UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

o	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
o	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2018
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from              to
OR
o	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)

Nicolás Billikopf, phone: (56-2) 2353-4628, nicolas.billikopf@enel.com, Santa Rosa 76, Piso 15, Santiago, Chile

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

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

Title of each class	Name of each exchange on which registered
American Depositary Shares representing Common Stock	New York Stock Exchange
Common Stock, no par value *	New York Stock Exchange
US$ 600,000,000 4.00% Notes due October 25, 2026	New York Stock Exchange
US$ 858,000 6.60% Notes due December 1, 2026	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 by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x  Yes   o   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.  o  Yes   x   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. x  Yes   o 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). x Yes   o 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 x Accelerated filer o Non-accelerated filer o Emerging growth company o

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. o

†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 which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP o International Financial Reporting Standards as issued
by the International Accounting Standards Board x Other o

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.

o Item 17   o 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).

o Yes   x No

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:    57,452,641,516

Enel Américas Simplified Organizational Chart(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 its economic interest in such consolidated subsidiary. Please refer to “Presentation of Information” for an explanation of the calculation of economic interest.

(2)As of December 31, 2018, Enel SpA owned 51.8% of Enel Américas. As of the date of this Report, Enel SpA owns a 56.4% beneficial interest in Enel Américas.

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TABLE OF CONTENTS

		Page
GLOSSARY		3
INTRODUCTION		7
PRESENTATION OF INFORMATION		8
FORWARD-LOOKING STATEMENTS		10
RECENT DEVELOPMENTS		11
PART I
Item 1.	Identity of Directors, Senior Management and Advisers	12
Item 2.	Offer Statistics and Expected Timetable	12
Item 3.	Key Information	12
Item 4.	Information on the Company	24
Item 4A.	Unresolved Staff Comments	92
Item 5.	Operating and Financial Review and Prospects	93
Item 6.	Directors, Senior Management and Employees	134
Item 7.	Major Shareholders and Related Party Transactions	143
Item 8.	Financial Information	145
Item 9.	The Offer and Listing	146
Item 10.	Additional Information	148
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	162
Item 12.	Description of Securities Other Than Equity Securities	166
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	167
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	167
Item 15.	Controls and Procedures	167
Item 16.	Reserved	168
Item 16A.	Audit Committee Financial Expert	168
Item 16B.	Code of Ethics	169
Item 16C.	Principal Accountant Fees and Services	170
Item 16D.	Exemptions from the Listing Standards for Audit Committees	170
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	170
Item 16F.	Change in Registrant’s Certifying Accountant	171
Item 16G.	Corporate Governance	171
Item 16H.	Mine Safety Disclosure	171
PART III
Item 17.	Financial Statements	172
Item 18.	Financial Statements	172
Item 19.	Exhibits	173

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GLOSSARY

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 e Energia	Brazilian Ministry of Mines and Energy.
BNDES	Banco Nacional de Desenvolvimento Econȏmico e Social	The National Bank for Economic and Social Development (“BNDES”) is the principal agent of development in Brazil with a focus on sustainable social and environmental development.
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 operation of the Mercado Eléctrico Mayorista (Wholesale Electricity Market), or MEM. CAMMESA’s stockholders are generation, transmission and distribution companies, large users and the Secretariat of Energy.
CCEE	Câmara de Comercialização de Energia Elétrica	Electricity Trade Chamber or Clearing House
Chilean Stock Exchanges	Chilean Stock Exchanges	The two principal 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.
CNPE	Conselho Nacional de Politica Energética	Brazilian national energy policy council in charge of advising the Brazilian President on energy policy.
CMF	Comisión para el Mercado Financiero	Chilean Financial Market Commission, the governmental authority that supervises the financial markets. Formerly the Chilean Superintendence of Securities and Insurance or SVS in its Spanish acronym.
CMSE	Comitê de Monitoramento do Setor Elétrico	The Brazilian energy sector monitoring committee that evaluates the continuity and security of the energy supply across the country.
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.
Colombian MME	Ministerio de Minas y Energía	Colombian Ministry of Mines and Energy.
CONPES	Consejo Nacional de Política Económica y Social	The Colombian council for economic and social policy, the highest national planning authority, and an advisory entity to the government in all aspects related to economic and social development.

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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 subsidiary of Enel Brasil.
DCV	Depósito Central de Valores S.A.	Chilean Central Securities Depositary.
DECSA	Distribuidora Eléctrica de Cundinamarca S.A.	Colombian distribution company that merged into Codensa in 2016.
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.
EEB	Empresa de Energía de Bogotá S.A.	Colombian state-owned financial and energy holding company, with investments in the electricity generation, transmission, trading and distribution sectors and in the natural gas transmission, distribution and trading sectors.
EEC	Empresa de Energía de Cundinamarca S.A. E.S.P.	Colombian distribution subsidiary of DECSA, which merged with Codensa in 2016.
EGP Volta Grande	Enel Green Power Volta Grande S.A.	Brazilian generation subsidiary located in the State of Minas Gerais, in Brazil, 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.
Enel	Enel S.p.A.	An Italian energy company with multinational operations in the power and gas markets. Our parent company, with a 51.8% economic interest as of December 31, 2018, and 56.4% beneficial interest as of the date of this Report, after making additional purchases in 2019.
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, and Peru, and controlled by Enel. Registrant of this Report. Formerly known as Enersis S.A.
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.

4

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, 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, owned 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, owned by Enel Investimentos Sudeste S.A., a wholly-owned investment vehicle of 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. Formerly Edegel S.A.A.
Enel Generation Piura	Enel Generación Piura S.A.	A publicly held Peruvian generation subsidiary. Formerly Empresa Eléctrica de Piura S.A. or EEPSA.
Enel Sudeste	Enel Investimentos Sudeste S.A	A Brazilian investment holding company, owned by Enel Brasil, and parent company of Enel Distribution Sao Paulo.
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 that are different from the sale of energy or concessioned energy distribution and associated services in Brazil, owned by Enel Brasil.
Enel X Colombia	Enel X Colombia S.A.S.	A Colombian subsidiary engaged in developing, implementing and selling products and services that are different from the sale of energy or concessioned energy distribution and associated services in Colombia, owned by Codensa.
ENRE	Ente Nacional Regulador de la Electricidad	Argentine national regulatory authority for the energy sector.
FONINVEMEM	Fondo para Inversiones Necesarias que permitan Incrementar la Oferta de Energía Eléctrica en el Mercado Eléctrico Mayorista	Argentine fund created to increase electricity supply in the MEM.
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.
IFRS	International Financial Reporting Standards	International Financial Reporting Standards as issued by the International Accounting Standards Board (IASB).

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LNG	Liquefied Natural Gas.	Liquefied natural gas.
MADS	Ministerio de Ambiente y Desarrollo Sostenible	Colombian Ministry of Environment and Sustainable Development.
MEM	Mercado Eléctrico Mayorista	Wholesale Electricity Market. There are such markets in each of Argentina, Colombia, and Peru.
MINEM	Ministerio de Energia y Minas	Peruvian Ministry of Energy and Mines.
NCRE	Non-Conventional Renewable Energy	Energy sources which are continuously replenished by natural processes, such as wind, biomass, 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.
Osinergmin	Organismo Supervisor de la Inversión en Energía y Minería	Energy and Mining Investment Supervisor Authority, the Peruvian regulatory electricity authority.
OSM	Ordinary Shareholders’ Meeting	Ordinary Shareholders’ Meeting.
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.
SEE	Secretaria de Energia Argentina	The Argentine Ministry of Energy and Mines manages the electricty industry through the Secretary of Electric Energy.
SEIN	Sistema Eléctrico Interconectado Nacional	Peruvian national interconnected electricity system.
SENACE	Servicio Nacional de Certificación Ambiental para las Inversiones Sostenibles	Peruvian autonomous national environmental certification service for sustainable investments that reports to the Peruvian Ministry of the Environment.
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$ 27,565.79 as of December 31, 2018.
UPME	Unidad de Planificación Minero Energética	Colombian energy and mining planning unit responsible for planning the expansion of the generation and transmission systems.
UTA	Unidad Tributaria Anual	Chilean annual tax unit. One UTA equals 12 Unidades Tributarias Mensuales (“UTM”), a Chilean inflation-indexed monthly tax unit used to define fines, among other purposes. As of December 31, 2018, one UTM was equivalent to Ch$ 48,353 and one UTA was equivalent to Ch$580,236.
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 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, 2018.

We are a Chilean company engaged through our subsidiaries and jointly-controlled companies in the electricity generation and transmission and distribution businesses in Argentina, Brazil, Colombia 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, Enel Distribution Sao Paulo and Cien in Brazil, Emgesa in Colombia, 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 and Enel Distribution Goias in Brazil, Codensa in Colombia and Enel Distribution Peru in Peru. For additional information relating to our main 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 part of this process, the former Enersis S.A. changed its name to Enel Américas S.A. on December 1, 2016. For additional information relating the company and the corporate reorganization completed in 2016, please see “Item 4. Information on the Company — A. History and Development of the Company — History” and “— The 2016 Reorganization”.

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 56.4% of us and is our ultimate controlling shareholder.

7

PRESENTATION OF INFORMATION

Financial Information

In this Report, unless otherwise specified, references to “U.S. dollars,” “US$,” are to dollars of the United States of America (“United States”); references to “Ar$” or “Argentine pesos” are to the legal currency of Argentina; references to “R$,” or “reais” are to Brazilian reais, the legal currency of Brazil; references to “pesos” or “Ch$” are to Chilean pesos, the legal currency of Chile; references to “CPs” or “Colombian pesos” are to the legal currency of Colombia references to “soles” are to Peruvian Soles, the legal currency of Peru; 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 in order to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month. As of December 31, 2018, one UF was equivalent to Ch$ 27,565.79. The U.S. dollar equivalent of one UF was US$ 39.68 as of December 31, 2018, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2018, of Ch$ 694.77 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, 2018.

Since 2017, our functional currency is the U.S. dollar, and therefore our consolidated financial statements and other financial information concerning us included in this Report are presented in U.S. dollars. The change of our functional currency was recorded as of January 1, 2017, by translating all items of our consolidated financial statements to the new functional currency, using the exchange rate of Ch$ 669.47 as of January 1, 2017. We also changed our presentation currency of our consolidated financial statements from the Chilean peso to the U.S. dollar. The change in the presentation currency was applied retrospectively as if the U.S. dollar had always been the presentation currency of the consolidated financial statements. The consolidated financial statements for the year ended as of December 31, 2016, was restated in U.S. dollars using the average exchange rate for the period.  For further information about the change of our functional currency, please refer to Note 3 of the Notes to our consolidated financial statements.

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 of 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 participation in associated companies over which we exercise significant influence are 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 and 2.5 of the Notes to our consolidated financial statements.

During 2016, we completed a corporate reorganization, which involved the separation of our Chilean and non-Chilean electricity businesses, resulting in our retaining only the non-Chilean electricity businesses, effective as of March 1, 2016. All operations regarding the former Chilean businesses have been presented as discontinued operations. In order to comply with conditions established under IFRS, the financial statements for the year ended as of December 31, 2016 include discontinued operations for two months. The financial statements for the year ended December 31, 2018 and 2017 do not include discontinued operations. For additional information relating to the corporate reorganization, please see “Item 4. Information on the Company — A. History and Development of the Company — The 2016 Reorganization.”

This Report may contain translations of certain 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, 2018, 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 shown in this Report could have been or could be converted into U.S. dollars or Chilean pesos, as the case may be, at such rate or at any other rate. See “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”.

