euro	Colombian Peso	Peruvian Sol	Argentine Peso	Brazilian Real	Other Currency	Total
Current Liabilities
Other current financial liabilities	7,103	—	789,559	—	453,666	201,641	36	373,125	—	1,825,130
Current lease liability	19	—	20,470	17	4,792	10,434	78	15,685	—	51,495
Trade and other current payables	—	46,970	206,653	12,519	471,331	194,903	517,715	2,643,452	33	4,093,576
Current accounts payable to related parties	—	167,003	152,956	236,546	2,652	1,643	177	36,145	—	597,122
Other current provisions	—	—	44,308	—	40,176	12,931	45,167	77,843	—	220,425
Current tax liabilities	—	—	—	—	110,724	33,777	44,383	33,986	—	222,870
Other current non-financial liabilities	—	369	11,908	—	31,914	28,193	21,876	172,249	95	266,604
Total Current Liabilities	7,122	214,342	1,225,854	249,082	1,115,255	483,522	629,432	3,352,485	128	7,277,222
Non-Current Liabilities
Other non-current financial liabilities	3,611	—	806,446	—	1,251,190	404,359	-	1,372,100	—	3,837,706
Non-current lease liability	—	—	25,668	386	15,639	13,816	45	35,516	—	91,070
Trade and other non-current payables	—	—	10,990	-	1,136	729	86,559	1,962,061	—	2,061,475
Non-current accounts payable from related parties	—	—	—	144,391	—	—	—	—	—	144,391
Other long-term provisions	—	—	—	—	78,504	20,879	19,760	714,757	—	833,900
Deferred tax liabilities	—	2,521	—	—	208,618	74,847	286,936	40,031	—	612,953
Non-current provisions for employee benefits	—	2,960	1,906	—	124,248	4,299	13,920	1,476,884	—	1,624,217
Other non-current non-financial liabilities	—	-	31,600	—	19,707	5,132	30,294	30,228	—	116,961
Total Non-Current Liabilities	3,611	5,481	876,610	144,777	1,699,042	524,061	437,514	5,631,577	—	9,322,673
Total Liabilities	10,733	219,823	2,102,464	393,859	2,814,297	1,007,583	1,066,946	8,984,062	128	16,599,895

F-199

APPENDIX No.3 ADDITIONAL INFORMATION OFFICIAL BULLETIN No. 715 OF FEBRUARY 3, 2012

This appendix forms an integral part of these consolidated financial statements.

a) Portfolio stratification

- Trade and other receivables by maturity:

	12-31-2021
Trade and other receivables, current	Up-to-date	1 - 90 days in arrears	91 - 180 days in arrears	More than 181 days in arrears	Total Current	Total Non-Current
Trade receivables, gross	2,598,215	569,756	164,762	975,238	4,307,971	497,193
Allowance for impairment	(27,829)	(30,264)	(40,749)	(739,521)	(838,363)	(32,338)
Accounts receivable for finance lease	913	—	—	—	913	13,742
Allowance for impairment	(24)	—	—	—	(24)	(365)
Other receivables, gross	241,477	—	—	—	241,477	273,419
Allowance for impairment	(833)	—	—	—	(833)	(26,800)
Total	2,811,919	539,492	124,013	235,717	3,711,141	724,851
	12-31-2020
Trade and other receivables, current	Up-to-date	1 - 90 days in arrears	91 - 180 days in arrears	More than 181 days in arrears	Total Current	Total Non-Current
Trade receivables, gross	2,135,722	580,640	124,262	852,428	3,693,052	354,376
Allowance for impairment	(19,775)	(25,636)	(31,925)	(607,172)	(684,508)	(65,015)
Accounts receivable for finance lease	584	—	—	—	584	8,214
Allowance for impairment	(16)	—	—	—	(16)	(214)
Other receivables, gross	231,310	—	—	—	231,310	281,333
Allowance for impairment	(5,487)	—	—	—	(5,487)	(170)
Total	2,342,338	555,004	92,337	245,256	3,234,935	578,524

- By type of portfolio:

	12-31-2021						12-31-2020
Time in Arrears	Non-renegotiated portfolio		Renegotiated portfolio		Total Gross Portfolio		Non-renegotiated portfolio		Renegotiated portfolio		Total Gross Portfolio
	Number of customers	Gross amount	Number of customers	Gross amount	Number of customers	Gross amount	Number of customers	Gross amount	Number of customers	Gross amount	Number of customers	Gross amount
Up-to-date	10,206,080	2,846,359	5,767,598	249,049	15,973,678	3,095,408	9,945,761	2,211,900	6,354,193	278,198	16,299,954	2,490,098
1 to 30 days	10,068,327	357,910	458,333	21,645	10,526,660	379,555	9,176,101	314,733	659,102	24,711	9,835,203	339,444
31 to 60 days	3,768,651	111,707	319,522	15,224	4,088,173	126,931	3,701,107	108,544	323,324	15,590	4,024,431	124,134
61 to 90 days	2,184,046	52,203	236,723	11,067	2,420,769	63,270	2,534,180	106,748	202,523	10,314	2,736,703	117,062
91 to 120 days	2,003,370	62,975	236,769	10,908	2,240,139	73,883	1,724,446	35,933	193,115	9,759	1,917,561	45,692
121 to 150 days	1,775,294	38,225	221,348	10,002	1,996,642	48,227	1,523,287	33,667	177,697	9,147	1,700,984	42,814
151 to 180 days	1,444,114	33,018	206,498	9,634	1,650,612	42,652	1,139,659	27,439	140,387	8,317	1,280,046	35,756
181 to 210 days	1,111,566	101,997	195,652	9,567	1,307,218	111,564	775,377	58,020	132,352	6,387	907,729	64,407
211 to 250 days	706,328	33,300	176,952	8,251	883,280	41,551	504,524	23,907	167,038	6,891	671,562	30,798
More than 251 days	17,923,445	722,336	594,230	99,787	18,517,675	822,123	13,507,750	670,403	1,701,673	86,820	15,209,423	757,223
Total	51,191,221	4,360,030	8,413,625	445,134	59,604,846	4,805,164	44,532,192	3,591,294	10,051,404	456,134	54,583,596	4,047,428

F-200

b) Portfolio in default and in legal collection process.

	2021		2020		2019
Portfolio in Default and in Legal Collection Process	Number of customers	Amount	Number of customers	Amount	Number of customers	Amount
Notes receivable in default	660,033	112,258	1,218,370	252,488	907,062	111,016
Notes receivable in legal collection process (*)	13,985	51,461	13,661	54,986	9,399	44,329
Total	674,018	163,719	1,232,031	307,474	916,461	155,345

(*) Legal collections are included in the portfolio in arrears.

c) Provisions and write-offs

Allowances and write-offs	12-31-2021	12-31-2020
Provisions for non-renegotiated portfolio	295,574	204,419
Provisions for renegotiated portfolio	21,950	38,529
Recoveries	(1,520)	(576)
Total	316,004	242,372

d) Number and amount of operations

	12-31-2021		12-31-2020
Number and Amount of Transactions	Total detail by type of transaction Last Quarter	Total detail by type of operation Year-to- date	Total detail by type of transaction Last Quarter	Total detail by type of operation Year-to- date
Allowance for impairment and recoveries:
Number of transactions	1,025,520	3,830,580	377,287	3,800,417
Amount of the transactions	199,315	316,004	49,648	242,372

F-201

APPENDIX No. 3.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES

This appendix forms an integral part of these consolidated financial statements.

a) Portfolio stratification

- Trade receivables by time in arrears:

	12-31-2021
Trade receivables	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non- Current
Trade receivables, Generation and Transmission	380,941	5,453	1,751	449	1,176	347	326	476	487	8,708	8,119	408,233	12,193
- Large Clients	132,533	3,657	1,226	305	333	301	—	225	—	2,924	1,424	142,928	6,351
- Institutional Clients	44,046	162	—	—	—	—	—	—	—	—	—	44,208	—
- Other	204,362	1,634	525	144	843	46	326	251	487	5,784	6,695	221,097	5,842
Allowance for impairment	(2,317)	(23)	(2)	—	—	(7)	(4)	(539)	(482)	(3,709)	(6,117)	(13,200)	—
Unbilled services	285,640	—	—	—	—	—	—	—	—	—	—	285,640	—
Billed services	95,301	5,453	1,751	449	1,176	347	326	476	487	8,708	8,119	122,593	12,193
Trade receivables, Distribution	2,217,274	374,102	125,180	62,821	72,707	47,880	42,326	111,088	41,064	112,178	693,118	3,899,738	485,000
- Mass-market Clients	1,580,451	296,626	97,130	46,331	41,075	35,657	29,167	60,987	30,209	83,825	496,112	2,797,570	432,688
- Large Clients	475,627	58,619	20,012	11,091	9,923	8,207	9,274	17,843	6,856	19,685	140,337	777,474	18,822
- Institutional Clients	161,196	18,857	8,038	5,399	21,709	4,016	3,885	32,258	3,999	8,668	56,669	324,694	33,490
Allowance for impairment	(25,512)	(6,285)	(12,611)	(11,343)	(12,984)	(15,223)	(12,531)	(68,246)	(27,955)	(69,702)	(562,771)	(825,163)	(32,338)
Unbilled services	610,303	—	—	—	—	—	—	—	—	—	—	610,303	—
Billed services	1,606,971	374,102	125,180	62,821	72,707	47,880	42,326	111,088	41,064	112,178	693,118	3,289,435	485,000
Total trade receivables, gross	2,598,215	379,555	126,931	63,270	73,883	48,227	42,652	111,564	41,551	120,886	701,237	4,307,971	497,193
Total Allowance for impairment	(27,829)	(6,308)	(12,613)	(11,343)	(12,984)	(15,230)	(12,535)	(68,785)	(28,437)	(73,411)	(568,888)	(838,363)	(32,338)
Total trade receivables, net	2,570,386	373,247	114,318	51,927	60,899	32,997	30,117	42,779	13,114	47,475	132,349	3,469,608	464,855
	12-31-2020
Trade receivables	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non- Current
Trade receivables, Generation and Transmission	570,481	20,280	886	43,848	49	1	79	2,325	288	3,042	2,665	643,944	29,555
- Large Clients	76,662	20,098	863	3,946	—	—	—	2,065	—	2,968	—	106,602	29,536
- Institutional Clients	55,544	—	—	—	—	—	—	—	—	—	—	55,544	-
- Other	438,275	182	23	39,902	49	1	79	260	288	74	2,665	481,798	19
Allowance for impairment	(455)	(6)	(3)	—	(1)	—	—	(307)	—	(2,968)	(2,456)	(6,196)	(29,103)
Unbilled services	514,703	—	—	—	—	—	—	—	—	—	—	514,703	-
Billed services	55,778	20,280	886	43,848	49	1	79	2,325	288	3,042	2,665	129,241	29,555
Trade receivables, Distribution	1,565,241	319,164	123,248	73,214	45,643	42,813	35,677	62,082	30,510	91,245	660,271	3,049,108	324,821
- Mass-market Clients	1,069,469	238,880	90,411	42,427	31,033	30,426	24,545	47,689	19,323	61,763	438,879	2,094,845	262,530
- Large Clients	374,227	58,211	20,058	10,984	8,380	7,597	7,364	10,669	6,000	20,894	142,121	666,505	15,498
- Institutional Clients	121,545	22,073	12,779	19,803	6,230	4,790	3,768	3,724	5,187	8,588	79,271	287,758	46,793
Allowance for impairment	(19,320)	(4,185)	(10,913)	(10,529)	(9,643)	(13,056)	(9,225)	(40,673)	(18,550)	(51,215)	(491,003)	(678,312)	(35,912)
Unbilled services	506,230	—	—	—	—	—	—	—	—	—	—	506,230	—
Billed services	1,059,011	319,164	123,248	73,214	45,643	42,813	35,677	62,082	30,510	91,245	660,271	2,542,878	324,821
Total trade receivables, gross	2,135,722	339,444	124,134	117,062	45,692	42,814	35,756	64,407	30,798	94,287	662,936	3,693,052	354,376
Total Allowance for impairment	(19,775)	(4,191)	(10,916)	(10,529)	(9,644)	(13,056)	(9,225)	(40,980)	(18,550)	(54,183)	(493,459)	(684,508)	(65,015)
Total trade receivables, net	2,115,947	335,253	113,218	106,533	36,048	29,758	26,531	23,427	12,248	40,104	169,477	3,008,544	289,361

Since not all of our commercial databases in our Group’s different consolidated entities distinguish whether the final electricity service consumer is an individual or legal entity, the main management segmentation used by all consolidated entities to monitor and follow up on trade receivables is the following:

- Mass-market customers

- Large customers

- Institutional customers

F-202

- By type of portfolio:

	12-31-2021
Type of Portfolio	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	Total Current	Total Non- Current
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	380,941	5,453	1,751	449	1,176	347	326	476	487	16,827	408,233	12,193
- Large Clients	133,912	3,657	1,226	305	333	301	—	225	—	4,347	144,306	12,163
- Institutional Clients	43,486	162	—	—	—	—	—	—	—	—	43,648	—
- Other	203,543	1,634	525	144	843	46	326	251	487	12,480	220,279	30
Renegotiated portfolio	—	—	—	—	—	—	—	—	—	—	—	—
- Large Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Other	—	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Non-renegotiated portfolio	2,113,807	352,457	109,956	51,754	61,799	37,878	32,692	101,521	32,813	705,509	3,600,186	339,418
- Mass-market Clients	1,510,037	278,741	84,853	36,992	31,769	27,271	22,000	53,562	23,352	512,046	2,580,623	335,099
- Large Clients	452,614	56,132	18,135	10,079	8,856	7,018	7,561	16,147	5,794	143,181	725,517	4,137
- Institutional Clients	151,156	17,584	6,968	4,683	21,174	3,589	3,131	31,812	3,667	50,282	294,046	182
Renegotiated portfolio	103,467	21,645	15,224	11,067	10,908	10,002	9,634	9,567	8,251	99,787	299,552	145,582
- Mass-market Clients	70,415	17,885	12,276	9,339	9,305	8,386	7,755	7,095	6,358	67,891	216,705	118,050
- Large Clients	23,012	2,487	1,878	1,012	1,068	1,189	1,394	1,872	1,222	16,841	51,975	9,094
- Institutional Clients	10,040	1,273	1,070	716	535	427	485	600	671	15,055	30,872	18,438
Total gross portfolio	2,598,215	379,555	126,931	63,270	73,883	48,227	42,652	111,564	41,551	822,123	4,307,971	497,193
	12-31-2020
Type of Portfolio	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	Total Current	Total Non- Current
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	570,481	20,280	886	43,848	49	1	79	2,325	288	5,707	643,944	628
- Large Clients	76,662	20,098	863	3,946	—	—	—	2,065	—	2,968	106,602	—
- Institutional Clients	55,544	—	—	—	—	—	—	—	—	—	55,544	—
- Other	438,275	182	23	39,902	49	1	79	260	288	2,739	481,798	628
Renegotiated portfolio	—	—	—	—	—	—	—	—	—	—	—	28,927
- Large Clients	—	—	—	—	—	—	—	—	—	—	—	28,927
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Other	—	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Non-renegotiated portfolio	1,444,504	294,453	107,658	62,900	35,884	33,666	27,360	55,695	23,619	664,696	2,750,435	196,287
- Mass-market Clients	979,330	221,045	79,769	34,801	23,547	23,670	19,382	43,181	14,971	443,333	1,883,029	191,559
- Large Clients	349,489	53,788	17,629	9,207	7,070	6,316	5,195	9,579	4,769	147,615	610,657	4,512
- Institutional Clients	115,685	19,620	10,260	18,892	5,267	3,680	2,783	2,935	3,879	73,748	256,749	216
Renegotiated portfolio	120,737	24,711	15,590	10,314	9,759	9,147	8,317	6,387	6,891	86,820	298,673	128,534
- Mass-market Clients	90,140	17,835	10,642	7,626	7,484	6,755	5,164	4,508	4,353	57,309	211,816	99,922
- Large Clients	24,737	4,423	2,429	1,777	1,311	1,282	2,169	1,090	1,230	15,400	55,848	8,561
- Institutional Clients	5,860	2,453	2,519	911	964	1,110	984	789	1,308	14,111	31,009	20,051
Total gross portfolio	2,135,722	339,444	124,134	117,062	45,692	42,814	35,756	64,407	30,798	757,223	3,693,052	354,376

F-203

APPENDIX 3.2 ESTIMATED SALES AND PURCHASES OF CAPACITY AND TOLL

This appendix forms an integral part of these consolidated financial statements.