Technical Terms

References to “TW” are to terawatts (10(12) watts or a trillion watts); references to “GW” and “GWh” are to gigawatts (10(9) watts or a billion watts) and gigawatt hours, respectively; references to “MW” and “MWh” are to megawatts (10(6) watts or a million watts) and megawatt hours, respectively; references to “kW” and “kWh” are to kilowatts (10(3) watts or a thousand watts) and kilowatt hours,

8

respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. References to “BTU” and “MBTU” are to 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 with respect to 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 are presenting in this Report corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its own operation.

Statistics relating to aggregate annual electricity production are expressed in GWh and based on a year of 8,760 hours, except for leap years, which are based 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 own 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 total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical losses.

Calculation of Economic Interest

References are made in this Report to the “economic interest” of Enel Américas in its related companies. We could have direct and indirect interest is such companies. In circumstances where we do not directly own an interest in a related company, our economic interest in such ultimate related 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 related company. For example, if we directly own a 6% equity stake in an associated 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.  Because of this rounding, it is possible that amounts in tables may not add up to exactly the same amounts as the sum 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 from operations;

·our dividend policy;

·the future impact of competition and regulation;

·political and economic conditions in the countries in which we or our related companies 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 and interventionist measures by authorities in the markets in South America where we conduct our businesses;

·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 with respect to 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 to reflect 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.

10

RECENT DEVELOPMENTS

On February 27, 2019, we publicly announced our intention to undertake a capital increase for up to US$ 3.5 billion in cash (the “Capital Increase”) and on April 25, 2019, our Board of Directors unanimously approved setting the amount of the Capital Increase at US$3.0 billion, subject to shareholder approval.  If successful, the net cash proceeds of the offering of the newly authorized shares of common stock in the Capital Increase would be used as follows:

1.Repayment of Enel Brasil debt: The Company intends to apply the proceeds first to provide up to US$ 2.65 billion to its subsidiary, Enel Brasil, through a subsequent capital increase in Enel Brasil and/or one or more loans to Enel Brasil to enable it to repay a loan currently provided by Enel Finance International N.V. (“EFI”) to Enel Brasil, which replaced Enel Brasil’s debt with banks incurred in connection with the acquisition of Enel Distribution Sao Paulo.

2.Restructuring of pension fund liabilities.  The Company intends to use the US$350 million balance of the proceeds for the restructuring of pension fund obligations of Enel Distribution Sao Paulo.

An Extraordinary Shareholders’ Meeting (“ESM”) has been summoned to be held on April 30, 2019, to approve, among other things, the Capital Increase through the issuance of common shares, which will have the same rights as the outstanding shares of common stock already issued. Approval of the Capital Increase includes approval of the formula to determine the subscription price, which will be denominated in U.S. dollars and determined as (i) the weighted-average price of the Company’s common stock on the two Chilean stock exchanges for the five Chilean trading days preceding the start of the statutory preemptive rights offering period, with the price on each such Chilean trading day converted into U.S. dollars based on the dólar observado for such day, (ii) less a 5% discount, together with the delegation of authority to the Board of Directors to make the final determination of the subscription price based on such formula.

If the Capital Increase is approved at the ESM by at least two thirds of the outstanding common stock and proceeds, the offering of the newly authorized shares will first be undertaken within the 30-day statutory preemptive rights offering period provided by Chilean law.  The newly authorized shares not subscribed during the statutory preemptive rights offering period will be offered during a second subscription rights offering period subject to the same price and certain other terms and conditions as those of the statutory preemptive rights offering period, only to those shareholders and transferees who exercised their statutory preemptive rights in the preemptive rights offering period, in proportion to the number of new shares subscribed by them.

Our controlling shareholder, Enel S.p.A., owns a beneficial interest of 56.4% of the Company’s common stock as of the date of this Report and has publicly stated that if the Capital Increase is approved and proceeds, it intends, subject to market conditions, to acquire additional shares of the Company’s common stock in the Capital Increase in proportion to its ownership interest in it as of the record date to be established for the Capital Increase by exercising preemptive rights to subscribe for shares of the Company’s common stock.

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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.Selected Financial Data.

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, 2018 and 2017 and for each of the years in the three-year period ended December 31, 2018 are derived from our audited consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2016, 2015 and 2014, and for the years ended December 31, 2015 and 2014 are derived from our consolidated financial statements not 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 of the change of our functional currency from Chilean pesos to U.S. dollars in 2017. The change of our functional currency was recorded as of January 1, 2017, by translating all items of our consolidated financial statements to the new functional currency, using the closing exchange rate at the date of exchange. We also changed our presentation currency of our consolidated financial statements from Chilean pesos to U.S. dollars. The change in the presentation currency was applied retrospectively as if the U.S. dollar had always been the presentation currency of the consolidated financial statements. The consolidated statement of financial position data as of December 31, 2016, 2015 and 2014 were translated into U.S. dollars using the closing U.S. dollar Observed Exchange Rate (dólar observado) of Ch$ 669.47, Ch$710.16 and Ch$ 606.75 per US$ 1.00, respectively. The consolidated statement of comprehensive income data for the years ended December 31, 2016, 2015 and 2014 were translated into U.S. dollars using the average exchange rates of Ch$ 676.19, Ch$ 654.71 and Ch$ 569.76 per US$ 1.00, respectively.  For further information about the change of our functional currency please refer to Note 3 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. Amounts in the tables are expressed in millions of U.S. dollars, except for ratios, operating data and data for shares and American Depositary Shares (“ADS”).

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

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	As of and for the year ended December 31,
	2018		2017		2016		2015		2014
	(US$ millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income	13,184		10,438		7,643		8,097		9,138
Operating costs(1)	(10,750	)	(8,219	)	(5,843	)	(6,181	)	(6,702	)
Operating income from continuing operations	2,435		2,219		1,800		1,917		2,436
Financial results(2)	(333	)	(582	)	(439	)	43		(374	)
Other gains	1		5		12		(10	)	2
Share of profit (loss) of associates and joint venture accounted for using the equity method	2		3		3		5		4
Income from continuing operations before income tax	2,105		1,646		1,376		1,955		2,068
Income tax expenses, continuing operations	(438	)	(519	)	(531	)	(800	)	(748	)
Net Income from continuing operations	1,667		1,127		845		1,155		1,320
Profit after tax from discontinued operations	—		—		170		593		378
Net income	1,667		1,127		1,015		1,748		1,698
Net income attributable to the parent Company	1,201		709		566		1,011		1,004
Net income attributable to non-controlling interests	466		417		448		738		694
Basic and diluted earnings from continuing operations per average number of shares (US$ per share)	0.021		0.012		0.009		0.013		0.015
Basic and diluted earnings from continuing operations per average number of ADS (US$ per ADS)	1.045		0.617		0.453		0.638		0.732
Basic and diluted earnings from discontinued operations per average number of shares (US$ per share)	—		—		0.002		0.008		0.006
Basic and diluted earnings from discontinued operations per average number of ADS (US$ per ADS)	—		—		0.116		0.392		0.290
Total basic and diluted earnings per average number of shares (US$ per share)	0.021		0.012		0.009		0.013		0.015
Total basic and diluted earnings per average number of ADSs (US$ per ADS)	1.045		0.617		0.453		0.638		0.732
Cash dividends per share (US$ per share)	0.006		0.005		0.007		0.010		0.012
Cash dividends per ADS (US$ per ADS)	0.309		0.249		0.332		0.509		0.607
Weighted average number of shares of common stock (millions)	57,453		57,453		49,769		49,093		49,093
Consolidated Statement of Financial Position Data
Total assets	27,396		20,169		16,851		21,754		26,240
Non-current liabilities	8,914		6,956		5,150		3,878		7,330
Equity attributable to the parent company	6,724		6,481		6,200		8,486		10,222
Equity attributable to non-controlling interests	2,108		1,798		1,680		3,047		3,424
Total equity	8,832		8,279		7,880		11,532		13,645
Capital stock(3)	6,763		6,763		6,904		8,173		9,566
Other Consolidated Financial Data
Capital expenditures (CAPEX)(4)	1,541		1,371		1,230		2,081		1,912
Depreciation, amortization and impairment losses(5)	923		728		630		550		683

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(1)Operating expenses represent raw materials and consumables used, other work performed by the entity and capitalized, employee benefit expenses, depreciation and amortization expenses, impairment loss recognized in the period’s profit or loss and other expenses.

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

(3)Capital stock represents issued capital.

(4)CAPEX figures represent cash flows used for purchases of property, plant and equipment and intangible assets for each year.

(5)For further detail please refer to Note 31 of the Notes to our consolidated financial statements.

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	As of and for the year ended December 31,
	2018	2017	2016	2015	2014
OPERATING DATA OF PRINCIPAL SUBSIDIARIES(1)
Edesur (Argentina)
Electricity sold (GWh)	17,548	17,736	18,493	18,492	17,972
Number of customers (thousands)	2,530	2,529	2,505	2,479	2,464
Total energy losses (%)(2)	14.2	12.0	12.0	11.6	10.8
Enel Distribution Rio (Brazil)
Electricity sold (GWh)	11,091	11,091	11,181	11,096	11,678
Number of customers (thousands)	2,959	3,030	3,054	2,997	2,876
Total energy losses (%)(2)	21.0	20.4	19.4	19.4	20.3
Enel Distribution Ceara (Brazil)
Electricity sold (GWh)	11,843	11,522	11,628	11,229	11,165
Number of customers (thousands)	3,933	4,017	3,890	3,757	3,625
Total energy losses (%)(2)	13.9	13.6	12.5	12.5	12.8
Enel Distribution Goias (Brazil)
Electricity sold (GWh)	13,755	12,264	—	—	—
Number of customers (thousands)	3,027	2,928	—	—	—
Total energy losses (%)(2)	11.6	11.7	—	—	—
Enel Distribution Sao Paulo (Brazil)
Electricity sold (GWh)	24,693	—	—	—	—
Number of customers (thousands)	7,224	—	—	—	—
Total energy losses (%)(2)	9.5	—	—	—	—
Codensa (Colombia)
Electricity sold (GWh)	14,024	13,790	13,632	13,946	13,660
Number of customers (thousands)	3,439	3,340	3,248	2,865	2,772
Total energy losses (%)(2)	7.7	7.8	7.1	7.1	7.2
Enel Distribution Peru (Peru)
Electricity sold (GWh)	8,045	7,934	7,782	7,624	7,339
Number of customers (thousands)	1,423	1,397	1,367	1,337	1,293
Total energy losses (%)(2)	8.1	8.2	7.8	8.1	8.2
Enel Américas(3)
Installed capacity in Argentina (MW) (3) (4)	4,419	4,419	4,537	4,537	4,502
Installed capacity in Brazil (MW)(4) (5)	1,354	1,354	1,372	992	987
Installed capacity in Colombia (MW) (3) (4)	3,499	3,467	3,509	3,509	3,460
Installed capacity in Peru (MW) (3) (4)	1,985	1,979	2,026	1,977	1,984
Generation in Argentina (GWh)	13,949	14,825	13,124	15,204	14,390
Generation in Brazil (GWh)(5)	3,755	4,034	4,034	4,398	5,225
Generation in Colombia (GWh)	14,052	14,765	14,952	13,705	13,559
Generation in Peru (GWh)	8,106	7,430	8,698	8,801	9,062

(1)Some information may be different than reported in previous periods. For further details, please refer to “Item 4. Information on the Company — B. Business Overview. — Electricity Distribution Business.”

(2)Energy losses in distribution arise from illegally tapped energy as well as technical losses. They are calculated as the difference between total energy generated, and purchased (GWh) and the energy sold excluding tolls and energy consumption not billed (GWh), within a given period. Losses are expressed as a percentage of total energy purchased.

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(3)Installed capacity figures may differ from previous years, since this year we are reporting the net installed capacity instead of the gross installed capacity.

(4)Prior to 2017, figures correspond to gross installed capacity.

(5)The 2017 and 2018 data includes the capacity and generation of the Volta Grande hydroelectric plant, as a result of its acquisition and consolidation since November 2017.

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 peso price 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 exchange rate fluctuations affect the price of our American Depositary Shares (“ADSs”) as well as the amount of dividends to be paid (see “Item 8. Financial Information — A. Consolidated Statements and Other Financial Information — Dividends”).  In addition, to the extent that significant financial liabilities are denominated in foreign currencies, exchange rate fluctuations may have a significant impact on earnings.

For further details regarding variations 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 “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 — d. Economic Conditions — Local Currency Exchange Rate.”

B.Capitalization and Indebtedness.

Not applicable.

C.Reasons for the Offer and Use of Proceeds.

Not applicable.

D.Risk Factors.

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

Governmental authorities have altered monetary, credit, tariff, tax and other policies to influence the course of South American countries, including Argentina, Brazil, Colombia and Peru.  Even though we do not have electricity operations in Chile, we are a company established under the laws of the Republic of Chile, and are also subject to changes in Chilean tax, labor and monetary laws, among others.  Other governmental actions in these South American countries have also involved wage, price and tariff rate controls and other interventionist measures, such as expropriation or nationalization.

In the distribution business, if we do not meet certain minimum service and technical standards, we may lose our concessions.  In some concession areas, such as those in Buenos Aires, Goiás and Rio de Janeiro, it may be especially difficult to meet certain minimum standards which, if not met, empower regulators to revoke our concessions and reassign them to our competitors.

For 2019, we expect that there will be tax reforms and amendments to the current tax laws in Brazil, Chile, Colombia and Peru. 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 or diplomatic developments, including the response by governments in the region to these circumstances, could also reduce our profitability.

Our businesses depend heavily on hydrology, flooding, storms, ocean currents and other weather conditions.

Approximately 55% of our consolidated installed generation capacity in 2018 was hydroelectric.  Accordingly, extremely dry hydrological conditions could adversely affect our business, results of operations and financial condition.  Regional hydrological conditions have often been affected by two weather phenomena - El Niño and La Niña - that influence rainfall and result in droughts, impacting our ability to dispatch energy from our hydroelectric facilities.

El Niño has affected Colombian hydrologic conditions in the past, where 87% of our installed capacity is hydroelectric, leading to rainfall deficits and high temperatures, and as a consequence, higher energy prices.  In March 2017, “El Niño Costero” in Peru led to unusually heavy rains, which flooded the Santa Eulalia River, caused innumerable landslides and avalanches in the coastal basins and resulted in the stoppage of several of our hydroelectric plants, mainly our Callahuanca (81 MW) and Moyopampa (69 MW)

16

hydroelectric plants.  As of the date of this Report, all six hydro power plants of Enel Generation Peru are in operations. Each El Niño event is different and, depending on its intensity and duration, the magnitude of the social and economic effects could be material.

The distribution business is also affected by inclement weather, mainly in Argentina.  With extreme temperatures, demand can increase significantly within a short period of time, which could affect service and result in service outages which may result in fines.  Depending on weather conditions, results obtained by our distribution business can vary from year to year.

Our operating expenses increase during drought periods when thermal plants, which have higher operating costs relative to hydroelectric plants, are dispatched more frequently.  In addition, depending on our commercial obligations, we may need to buy electricity at higher spot prices in order to comply with our contractual supply obligations and the cost of these electricity purchases may exceed our contracted electricity sale prices, thus potentially producing losses from those contracts.  For further information with respect to 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 plants, including our facilities that use natural gas, fuel oil or coal, in the following manner:

·Our thermal plants require water for cooling and droughts may reduce the availability of water and increase the cost of transportation. 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.

·Thermal power plants that burn natural gas generate emissions such as nitrogen oxide (NO), carbon dioxide (CO2) and carbon monoxide (CO) gases. When operating with diesel, they release NO, sulfur dioxide (SO2) and particulate matter into the atmosphere. Coal fired plants generate SO2 and NO emissions. Therefore, use of thermal plants during droughts generally increases the risk of producing higher levels of greenhouse emissions.

A full recovery from the drought that has been affecting the regions where most of our hydroelectric plants are located may last for an extended period but new drought periods may recur in the future. A prolonged drought may exacerbate the risks described above and have a further adverse effect upon our business, results of operations and financial condition.

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

The Argentine peso experienced a steep devaluation against the U.S. dollar during 2018, with a 20% depreciation in just one day, on August 30, 2018. This devaluation was the result of the internal economic deterioration, increased external debt and high inflation.  Although the pace of the devaluation of the Argentine peso against the U.S. dollar has slowed down recently, the increase in interest paid on time deposits has been insufficient to offset the inflation rate. The interest rate established by the Argentine Central Bank was already at a maximum of 45% per annum, when the Argentine monetary authority increased it to 60% per annum. Even though the Argentine government has been taking fiscal, monetary and other actions to soften the effect of devaluation, including several agreements with the International Monetary Fund, the devaluation of the Argentine peso may continue in 2019 and future years.

Argentina’s sovereign creditworthiness has also seriously deteriorated, reaching a maximum of 780 basis points over its sovereign debt at par value during August 2018. Argentina’s sovereign debt rating was cut from “B+” to “B” by Standard & Poor’s in November 2018. Moody’s maintained the rating at “B2,” updated in November 2018 with a “stable” outlook, while Fitch maintained the rating at “B,” but changed the outlook from “stable” to “negative” in November 2018.

As a result, as of July 2018, Argentina is 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 in order 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 indexation of the nonmonetary assets and liabilities of our Argentine subsidiaries prior to January 1, 2018. Such gain has been presented as an adjustment to our retained earnings as of January 1, 2018, of US$ 961 million, after tax. The indexation gain for the year ended December 31, 2018, of US$ 271 million is included in our financial results.

17

Further deterioration of Argentina’s economy could adversely affect our results of operations and financial condition.  For more information, please see Note 8 of the Notes to our consolidated financial statements.

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

Our businesses and the tariffs we charge to our customers are subject to extensive regulation, which may adversely affect our profitability.  For example, governmental authorities in any of the countries in which we operate may impose material rationing policies during droughts or prolonged failures of power facilities, which may adversely affect our business, results of operations and financial condition. Our operating subsidiaries are subject to environmental regulations which require us to perform environmental impact studies for future projects and obtain constructions and operating permits from both local and national regulators.  The approval of these environmental impact studies may be withheld and delayed by governmental authorities.

Governmental authorities may also delay the distribution tariff review process, or tariff adjustments determined by governmental authorities may be insufficient to pass through our costs to customers as was the case with Codensa. Our Colombian distribution company, whose tariff review has been expected to occur since 2015, may finally have new regulated tariffs approved during 2019.  Similarly, electricity regulations issued by governmental authorities in the countries in which we operate may affect the ability of our generation companies to collect revenues sufficient to offset their operating costs, which could adversely affect our business, results of operations and financial condition.

Delays or modifications to any proposed project and laws or regulations may change or be interpreted in a manner that could adversely affect our operations or our plans, which could adversely affect our business, results of operations and financial condition.

Regulatory authorities may impose fines on our subsidiaries due to operational failures or breaches of regulations.

Our electricity businesses may be subject to regulatory fines for any breach of current regulations, including energy supply failures, in the four countries in which we operate.

Our electricity generation subsidiaries are supervised by local regulatory entities and may be subject to fines in cases where, in the opinion of the regulatory entity, the company is responsible for the operational failures that affect the regular energy supply to the system, including due to the lack of coordination with the system operator.  Our subsidiaries may be required to pay fines or compensate customers if those subsidiaries are unable to deliver electricity, even if such failures are not within their control, or when those subsidiaries do not meet environmental or other standards.  Fines may also be associated with breach of regulations.

In 2017 and 2018, Enel Distribution Sao Paulo was fined by ANEEL for a total amount of R$ 81 million due to three alleged infractions, one of them related to non-compliance with Ombudsman Tele-service and Call Center and the other two related to non-compliance with quality of service indicators.

In Argentina, as a result of the tariff review for the 2017-2021 period, Edesur’s fines for technical service quality, technical product and commercial quality have gradually increased.

We depend on payments from our subsidiaries and associates to meet our payment obligations.

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

Historically, we have not been able to access the cash flows of some of our operating subsidiaries at all times due to government regulations, strategic considerations, economic conditions and credit restrictions.  In the future, we may not always be able to rely on cash flows from operations in those entities 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 and equity affiliates to pay dividends and make loan payments or other distributions to us.  In addition, the ability of any of our subsidiaries that are not wholly-owned to distribute cash to us may be limited by the directors’ fiduciary duties of such subsidiaries to their minority shareholders.  Furthermore, some of our subsidiaries may be forced by local authorities, in accordance with applicable

18

regulation, to diminish or eliminate dividend payments.  As a consequence of such restrictions, our subsidiaries could, under certain circumstances, be impeded from distributing cash to us.

Contractual Constraints. Distribution restrictions included in the credit agreements of our subsidiaries, including Enel Generation Piura and most of our subsidiaries in Brazil, may prevent dividends and other distributions to shareholders if they are not in compliance with certain financial ratios. Our credit agreements typically prohibit distributions if there is an ongoing default.

Operating Results of Our Subsidiaries. The ability of our subsidiaries and equity affiliates to pay dividends or make loan payments or other distributions to us is limited by their operating results. To the extent that the cash requirements of any of our subsidiaries exceed their available cash, cash will not be upstreamed to us.

In addition, the currency of any dividend paid by our subsidiaries is subject to depreciation in relation to our functional currency, which may have a negative impact on our ability to pay dividends to shareholders.

Any of the situations described above could adversely affect our business, results of operations and financial condition.

We are involved in litigation proceedings.

We are currently involved in various litigation proceedings, which could result in unfavorable decisions or financial penalties against us. In Brasil, Enel Distribution Goias is involved in tax litigation relating to claims that date back to a period before its privatization, which may not only have an adverse effect on us but may divert our resources and our management’s attention for many years.

In Colombia, we exercise control over Emgesa and Codensa through shareholder agreements with Grupo Energía Bogotá S.A. (“GEB”). In December 2017, we were notified that GEB had submitted to arbitration some differences arising between the parties on the distribution of 2016 net income of Emgesa and Codensa under the terms of the shareholder agreements.  GEB claims that we violated the provisions of the shareholder agreements, which regulate the distribution, obligating the parties to vote in favor of distribution of 100% of the profits that can be distributed each period. Instead, Emgesa and Codensa distributed 70% of the 2016 net income.  The claims seek the distribution of 100% of the profits for 2016 of each company.  Amounts in dispute are US$ 21 million for Codensa and US$ 27 million for Emgesa.  An adverse ruling would bring a precedent that will oblige us to always vote for 100% distribution of the profits of each year, which may not be financially prudent for our subsidiaries and for us.