Country	COLOMBIA				PERU				ARGENTINA				BRAZIL				CENTRAL AMERICA				TOTAL
	12-31-2021		12-31-2020		12-31-2021		12-31-2020		12-31-2021		12-31-2020		12-31-2021		12-31-2020		12-31-2021		12-31-2020		12-31-2021		12-31-2020
BALANCE	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls
Current accounts receivable from related parties	—	—	—	—	—	—	—	—	—	—	—	—	—	2	31,286	19	—	—	—	—	—	2	31,286	19
Trade and other receivables, current	142,970	3,069	139,254	11,961	61,208	10,318	61,975	12,240	88,248	—	77,421	—	585,845	4,554	745,630	3,952	29,802	236	—	—	908,073	18,177	1,024,280	28,153
Trade and other receivables, non-current	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Total Asset Estimate	142,970	3,069	139,254	11,961	61,208	10,318	61,975	12,240	88,248	—	77,421	—	585,845	4,556	776,916	3,971	29,802	236	0	0	908,073	18,179	1,055,566	28,172
Current accounts payable to related parties	—	—	677	—	—	—	—	—	—	—	—	—	—	—	33,351	—	—	—	—	—	—	—	34,028	—
Trade and other payables, current	102,729	12,218	30,139	12,246	37,500	9,333	52,233	9,763	44,869	—	38,689	—	701,646	54,772	1,120,722	59,673	5,348	2,985	—	—	892,092	79,308	1,241,783	81,682
Total Liability Estimate	102,729	12,218	30,816	12,246	37,500	9,333	52,233	9,763	44,869	—	38,689	—	701,646	54,772	1,154,073	59,673	5,348	2,985	—	—	892,092	79,308	1,275,811	81,682
Country	COLOMBIA				PERU				ARGENTINA				BRAZIL				CENTRAL AMERICA				TOTAL
	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
INCOME STATEMENT	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls
Energy sales	173,022	3,336	129,017	11,081	63,003	10,620	64,115	12,663	87,622	—	75,346	—	604,872	4,708	782,533	4,193	29,802	236	—	—	958,321	18,900	1,051,011	27,937
Energy purchases	49,010	13,282	28,552	11,345	38,600	9,607	54,038	10,100	44,865	—	38,686	—	723,648	56,572	1,167,029	60,048	5,348	2,985	—	—	861,471	82,446	1,288,305	81,493

F-204

APPENDIX No. 4 DETAIL OF DUE DATES OF PAYMENTS TO SUPPLIERS

This appendix forms an integral part of these consolidated financial statements.

	Balance as of				Balance as of
	12-31-2021				12-31-2020
Suppliers with Payments Up-to-Date	Goods	Services	Other	Total	Goods	Services	Other	Total
Up to 30 days	63,067	817,048	1,062,435	1,942,550	104,782	469,913	1,321,209	1,895,904
From 31 to 60 days	65,958	581,141	48,616	695,715	52,007	233,753	96,755	382,515
From 61 to 90 days	19,513	82,550	4,599	106,662	3,877	30,449	15,620	49,946
From 91 to 120 days	3,198	20,119	2,535	25,852	373	23,619	124,617	148,609
From 121 to 365 days	32	65,861	18,718	84,611	6,462	16,912	19,770	43,144
More than 365 days	—	20,915	77,355	98,270	—	3,075	111,587	114,662
Total	151,768	1,587,634	1,214,258	2,953,660	167,501	777,721	1,689,558	2,634,780
	Balance as of				Balance as of
	12-31-2021				12-31-2020
Suppliers with Payments Overdue	Goods	Services	Other	Total	Goods	Services	Other	Total
Up to 30 days	2,092	42,170	26,389	70,651	908	24,552	17,039	42,499
From 31 to 60 days	—	—	20,731	20,731	—	—	16,401	16,401
From 61 to 90 days	—	—	25,277	25,277	—	—	18,485	18,485
From 91 to 120 days	—	—	25,690	25,690	—	—	39,312	39,312
From 121 to 365 days	—	—	46,273	46,273	—	—	152,921	152,921
More than 365 days	—	—	387,492	387,492	—	—	—	—
Total	2,092	42,170	531,852	576,114	908	24,552	244,158	269,618
	Balance as of				Balance as of
	12-31-2021				12-31-2020
Suppliers Detail	Goods	Services	Other	Total	Goods	Services	Other	Total
Energy suppliers	7,868	129,069	1,730,335	1,867,272	60,184	56,933	1,627,935	1,745,052
Fuel and gas suppliers	—	9,619	—	9,619	17,410	7,211	—	24,621
Asset acquisitions	49,718	97,856	—	147,574	12,693	34,671	12,958	60,322
Payables due for goods and services	96,274	1,393,260	15,775	1,505,309	78,122	703,458	292,823	1,074,403
Total	153,860	1,629,804	1,746,110	3,529,774	168,409	802,273	1,933,716	2,904,398

F-205