Our financial condition or results of operations could be adversely affected if we are unsuccessful in defending litigations or other lawsuits and proceedings against us.  For further information on litigation proceedings, please see “Item 8. Financial Information — A. Consolidated Statements and Other Financial Information — Legal Proceedings” and Note 36.3 of the Notes to our consolidated financial statements.

Political events or financial or other crises in any region worldwide can have a significant impact on the countries in which we operate, and consequently, may adversely affect our operations as well as our liquidity.

The four countries in which we operate are vulnerable to external shocks, including financial and political events, which could cause significant economic difficulties and affect growth.  If any of these countries experience lower than expected economic growth or a recession, it is likely that our customers will demand less electricity and that some of our customers may experience difficulties paying their electric bills, possibly increasing our uncollectible accounts.  Any of these situations could adversely affect our results of operations and financial condition.

Financial and political events in other parts of the world could also adversely affect our business.  For example, since 2018, the U.S. and China have been involved in a trade war involving protectionist measures, which increased the volatility of financial markets worldwide due to the uncertainty of political decisions.  Instability in the Middle East or in any other major oil producing region could also result in higher fuel prices worldwide, increasing the operating cost for our thermal generation plants and adversely affect our results of operations and financial condition.

The U.S. federal government has experienced shutdowns in recent times, including the 2018-2019 U.S. government shutdown, which affected the SEC among many other federal agencies, and extended for 35 days, the longest federal government shutdown in U.S. history.  Even temporary or threatened U.S. government shut-downs could have a material adverse effect on the timing, execution and increased expense associated with our international financing and our M&A activities.

In addition, an international financial crisis and its disruptive effects on the financial industry could adversely impact our ability to obtain new bank financings on the same historical terms and conditions that we have benefited from to date.

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Political events or financial or other crises could also diminish our ability to access the capital markets in the countries in which we operate as well as the international capital markets for other sources of liquidity, or increase the interest rates available to us.  Reduced liquidity could, in turn, adversely affect our capital expenditures, our long term investments and acquisitions, our growth prospects and our dividend payout policy.

South American economic fluctuations, political instability and corruption scandals may affect our results of operations and financial condition as well as the value of our securities.

All of our operations are located in South America.  Accordingly, our consolidated revenues may be affected by the performance of South American economies as a whole.  If local, regional, or worldwide economic trends adversely affect the economy of any of the four countries in which we operate, our financial condition and results from operations could be adversely affected.  We operate in Argentina, Brazil, Colombia and Peru, more volatile countries that have at times experienced political instability, including due to corruption scandals involving several high ranking government officials.

Insufficient cash flows from our subsidiaries located in these countries have resulted in their inability to meet debt obligations and the need to seek waivers to comply with some debt covenants or, to a limited extent, to require guarantees or other emergency measures from us as shareholders, especially in Brazil and Argentina. For further details regarding recent financial support provided to our Brazilian subsidiaries, please refer to “Item 7. Major Shareholders and Related Party Transactions — B. Related Party Transactions.”

Future adverse developments in these countries may impair our ability to execute our strategic plan, which could adversely affect our growth and our results of operations and financial condition.

In addition, South American financial and securities markets are influenced by economic and market conditions in other countries, which could adversely affect the value of our securities.

Construction and operation of power plants may encounter significant delays or halt and cost over-runs as well as stakeholder opposition that may damage our reputation and potentially result in impairment of our goodwill.

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, and they may be subject to construction delays, strikes, adverse weather conditions, natural disasters, civil unrest, accidents, and human error.  Any such event could adversely impact our business, results of operations and financial condition.

Market conditions when the projects are initially approved may differ significantly from those that prevail when the projects are completed, which in some cases may make them less profitable.  Deviations in these assumptions, including the estimates of the timing and expenditures related to these projects, may lead to cost over-runs and a completion time widely exceeding our initial estimates, which in turn may have a material adverse effect in our business, results of operation and financial condition.

The locations where we may develop new projects are also sometimes highly challenging in terms of geographical topography (mainly in Colombia and Peru), such as mountain slopes, jungles or other areas with very limited access. Additionally, given the geographical location for some projects, there may be additional inherent archeological heritage risks. These factors may also lead to significant delays and cost overruns.

The operation of our thermal power plants, especially those that are coal fired, may also affect our goodwill with stakeholders, due to greenhouse gas emissions, which could adversely affect the environment and local residents. In addition, communities may have their own interests and different perceptions of the company, influenced by stakeholders unrelated to our power plants. If the company fails to appropriately deal with all relevant stakeholders, it may face opposition, which could adversely affect our reputation, stall operations or lead to litigation threats or actions. Our reputation is the foundation of our relationship with key stakeholders and other constituencies. If we are unable to effectively manage real or perceived issues that could affect us negatively, our business, results of operations and financial condition could be adversely affected.

Damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders and ultimately lead to projects and operations that may be abandoned, causing our share prices to drop and hindering our ability to attract and retain valuable employees, any of which could result in an impairment of our goodwill with stakeholders.

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

On an ongoing basis, we review acquisition prospects that may increase our market coverage or provide synergies with our existing businesses, though there can be no assurance that we will be able to identify and consummate suitable acquisition transactions in the future.  The acquisition and integration of independent companies that we do not control is generally a complex, costly and time-consuming process and requires significant efforts and expenditures.  If we consummate further acquisitions, such as Enel Distribution Sao Paulo in 2018, they could result in the incurrence of substantial debt and assumption of unknown liabilities, the potential loss of key employees, amortization of expenses related to tangible assets and the diversion of management’s attention from other business concerns.  For example, as a result of the acquisition of Enel Distribution Sao Paulo, our liabilities increased considerably, due to the new debt for the purchase itself, as well the consolidation of Enel Distribution Sao Paulo’s existing debt.

In addition, integrating acquired businesses may be difficult, expensive, time-consuming and a strain on our resources and our relationships with our employees and customers and ultimately may not be successful or achieve the expected benefits.

Any delays or difficulties encountered in connection with acquisitions and the integration of their operations could have a material adverse effect on our business, financial condition or results of operations.

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

We own water rights for the supply of water from rivers, lakes and reservoirs near our production facilities, granted by each countries’ respective authority.  In Colombia, water rights or water concessions are granted 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 decrease or depletion of water.  In Colombia, water for human consumption has priority over any other use.  In Peru, the concessions are granted for indefinite periods and could be revoked due to scarcity or a decline in service quality.

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

Foreign exchange risk may adversely 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, our subsidiaries generate revenues in Argentine pesos, Peruvian nuevos soles, Brazilian reais and Colombian pesos.  Furthermore, we pay our dividends in Chilean pesos. We generally have been and will continue to be materially exposed to currency fluctuations of our local currencies against the U.S. dollar because of time lags and other limitations to peg our tariffs to the U.S. dollar.  Because of this exposure, the cash generated by our subsidiaries and the value of dividends can decrease substantially, expressed in U.S. dollars, when local currencies have experienced a devaluation against the U.S. dollar.  Future volatility in the exchange rate of the currencies 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.

Our long-term energy sale contracts and the liberalization of our markets are subject to fluctuations in the market prices of certain commodities, energy and other factors.

We have economic exposure to fluctuations in the market prices of certain commodities as a result of the long-term energy sales contracts into which we have entered.  Our subsidiaries have material obligations as selling parties under long term fixed-price electricity sales contracts.  Prices in these contracts are indexed for different commodities, the exchange rate, inflation, and the market price of electricity.  Adverse changes to these indices would reduce the rates we charge under our long term fixed-price electricity sales contracts, which could adversely affect our business, results of operations and financial condition.  In our distribution business, we are also exposed to fluctuations in energy prices.  In Argentina, with the liberalization of the energy market, this risk could become more relevant in the future.

In some countries, including Peru, where our customers may freely select unregulated tariffs, such choice may be detrimental to the operating income we would have received had they selected a regulated regime instead.  Customers may also sometimes choose an alternative energy provider, which could adversely affect our business, results of operations and financial condition.

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Our controlling shareholder may exert influence over us and may have a different strategic view for our development than that of our minority shareholders.

Enel, our controlling shareholder, owns a beneficial interest of 56.4% of our share capital as of the date of this report, and has the power to determine the outcome of all material matters that require a simple majority of shareholders’ votes, in accordance with Chilean corporate law, such as the election of the majority of our board members and, subject to a majority of contractual and legal restrictions, the adoption of our dividend policy. Enel also exercises significant influence over our business strategy and operations.  Its interests may in some cases differ from those of our minority shareholders.  For example, Enel conducts its business operations in the field of renewable energy in non-Chilean South American countries through Enel Green Power S.p.A. in which we have no equity interest.  Certain conflicts of interest affecting Enel in these matters may be resolved in a manner that is different from interests of our company or of our minority shareholders.

Our electricity business is subject to risks arising from natural disasters, catastrophic accidents and acts of terrorism, which could adversely affect our operations, earnings and cash flow.

Our primary facilities include power plants, transmission and distribution assets. Our facilities may be damaged by earthquakes, fires, and other catastrophic disasters arising from natural or accidental human causes, as well as acts of vandalism, riot, 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 to us not covered by our business interruption insurance. There may be lags between a major 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.

We are subject to financing risks, such as those associated with funding our new projects and capital expenditures, and risks related to refinancing our maturing debt; we are also subject to debt covenant compliance, all of which could adversely affect our liquidity.

As of December 31, 2018, our consolidated debt totaled US$ 8,917 million (including US$ 2,652 million in debt with EFI, a related company).

Some of our debt agreements are subject to (1) financial covenants, (2) affirmative and negative covenants, (3) events of default, (4) mandatory prepayments for contractual breaches, and (5) certain change of control clauses for material mergers and divestments, among other provisions.  A significant portion of our financial indebtedness is subject to cross default provisions, which have varying definitions, criteria, materiality thresholds and applicability with respect to subsidiaries that could give rise to such a cross default.

In the event that we or any of our significant subsidiaries breach any of these material contractual provisions, our debtholders may demand immediate repayment, and a significant portion of our indebtedness could become due and payable.  We may be unable to refinance our indebtedness or obtain such refinancing on terms acceptable to us.  In the absence of such refinancing, we could be forced to dispose of assets in order to make the payments due on our indebtedness under circumstances that might not be favorable to obtaining the best price for such assets.  Furthermore, we may be unable to sell our assets quickly enough, or at sufficiently high prices, to enable us to make such payments.

We may also be unable to raise the necessary funds required to finish our projects under development or under construction.  Market conditions prevailing at the moment we require these funds or other unforeseen project costs can compromise our ability to finance these projects and expenditures.

As of the date of this Report, Brazil is the country with our highest refinancing risk.  As of December 31, 2018, debt of our Brazilian subsidiaries amounted to US$ 2,837 million (excluding debt with EFI).  Our inability to finance new projects or capital expenditures or to refinance our existing debt could adversely affect our results of operation and financial condition.

We rely on electricity transmission facilities that we do not own or control, as well as on gas pipeline infrastructure and fuel supply contracts.  If these facilities do not provide us with an adequate service, we may not be able to deliver the power 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 transmission is disrupted, or transmission capacity is inadequate, we may be unable to sell and deliver our electricity.  If a region’s power transmission infrastructure is inadequate, our recovery of sales costs and profits may be insufficient.  If restrictive transmission price regulation is imposed, transmission companies upon whom we rely may not have sufficient incentives to invest in expansion of their transmission infrastructure, which could adversely affect our operations and

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financial results.  The construction of new transmission lines may take longer than in the past, mainly because of social and environmental requirements that are creating uncertainties as to the timing of project completion. In addition, in some of the countries in which we operate, the increase of NCRE projects is creating congestion for the current transmission systems as these projects can be built relatively quickly, while new transmission projects may take longer to be built.  In Argentina, for example, the lack of investment in transmission lines will reduce incentives for the development of NCRE projects.

We also rely on pipelines to obtain natural gas, mainly in Peru, where most of our generation capacity is thermal. The Peruvian system had faced gas and energy congestion due to the lack of sufficient capacity in the pipeline and transmission lines, respectively, which led to higher spot prices. Our thermal generation facilities also purchase gas, coal, diesel and other fuels to produce electricity, depending on the technology. Any contract breach or supply shortage may prevent our facilities from producing electricity in a timely manner.  Due to the liberalization of the energy market in Argentina, including the fuel market, our Argentine generating subsidiaries will be subject to the volatility of fuel prices, mainly LNG, which in winter could be scarce due to the higher residential demand.  Before the regulatory changes, these risks were undertaken by CAMMESA.

Fortaleza owns and operates a 327 MW natural gas combined-cycle power plant, with the capacity to generate one-fourth of the electricity requirements of more than 9 million people in Ceará. Fortaleza has a contract with Petrobras, designated by the Brazilian Federal Government to supply natural gas under the Thermoelectric Priority Program, under which the gas supply to Fortaleza was supposed to be guaranteed until 2023 at a contractually defined price. The main purpose of the contract is to avoid a short term energy crisis by providing security through thermal generation, as hydro power plants are vulnerable to hydrological conditions, as was the case in 2018. Since September 2001, the Brazilian government allowed Fortaleza facility to receive all needed fuel until the end of the PPA period, but there are important unresolved matters. During 2018, Fortaleza’s operating costs considerably increased due to higher energy purchases resulting from the gas supply stoppage, which forced the company to purchase energy in the market in order to fulfill its contractual obligations with Enel Distribution Ceara, which had contracted to buy all of Fortaleza’s generation until 2023. Any such disruption, failure or lack of transmission facilities could interrupt our business or affect prices in the market, which could adversely affect our results of operations and financial condition.

Our business may experience adverse consequences if we are unable to reach satisfactory collective bargaining agreements with our unionized employees or if we are not able to retain key employees.

A large percentage of our employees are members of unions and have collective bargaining agreements that must be renewed on a regular basis. Our business, financial condition and results of operations could be adversely affected by a failure to reach agreement with any labor union representing such employees or by an agreement with a labor union that contains terms we view as unfavorable. The laws of many of the countries in which we operate provide legal mechanisms for judicial authorities to impose a collective bargaining agreement if the parties are unable to come to an agreement, which may materially increase our costs.

In addition, we employ many highly-specialized employees, and certain actions such as strikes, walk-outs or work stoppages by these employees, could adversely impact our business, results of operations and financial condition as well as our reputation.

The relative illiquidity and volatility of the Chilean securities market could adversely 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 since we are organized under the laws of the Republic of Chile and have our headquarters in Chile.  Chilean securities markets are substantially smaller and less liquid than the major securities markets in the United States or other developed countries.  The low liquidity of the Chilean market may impair the ability of shareholders to sell shares, or holders of ADSs to sell shares of our common stock withdrawn from the ADS program, into the Chilean market in the amount and at the price and time they wish to do so.  Also, the liquidity and the market for our shares or ADSs may be affected by a number of factors including variations in exchange and interest rates, the deterioration and volatility of the markets for similar securities and any changes in our liquidity, financial condition, creditworthiness, results and profitability.

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

All of our operations are located outside of the United States.  All of our directors and all of our officers reside outside of the United States and substantially all of their assets are located outside the United States.  If any investor 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 or to enforce judgments obtained in United States courts based upon the civil liability provisions of the federal securities laws of the United States against them in United States or Chilean courts.  In addition, there is doubt as to whether an action could be brought successfully in Chile on the basis of liability based solely upon the civil liability provisions of the United States federal securities laws.

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Interruption 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. In addition, we use our IT Systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. In our generation business, IT Systems are critical in controlling and monitoring our power plants’ operations, maintaining generation and network performance, generating invoices to bill customers, achieving operating efficiencies and meeting our service targets and standards. Our distribution business increasingly relies on IT Systems to monitor smart grids, billing processes for millions of customers and customer service platforms.  The operation of our generations, transmission and distribution systems 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 the information and communication among and between those parties has increased significantly since the deployment of smart meters and intelligent grids, especially in Brazil and Colombia, where we have installed a significant amount of smart meters.

Our generation, transmission and distribution facilities, IT Systems and other infrastructure, as well as the information processed in our IT Systems could be affected by cybersecurity incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, nation states and individuals, being among the emerging risks identified in our planning process. Cybersecurity incidents could harm our businesses by limiting our generation, transmission 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 liability. Our business systems are part of an interconnected system. Therefore, a 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 also negatively impact our business.

In addition, our business requires the collection and retention 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. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations, as well as our reputation with customers, shareholders and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems.

The cybersecurity threat is dynamic and evolves continually and, in the electricity industry, is increasing in sophistication, magnitude and frequency.  There can be no assurance that we can implement adequate preventive measures or accurately assess the likelihood of a cyber-incident. We are unable to quantify the potential impact of cybersecurity incidents on our business and our reputation. These potential cybersecurity incidents and corresponding regulatory action could result in a material decrease in revenues and may result in significant additional costs, including penalties, third party claims, repair costs, additional insurance expense, litigation costs, notification and remediation costs, security costs and compliance costs.

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 CMF 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 and our ADSs are listed and traded on the NYSE.

Our contact information in Chile is:

Contact Person:	Nicolás Billikopf
Street Address:	Santa Rosa 76, Santiago, Código Postal 8330099, Chile
Email:	nicolas.billikopf@enel.com

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Telephone:	(56-2) 2353-4628
Web site:	www.enelamericas.com

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

We are an electricity utility company engaged, through our subsidiaries and affiliates, in the generation, transmission and distribution of electricity businesses in Argentina, Brazil, Colombia, and Peru.  As of December 31, 2018, we had 11,257 MW of net installed generation capacity and 24.5 million distribution customers.  Our installed capacity is comprised of 112 generation units in the four countries in which we operate, of which 55% are hydroelectric power plants.  As of December 31, 2018, we had consolidated assets of US$ 27.4 billion and operating revenues of US$ 13.2 billion.

Since June 2009, our controlling shareholder has been the Italian company Enel, which as of December 31, 2018, beneficially owned 51.8% of our shares. As of the date of this Report, Enel owns a beneficial interest of 56.4%. Enel is an energy company with multinational operations in the power and gas markets, with a focus on Europe and Latin America. Enel operates in 34 countries across five continents, produces energy through a managed installed capacity of almost 90 GW, which includes 43 GW of renewable sources, and distributes electricity and gas through a network covering 2.2 million kilometers. With over 73 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enel shares trade on the Milan Stock Exchange.

We are one of the largest publicly listed companies in the electricity sector in South America.  We have been known as Enel Américas since the 2016 Reorganization described further below.  However, we trace our origins to Compañía Chilena de Electricidad Ltda. (“CCE” in its Spanish acronym), which was formed in 1921 as a result of the merger of Chilean Electric Tramway and Light Co., founded in 1889, and Compañía Nacional de Fuerza Eléctrica (“CONAFE” in its Spanish acronym), with operations dating back to 1919.  Following nationalization of CCE in the 1970s, during the 1980s, the Chilean electric utility sector was reorganized through the Chilean Electricity Law, known as the Decree with Force of Law No. 1 of 1982 (“DFL 1”).  CCE’s operations were divided into a generation company, AES Gener S.A. (“Gener”), an unrelated company, and two distribution companies, one with a concession in the Valparaíso Region, Chilquinta S.A., an unrelated company, and the other with a concession in the Santiago Metropolitan Region, Compañía Chilena Metropolitana de Distribución Eléctrica S.A.  From 1982 to 1987, the Chilean electric utility sector went through a process of re-privatization.  In August 1988, Compañía Chilena Metropolitana de Distribución Eléctrica S.A. changed its name to Enersis S.A. (“Enersis”), and became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A. (currently Enel Distribución Chile S.A.).  In the 1990s, we diversified into non-Chilean electricity generation, transmission and distribution in other South American countries.  Subsequent to the 2016 Reorganization (described below), we no longer hold electricity assets in Chile, but instead hold electricity generation, transmission and distribution assets in Argentina, Brazil, Colombia and Peru.

We began international operations in 1992 with our participation in Edesur, a distribution company, and Costanera, a generation company, both in Argentina. We then expanded into Peru in 1994 through our distribution company, Edelnor (now Enel Distribution Peru) and in 1995 acquired the electricity generation company Edegel (now Enel Generation Peru). Our presence in Brazil and Colombia began in 1996 through our Brazilian distributor, Ampla (now Enel Distribution Rio), and the Colombian generator, Codensa. In 1997, we acquired an interest in the Colombian generator Emgesa. We acquired the Brazilian distributor Coelce (now Enel Distribution Ceara) in 1998 and the Brazilian generator Fortaleza in the state of Ceará in 2002. In 2005, Enel Brasil was formed in order to manage all the generation, transmission and distribution assets held in Brazil, namely, Enel Distribution Rio, Enel Distribution Ceara, Fortaleza and Cachoeira Dourada and the transmission business held through Cien.

During the 2000’s we increased our participation in some of our existing subsidiaries. In 2006, Empresa de Generación Termoeléctrica Ventanilla S.A., a Peruvian generation company that was owned by the Spanish electric utility, Endesa, S.A. (Endesa Spain) at the time, merged with and into Edegel becoming a 457 MW thermoelectric generation company. In September 2007, we merged our generation subsidiaries in Colombia into our generation company Emgesa. As of December 31, 2018, we held a 48.5% economic and 54.6% voting interest in Emgesa and, pursuant to a shareholders’ agreement, we control and consolidate the company.  For more information regarding the control and consolidation of Emgesa, see “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.”  In October 2009, Enel Generation Chile purchased an additional 29.4% of Enel Generation Peru, increasing our economic interest in it from 19.8% to 37.5%., and we also acquired an additional 24% of Enel Distribution Peru, increasing our economic interest in the company from 33.5% to 57.5%.

In March 2013, we completed a capital increase proposed by Endesa, S.A. (“Endesa Spain”), our parent company at the time, through in-kind contributions from all of its equity interests in 25 companies in the five South American countries in which we then operated. The other shareholders had the right to contribute their proportional participation in cash.  The capital increase was first

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offered to existing shareholders through a preemptive rights offering registered with the CMF and the U.S. SEC and subsequently through a follow-on offering. The total Ch$ 2,846 billion (US$ 6 billion at that time) capital increase consisted of Ch$ 1,714 billion (US$ 3.6 billion) of in-kind contributions from Endesa Spain and Ch$ 1,132 billion (US$ 2.4 billion) in cash from minority shareholders (the “2013 capital increase”). Following the 2013 capital increase, we acquired additional interests in certain companies, directly or indirectly through our subsidiaries and undertook other reorganizations including the following transactions:

·In May 2014, we finalized a voluntary public offer to purchase the shares of our subsidiary Enel Distribution Ceara that we did not own.  The investment amounted to Ch$ 133 billion (at that time) and we reached a 64.9% economic interest in Enel Distribution Ceara.  Following the 2016 Reorganization, and as of December 31, 2018, we held a 74.1% economic interest in Enel Distribution Ceara.

·In September 2014, we acquired the indirectly held shares that Inkia Americas Holdings Limited had in Generandes Perú S.A. (39.0% of the company), the controlling company of Enel Generation Peru.  The total investment amounted to Ch$ 243 billion (US$ 413 million at that time) and we increased our economic interest in Enel Generation Peru by 21%, to 58.6%.

·In February 2017, we acquired 94.8% of the shares of Celg Distribuição S.A. (now Enel Distribution Goias) in a tender process organized by the Brazilian Government through BNDES.  The offer amounted to R$ 2,187 million (US$ 640 million at that time).  In May 2017, Enel Brasil acquired the remaining 5% of Enel Distribution Goias, which is now wholly owned, for R$ 82 million.

·In September 2017, we were awarded the 30-year concession auctioned by the Brazilian regulator to operate Volta Grande, the 380 MW hydroelectric power plant located in the State of Minas Gerais.  The power plant started commercial operations in 1974.  It is comprised of four generation units with an installed capacity of 95 MW each.  The tender amounted to R$ 1,419 million (US$ 445 million at that time) and the payment took place on November 30, 2017.  To carry out this transaction, we fully subscribed and paid a cash capital increase in Enel Brasil amounting to R$ 568 million (US$ 178 million).  This capital increase was partially financed with the remaining proceeds of the 2013 capital increase.

·On October 4, 2017, our wholly owned subsidiary Enel Perú acquired a 7.5% stake of Enel Distribution Peru on the Lima Stock Exchange.  This transaction amounted to 262 million Peruvian soles (US$ 80 million at that time).  As a result, we increased our economic interest in Enel Distribution Peru to 83.2%.

·On June 4, 2018, we completed a tender offer to acquire Enel Distribution Sao Paulo, the main distribution company in Sao Paulo, Brazil and among the largest distribution companies in South America.  Enel Distribution Sao Paulo, with more than 7.2 million customers, operates in a concession area of 4,500 square kilometers.  In the tender offer, we acquired 73.4% of the shares at R$45.22 per share.  Until July 4, 2018, all remaining Enel Distribution Sao Paulo shareholders were allowed to sell their shares at the same tender offer price. As a result, we now own 93.3% of the company. During September 2018, Enel Américas participated in a capital increase of Enel Distribution Sao Paulo. Consequently, our final ownership is 95.9%. The total investment to acquire Enel Distribution Sao Paulo was approximately US$ 2,235 million (using the exchange rate at that time).

The 2016 Reorganization

During 2016, we completed a corporate reorganization to separate our Chilean businesses from our non-Chilean businesses (the “2016 Reorganization”).

The 2016 Reorganization involved the separation of the respective Chilean and non-Chilean electricity generation, transmission and distribution businesses of Empresa Nacional de Electricidad S.A. (“Endesa Chile”), Chilectra and Enersis by means of a “demerger” under Chilean law and the subsequent distribution of the shares of the newly created entities to each company’s respective shareholders (collectively, the “Spin-Offs”).  The “demerger” or separation of the businesses occurred on March 1, 2016 and the Spin-Offs were effective in April 2016, with the creation and public listing of the shares of the newly incorporated entities: (i) Enersis Chile S.A. (“Enersis Chile”), which held the Chilean businesses of Enersis, (ii) Endesa Américas S.A. (“Endesa Américas”), which held the non-Chilean businesses of Endesa Chile, and (iii) Chilectra Américas S.A. (“Chilectra Américas”), which held the non-Chilean businesses of Chilectra.  The 2016 Reorganization also involved the merger between the companies holding the non-Chilean assets.  The merger became effective on December 1, 2016 and merged Endesa Américas and Chilectra Américas with and into Enersis Américas, with the latter continuing as the surviving company.  The merger combined the non-Chilean generation, transmission and distribution businesses under a single holding company, contributed to the simplification of the corporate structure of the group and provided benefits such as subsidiary cash leakage reduction, strategic interest alignment and increased decision-making and operational efficiencies.  As a consequence of the merger, we issued 9,232,202,625 new shares, of which 872,333,871 shares were deemed reacquired and held as treasury stock and were cancelled as a result of the approval of the cancellation by the shareholders at

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the ESM held on April 27, 2017.  As a result, our ultimate controlling shareholder, Enel, owned 51.8% of our outstanding shares as of December 31, 2018 and owns a beneficial interest of 56.4% as of the date of this Report, after making additional purchases in 2019.

As part of this process, Enersis changed its name to Enersis Américas S.A. on March 1, 2016 and subsequently to Enel Américas S.A. on December 1, 2016. On October 18, 2016 (i) Endesa Chile changed its name to Enel Generation Chile S.A.; (ii) Chilectra changed its name to Enel Distribución Chile S.A.; and (iii) Enersis Chile S.A. changed its name to Enel Chile S.A.

Enel X

During 2018, we formed Enel X Colombia S.A.S. (“Enel X Colombia”), which is wholly owned by Codensa.  The main purpose of Enel X Colombia is to focus on public lighting tenders, supplementing the activities of Codensa.  We also changed the name of Enel Soluçoes S.A., a wholly owned subsidiary of Enel Brasil, to Enel X Brasil S.A. (“Enel X Brasil”).  These companies will develop, implement and sell products and services that incorporate innovation and cutting-edge technology and are different from the sale of energy or concessioned energy distribution and associated services.  These Enel X companies expect to offer turnkey projects for municipalities and other public and governmental entities, industrial or residential customer appliances such as photovoltaic systems, heating ventilation air conditioning, led lighting, projects related to energy efficiency, and the development of public and private electric mobility, and charging infrastructure, in all cases including customers outside of our concession areas.

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 at the time the cash flows are needed.

Our investment plan is flexible enough to adapt to changing circumstances by giving different priorities to each project in accordance with expected profitability and strategic fit.  Investment priorities are currently focused on the distribution business, related to network reliability, capacity improvement and new technology developments such as smart meters.

For the 2019-2021 period, we expect capital expenditures in our subsidiaries to amount to US$ 5,329 million.  Our focus will be investments currently in progress, maintenance of our distribution network and generation plants, in studies required to develop other potential generation and distribution projects and in the development of new businesses carried out by our Enel X subsidiaries.  For further detail regarding these projects, please see “Item 4. Information on the Company — D. Property, Plants and Equipment — Projects Under Development.”

The table below sets forth the expected capital expenditures for the 2019-2021 period and the capital expenditures incurred in 2018, 2017 and 2016:

	Estimated 2019-2021	2018	2017	2016
	(in millions of US$)
Capital expenditures(1)	5,329	1,541	1,371	1,230

(1)Capex amounts represent effective payments for each year, net of contributions, except for future projections.

While our planned investments go beyond the three years highlighted in this table, we are reporting three years so as to be better aligned with Enel’s three-year industrial plan that was disclosed in November 2018.  For further information, please refer to “Item 4. Information on the Company — D. Property, Plants and Equipment. — Project Investments” and “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations.”

Capital Expenditures in 2018, 2017 and 2016

An important part of our capital expenditures are related to non-discretionary investments that include maintenance of existing installed capacity to increase the quality and operation standards of our facilities.  On a consolidated basis, during 2018 our capital expenditures were primarily focused on Brazil and in a higher proportion in the distribution segment.

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In our distribution business, our capital expenditures over the last three years were primarily related to the expansion of service in response to increasing demand for energy and new customers, the improvement of quality of service and safety and the prevention of energy losses, especially in Brazil. During 2018, we invested significantly in Enel Distribution Sao Paulo, our most recent acquisition.  During 2018, we invested U$ 851 million in our other Brazilian distribution companies and US$ 289 million in Codensa, our Colombian distribution company.  We plan to continue to expand our services, increasing the connections available to end customers, and reduce energy losses to improve efficiency and profitability.

During 2017 and 2018, the focus of our capital expenditures in the generation business was in Emgesa and in Peru.  In Emgesa we started the improvements to our thermal power plant Termozipa to reduce its environmental impact and to extend its useful life.  The environmental upgrade aims to achieve the best environmental standards for gas emissions among coal-fired power plants in Latin America. In Peru, we were focused on the reconstruction of our hydroelectric power plants affected by the heavy rains at the beginning of 2017, which damaged the Callahuanca and Moyopampa power plants.  We also invested in maintenance activities and modernization of civil works and hydraulic units in Peru.  In the generation business in 2016, we invested in a new 51 MW unit “TG6” for the Malacas thermal power plant, owned by Enel Generation Piura in Peru, to substitute for the non-operating Mitsubishi units (TG1, TG2 and TG3) and to increase generation using available LNG.  The new unit started commercial operations in February 2017.

Projects in progress will be financed with resources provided by external financing as well as internally generated funds.

B.Business Overview.

We are a publicly held limited liability stock corporation headquartered in Chile, but with consolidated operations in Argentina, Brazil, Colombia, and Peru. Our core businesses are electricity generation, transmission and distribution.

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

	Year ended December 31,
	2018		2017		2016		Change 2018 vs. 2017
	(in millions of US$)						(in %)
Generation and Transmission Business in Argentina	328		300		307		9.3
Costanera	163		152		137		7.2
El Chocón	67		58		42		15.5
Dock Sud	95		88		128		7.9
Other	3		1		1		234.3
Generation and Transmission Business in Brazil	854		830		572		2.9
Cachoeira Dourada	540		503		285		7.4
Fortaleza	212		261		236		(19.1	)
Cien	83		89		77		(6.9	)
Volta Grande	82		9		—		n.a.
Other	(63	)	(32	)	(26	)	96.3
Generation and Transmission Business in Colombia	1,260		1,160		1,152		8.6
Emgesa	1,260		1,160		1,152		8.6
Generation and Transmission Business in Peru	790		730		679		8.2
Enel Generation Peru	708		646		587		0.9
Enel Generation Piura	89		87		96		1.2
Other	(7	)	(3	)	(4	)	n.a.
Total Generation and Transmission Business reportable segment	3,231		3,020		2,710		7.0
Distribution Business in Argentina	1,190		1,223		963		(2.7	)
Edesur	1,190		1,223		963		(2.7	)
Distribution Business in Brazil	6,922		4,613		2,472		50.1
Enel Distribution Rio	1,511		1,646		1,285		(8.2	)
Enel Distribution Ceara	1,411		1,450		1,187		(2.7	)
Enel Distribution Goias	1,542		1,517		—		1.6
Enel Distribution Sao Paulo	2,459		—		—		n.a.
Distribution Business in Colombia	1,714		1,538		1,361		11.1
Codensa	1,714		1,538		1,361		11.4
Distribution Business in Peru	913		879		865		3.2
Enel Distribution Peru	913		879		865		3.8
Total Distribution Business reportable segment	10,739		8,253		5,661		30,1
Less: Consolidation adjustments and non-core activities	(786	)	(835	)	(729	)	37.1
Total Revenues	13,184		10,438		7,642		26.3

For further information related to our revenues and total income, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 28 of the Notes to our consolidated financial statements.

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Electricity Generation Business

For the year ended December 31, 2018, electricity generation represented 23% of our operating revenues and 50% of our operating income before consolidation adjustments.

In 2018, our consolidated electricity sales were 65,329 GWh a 16.6% increase compared to 2017. In 2018, our production was 39,863 GWh, a 2.9% decrease compared to 2017. Our total installed capacity in 2018 was 11,257 MW, a 0.3% increase compared to 2017.

For the year ended December 31, 2017, electricity generation represented 27% of our operating revenues and 53% of our operating income before consolidation adjustments.

In 2017, our consolidated electricity sales were 56,051 GWh and our production was 41,053 GWh, a 10.8% and 1.5% increase respectively, compared to 2016. Our total installed capacity in 2017 was 11,219 MW, a 434 MW increase compared to 2016.

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

	Year ended December 31,
	2018	2017	2016
Argentina
Number of generating units(1)	29	29	29
Installed capacity (MW)(2)	4,419	4,419	4,419
Electricity generation (GWh)	13,949	14,825	13,124
Energy sales (GWh)	13,952	14,852	13,312
Brazil
Number of generating units(1) (3)	17	17	13
Installed capacity (MW)(2) (3)	1,354	1,372	992
Electricity generation (GWh)	3,755	4,034	3,665
Energy sales (GWh)	22,236	12,587	9,448
Colombia
Number of generating units(1)	36	36	36
Installed capacity (MW)(2)	3,499	3,467	3,467
Electricity generation (GWh)	14,052	14,765	14,952
Energy sales (GWh)	18,544	18,156	18,015
Peru
Number of generating units(1)(4)	30	28	27
Installed capacity (MW)(2) (4)	1,985	1,979	1,935
Electricity generation (GWh)	8,106	7,430	8,698
Energy sales (GWh)	10,597	10,457	9,800
Total
Number of generating units(1)	112	110	105
Installed capacity (MW)(2)	11,257	11,219	10,794
Electricity generation (GWh)	39,863	41,053	40,439
Energy sales (GWh)	65,329	56,051	50,575

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

(2)2017 and 2016 figures may differ from previous years since this year we are reporting the net total installed capacity instead of the gross installed capacity. Total installed capacity is defined as 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)In November 2017, EGP Volta Grande was purchased by Enel Brasil, adding four generation units with a total installed capacity of 380 MW.

(4)In Peru, the Hydro Energy Recovery (HER) Huampaní facility started commercial operations on August 30, 2018, adding two generation units with a total installed capacity of 0.7 MW. In addition, unit TG6 of the Malacas thermal plant started its commercial operations with 51 MW on February 25, 2017.

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In the electricity industry, it is common to divide the business into hydroelectric and thermoelectric generation because each type of generation has significantly different variable costs. Thermoelectric generation requires the purchase of fuel, which generally leads to higher variable costs than hydroelectric generation from reservoirs or rivers which generally has minimal variable costs. Of our total consolidated generation in 2018, 59.4% was from hydroelectric sources, and 40.6% was from thermal sources.

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

CONSOLIDATED GENERATION BY TYPE OF ENERGY (GWh)

	Year ended December 31,
	2018		2017		2016
	Generation	%	Generation	%	Generation	%
Hydroelectric	23,690	59.4	22,618	55.1	22,550	55.8
Thermal	16,173	40.6	18,435	44.9	17,889	44.2
Total generation	39,863	100	41,053	100	40,439	100

In the countries in which we operate, the potential for contracting electricity is generally 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 characteristics of the required service. Finally, the pool market, where energy is normally 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, on the other hand, 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.

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 also determine which customers can purchase energy in electricity pool markets.

The primary 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, are energy purchases and transportation costs. During periods of relatively low rainfall, the amount of our thermal generation normally increases. This involves an increase in the total fuel cost and the costs of transporting fuel to the thermal generation power plants. Under drought conditions, electricity that we have contractually agreed to provide may exceed the amount of electricity that we are able to generate, which requires us to purchase electricity in the pool market at spot prices in order 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 year by limiting our contractual sales requirements to a quantity that does not exceed the estimated production in a dry year. To determine the estimated production in a dry year, we take into consideration the available statistical information concerning rainfall, hydrological levels, and the capacity of key reservoirs. 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.”

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Seasonality

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

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

When there is more precipitation hydroelectric generating facilities can accumulate additional water to be used for generation. The increased level of our reservoirs allows us to generate more electricity with hydro power plants during months in which 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 El Niño phenomenon reduces the amount of water that can be accumulated in reservoirs, thereby curtailing our hydroelectric generation capacity. In order to mitigate hydrological risk, hydroelectric generation may be substituted with thermal generation (natural gas, LNG, coal or diesel) and energy purchases on the spot market, both of which could result in higher costs, in order to meet our obligations under contracts with both regulated and unregulated customers.

Operations in Argentina

We participate in electricity generation in Argentina through our subsidiaries Costanera, El Chocón and Dock Sud, with an aggregate of 29 power units with a total net installed capacity of 4,419 MW as of December 31, 2018. Costanera owns eleven 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 1,359 MW, and Dock Sud owns five thermal units with a total net installed capacity of 847 MW. Our hydro and thermal generation units in Argentina represented 11.5% of the Argentine National Interconnected System’s (“Argentine NIS”) installed capacity in 2018.

Our Argentine subsidiaries have stakes in three additional companies: Termoeléctrica Manuel Belgrano S.A., Termoeléctrica San Martín S.A. and Central Vuelta de Obligado S.A. (Vuelta de Obligado) These companies were formed to undertake the construction of three new generation facilities for a fund called “FONINVEMEM”, whose purpose is to increase electricity capacity and generation within the Argentine wholesale electricity market. By December 2018, the total aggregate capacity of these units was 2,456 MW (823 MW from Manuel Belgrano, 823 MW from San Martín and 810 MW from Vuelta de Obligado).

As of December 31, 2018, Costanera’s installed capacity accounted for 5.7% of the total net installed capacity in the Argentine NIS. Both Costanera’s steam turbine power plant and second combined-cycle plant can operate with either natural gas or diesel.

El Chocón accounted for 3.5% of the installed net capacity in the Argentine NIS as of December 31, 2018. El Chocón has a 30-year concession, ending in 2023, for two hydroelectric generation facilities with an aggregate installed net capacity of 1,328 MW. The larger of the two facilities for which El Chocón has a concession of 1,200 MW of net installed capacity is the primary flood control installation on the Limay River. The facility’s large reservoir, Ezequiel Ramos Mejía, enables El Chocón to be one of the Argentine NIS major peak suppliers. Variations in El Chocón’s water discharge are moderated by El Chocón’s Arroyito facility, a downstream dam with 128 MW of net installed capacity.

In November 2008, we completed construction on the Arroyito dam, and increased the elevation of the reservoir’s water level, which allows the release of water at an additional 1,150 m3/sec, for a total of 3,750 m3/sec. A portion of the Arroyito facility’s generation is sold under the “Energy Plus” program, which provides for the new electricity capacity to supply the electricity demand growth, using the 2005 demand level for electricity as a base. For details on “Energy Plus,” see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Argentine Electricity Regulatory Framework”).

Costanera has an agreement with El Chocón to operate four diesel engines belonging to El Chocón with a total net installed capacity of 35 MW, which are located in our Costanera thermal plant and began operations during 2016.

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Dock Sud’s net installed capacity of 847 MW accounted for 2% of the total net installed capacity in the Argentine NIS as of December 31, 2018. The Dock Sud combined-cycle plant consists of three generation units with an installed capacity of 775 MW that can operate with either natural gas or diesel. The two gas turbine units of Dock Sud have 72 MW of installed capacity.

For information on the installed generation capacity for each of our Argentine subsidiaries, see “Item 4. Information on the Company — D. Property, Plants and Equipment—Property, Plant and Equipment of Generating Companies.”

Our total generation in Argentina amounted to 13,949 GWh in 2018. According to CAMMESA, our generation market share was approximately 10.1% of the total electricity production in Argentina during 2018.

Our hydroelectric generation in Argentina accounted for over 20% of our total generation in Argentina in 2018, reaching 2,859 GWh, an increase of 50% compared to the previous year. This was mainly due to higher hydrological levels in the Limay River in 2018 compared to 2017. Our thermal generation in Argentina accounted for 80% of our total generation in 2018, reaching 11,090 GWh, a decrease of 16% compared to the previous year. This was mainly due to the combined cycle’s generation.

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

ELECTRICITY GENERATION IN ARGENTINA (GWh)

	Year ended December 31,
	2018		2017		2016
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (El Chocón)	2,859	20.5	1,908	12.9	2,256	17.2
Thermal generation (Costanera and Dock Sud)(1)	11,090	79.5	12,917	87.1	10,868	82.8
Total generation	13,949	100	14,825	100	13,124	100

(1)Includes diesel engines from 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,
	2018		2017		2016
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	13,949	99.9	14,825	99.8	13,124	98.6
Electricity purchases	3	0.01	27	0.2	188	1.4
Total(1)	13,952	100	14,852	100	13,312	100

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

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,
	2018	2017	2016
Costanera	7,101	7,852	5,713
El Chocón	2,901	2,055	2,574
Dock Sud	3,951	4,945	5,025
Total	13,952	14,852	13,312

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For the year ended December 31, 2018, Costanera did not have contracts with unregulated customers or distribution companies and sold all of its electricity to the pool market during the year.

For the year ended December 31, 2018, El Chocón had 13 contracts with unregulated customers and no contracts with distribution companies.

For the year ended December 31, 2018, 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.

The electricity demand throughout the Argentine NIS increased by 0.34% during 2018. The total electricity demand was 132,925 GWh in 2018, 132,479 GWh in 2017 and 133,111 GWh in 2016. Our Argentine subsidiaries compete with all the major power plants connected to the Argentine NIS.

According to the installed capacity reported by CAMMESA, in its monthly report as of December 2018, our major competitors in Argentina are: (1) the state controlled company Enarsa (with an installed capacity of 1,362 MW), (2) the nuclear unit “NASA” (with an installed capacity of 1,755 MW), and (3) the hydroelectric units Yacyretá and Salto Grande (with an aggregate installed capacity of 4,045 MW).

The main private competitors are: AES Group, Sociedad Argentina de Energía S.A. (“Sadesa”), and Pampa Energía. The AES Group has ten power plants connected to the Argentine NIS with a total net installed capacity of 4,224 MW. Sadesa owns a total of approximately 3,899 MW of installed capacity, the most significant of which are Piedra del Águila (with an installed capacity of 1,400 MW) and Central Puerto (a thermal facility with 1,777 MW of installed capacity). Pampa Energía, with a total installed capacity of 3,871 MW, competes with us with seven power plants, of which 938 MW is hydroelectric and 2,631 MW is thermal.

Operations in Brazil

We participate in electricity generation in Brazil through our subsidiaries Cachoeira Dourada, Fortaleza and Volta Grande.

As of December 31, 2018, we had a total net installed capacity of 1,354 MW in Brazil, representing 0.8% of the total net installed capacity of the Brazilian system.

Cachoeira Dourada is a hydroelectric company consisting of ten-generation units with a total net installed capacity of 655 MW, located in southeast Brazil.

Fortaleza owns a combined-cycle plant with three generation units which use natural gas, with a total net installed capacity of 319 MW. The plant is located 50 kilometers from the capital of the State of Ceará, and began commercial operations in 2003. Since January 2010, Fortaleza has received natural gas from the Pecem regasification terminal, an unrelated company. During 2018, our thermal generation decreased compared to 2017, due to a legal dispute about the gas supply contract with Petrobras (gas supplier). See Note 5. A — Brazil — Enel Generation Fortaleza in the notes to consolidated financial statements for further information about the gas supply stoppage.

EGP Volta Grande is a hydroelectric company consisting of 4 generation units with a total net installed capacity of 380 MW, located in southeast Brazil. EGP Volta Grande was purchased by our subsidiary Enel Brasil on November 30, 2017.

Our hydroelectric generation in 2018 was slightly higher than 2017, as 2018 hydrology conditions were similar to 2017.

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

ELECTRICITY GENERATION IN BRAZIL (GWh)

	Year ended December 31,
	2018		2017		2016
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (Cachoeira Dourada and EGP Volta Grande)	3,219	85.7	2,102	52.1	2,093	57.1
Thermal generation (Fortaleza)(1)	537	14.3	1,932	47.9	1,572	42.9
Total	3,755	100	4,034	100	3,665	100

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(1)In 2018, our thermal generation decreased due to a legal dispute about the gas supply contract with Petrobras (gas supplier). Petrobras ceased the supply of gas to Fortaleza.

The distribution electricity sales in Brazil by subsidiary is shown in the following table:

ELECTRICITY SALES BY SUBSIDIARY IN BRAZIL (GWh)

	Year ended December 31,
	2018		2017		2016
	Sales	% of SalesVolume	Sales	% of SalesVolume	Sales	% of SalesVolume
Cachoeira Dourada(1)	18,098	81.4	9,526	75.7	6,399	67.7
Fortaleza	2,763	12.4	2,923	23.2	3,049	32.3
Volta Grande	1,376	6.2	137	1.1	—	0.0
Total electricity sales	22,236	100	12,587	100	9,448	100

(1)The increase is mainly explained by a higher level of trading with unregulated clients.

For the year ended December 31, 2018, Cachoeira Dourada’s principal unregulated customers were (ordered by energy contracted): Focus, RR Comercializadora, and EDP.

Fortaleza has its entire output dedicated to one long-term contract with Enel Distribution Ceara that expires in 2023.  For the year ended December 31, 2018, EGP Volta Grande had no unregulated customers.

Operations in Colombia

We participate in electricity generation in Colombia through our subsidiary Emgesa. As of December 31, 2018, Emgesa operated 36 generation units, with a total net installed capacity of 3,499 MW, of which 3,091 MW was from hydroelectric plants and 408 MW was from thermal plants. According to Expertos de Mercado S.A. E.S.P. (“XM”), a Colombian company that provides system management in real time services in electrical, financial and transportation sectors, our hydroelectric and thermal generation plants represented 20.4% of the country’s total electricity generation net capacity as of December 2018, making Emgesa the company with the largest percentage of generation capacity, followed by Empresa Pública de Medellín with 20.3% and Isagen with 17.4%. For information on the installed generation capacity for each of our Colombian subsidiaries, see “Item 4. Information on the Company — D. Property, Plants and Equipment—Property, Plant and Equipment of Generating Companies.”

Approximately 75.5% of the electricity generation capacity in Colombia is hydroelectric, and therefore, our electricity generation depends on reservoir levels and rainfall.  According to XM, in 2018, Emgesa represented 20.4% of the country’s total electricity generation. During 2018, the hydrological conditions in Colombia were favorable and reached approximately 103% of its historical average.

During 2018, our hydroelectric generation represented 97.9% of our total generation and thermal generation represented the remaining 2.1%. For the year ended December 31, 2018, our hydroelectric generation decreased by 6% compared to 2017.

The average spot price of electricity during 2018 was CP 116 per kWh, a 9% increase compared to 2017, mainly due to the favorable hydrological conditions in the National Interconnected System (“Colombian NIS”), resulting in lower thermal generation in the Colombian NIS, including at Emgesa’s thermal plants.

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

ELECTRICITY GENERATION IN COLOMBIA (GWh)

	Year ended December 31,
	2018		2017		2016
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (1)	13,763	97.9	14,593	98.8	14,031	93.8
Thermal generation	289	2.1	172	1.2	920	6.2
Total generation	14,052	100	14,765	100	14,952	100

(1)Includes Rionegro with 9.2 GWh

During 2018, Emgesa used 83,295 tons of coal for its Termozipa coal-fired plant compared to the 61,005 tons used during 2017. This higher consumption can be explained by higher thermal generation as a result of higher spot prices in 2018 compared to 2017.

In 2017, the Cartagena power plant entered into a new fuel supply contract for the 2017-2019 period. In 2018, the three generation units of the Cartagena power plant consumed 11,212,998 gallons of fuels (ACPM, gas and fuel), a 185 % increase compared to 2017.

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

ELECTRICITY GENERATION AND PURCHASES IN COLOMBIA (GWh)

	Year ended December 31,
	2018		2017		2016
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	14,052	75.8	14,765	80.3	14,952	82.2
Electricity purchases	4,491	24.2	3,617	19.7	3,244	17.8
Total(1)	18,544	100	18,381	100	18,196	100

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

Colombia has a single interconnected electricity system, the Colombian NIS. Electricity demand in the Colombian NIS was 69,075 GWh during 2018, increasing 3.3 % compared to 2017.

Colombia has an agreement with Ecuador to provide an interconnection between the electricity systems of both countries. During 2018, Colombian electricity generators sold 106 GWh of electricity to Ecuadorian customers and imported 233 GWh of Electricity from Ecuador.

During 2018, Emgesa sold 4,387 GWh of electricity to unregulated clients, which represented 28% of the contracted sales. Regulated clients represented 72% of the contracted sales. Additionally, sales to the spot market totaled 2,827 GWh.

For the year ended December 31, 2018, principal distribution customers were: Codensa (our subsidiary), Electrificadora del Caribe (“Electricaribe”), Empresas Públicas de Medellín (“EPM”), Centrales Eléctricas del Norte de Santander (“CENS”) and Empresa de Energía de Boyacá (“EBSA”).

Operations in Peru

We participate in electricity generation in Peru through our subsidiaries Enel Generation Peru (formerly known as Edegel S.A.A.) and Enel Generation Piura (formerly known as Empresa Eléctrica de Piura S.A.). We operate a total of 30 generation units in Peru, with a total net installed capacity of 1,985 MW. As of December 2018, Enel Generation Peru owns 20 hydroelectric units, with a total net installed capacity of 792 MW, and the remaining 856 MW consists of 7 thermal units. Enel Generation Piura owns 3 thermal units with an aggregate installed capacity of 337 MW. On June 15, 2017, 4 hydroelectric units of Enel Generation Peru, belonging to the

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Callahuanca hydroelectric plant, experienced damages caused by avalanches that occurred during March 2017 and were temporarily taken out of operations. Since March 30, 2019, all of the Callahuanca Hydroelectric power plants have been in operations.

According to the Committee of Economic Operation of the Peruvian System (“COES” in its Spanish acronym), the Peruvian entity in charge of coordinating the efficient operation and centralized dispatch of generation units to satisfy demand, our hydroelectric and thermal generation plants in Peru represented 17% of the country’s total electricity generation capacity as of December 31, 2018.

For information on the installed generation capacity for each of our power plants in Peru, see “Item 4. Information on the Company — D. Property, Plants and Equipment. — Property, Plant and Equipment of Generating Companies.”

According to COES, we generated 18% of total Peruvian electricity production in 2018.

Hydroelectric generation represented 47.5% of total production of our Peruvian generation subsidiaries in 2018. In the case of Enel Generation Peru, from January to July 2018, hydrological conditions were favorable and were in accordance with their historical averages, but the production was lower than 2017, which was a humid year. On the other hand, thermal generation increased compared to 2017, mainly due to a better location in the ranking of dispatch.

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

ELECTRICITY GENERATION IN PERU (GWh)

	Year ended December 31,
	2018		2017		2016
	Generation	%	Generation	%	Generation	%
Hydroelectric generation (Enel Generation Peru)	3,849	47.5	4,015	54.0	4,170	47.9
Thermal generation (Enel Generation Peru and Enel Generation Piura)	4,257	52.5	3,415	46.0	4,529	52.1
Total generation	8,106	100	7,430	100	8,698	100

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 in order to operate as instructed by COES, and optimize the use of the natural gas transport system.

Enel Generation Piura has five long term sale and purchase agreements for “wet” gas, which is mixed with other hydrocarbons, under which Enel Generation Piura purchases “wet” gas and through a process obtains “dry” gas that is used for electric generation at its Malacas Power Plant and is sold to the Talara refinery (owned by Petroperu, the Peruvian National Oil Company) through a supply agreement. In addition, Enel Generation Piura also has one long-term sale and purchase agreement for “dry” gas. To satisfy its dry gas needs, Enel Generation Piura signed an agreement with Pariñas Processing Plant, which allows Enel Generation Piura to convert wet gas into dry gas, and recover natural gas liquids, which are shared with Pariñas Processing Plant.

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

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

	Year ended December 31,
	2018		2017		2016
	(GWh)	%	(GWh)	%	(GWh)	%
Electricity generation	8,106	76.5	7,430	71.1	8,698	88.8
Electricity purchases	2,491	23.5	3,027	28.9	1,101	11.2
Total	10,597	100	10,457	100	9,800	100

(1)Includes sales to distribution companies without contracts.

The Peruvian National Interconnected Electric System (“SEIN”) is the only interconnected system in Peru. Electricity sales in the SEIN increased by 3.7% in 2018 compared to 2017, amounting to 1,824 GWh.

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Our distribution electricity sales in Peru by subsidiary is shown in the following table:

ELECTRICITY SALES BY SUBSIDIARY IN PERU (GWh)

	Year ended December 31,
	2018		2017		2016
	Sales	% of SalesVolume	Sales	% of SalesVolume	Sales	% of SalesVolume
Enel Generation Peru	9,994	94.3	9,817	93.9	9,091	92.8
Enel Generation Piura	603	5.7	640	6.1	709	7.2
Total electricity sales	10,597	100	10,457	100	9,800	100

Enel Generation Peru’s electricity sales increased by 1.8% in 2018 compared to 2017, mainly due to higher sales to unregulated customers. In 2018, Enel Generation Peru had energy contracts with 8 regulated customers and 119 unregulated customers and sales to unregulated customers represented 56% of Enel Generation Peru’s total contracted sales.

For the year ended December 31, 2018, Enel Generation Peru’s principal distribution customers were (ordered by energy contracted): Enel Distribution Peru (our subsidiary), Luz del Sur and SEAL.

In 2018, Enel Generation Piura had contracts with 8 regulated customers and 8 unregulated customers. Sales to regulated customers represented 80% of Enel Generation Piura’s total contracted sales.

For the year ended December 31, 2018, Enel Generation Piura’s principal distribution customers were Enel Distribution Peru and Luz del Sur.

Our most significant competitors in Peru are: Engie Perú and Inkia Energy.

Electricity Transmission Business

Cien

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. In 2018, Cien represented 0.6 % of our operating revenues and 2.2% of our operating income before consolidation adjustments. Cien is recognized by the local authority as a “regulatory asset” and as part of the Brazilian grid, and therefore, it is entitled to receive fixed payments called Permitted Annual Compensation (RAP).

Cien enables the energy integration of Mercosur, as well as the import and export of electricity between Argentina, Brazil and Uruguay. It has two transmission lines covering a distance of 500 kilometers between Rincón in Argentina and the Santa Catarina substation in Brazil, with a total installed capacity of 2,100 MW. Cien operates each transmission line under a 30-year concession granted by the Brazilian government that will be in force until 2020 and 2022. Its 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, 2018, electricity sales increased by 35.8% compared to 2017, totaling 100,927 GWh. For more information on energy sales by our distribution subsidiaries for the last five fiscal years, see “Item 3. Key Information — A. Selected Financial Data.”

Edesur (Argentina)

Edesur is one of the largest electricity distribution companies in Argentina in terms of energy purchases. Edesur operates in a concession area of 3,309 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 that will be in force until 2087.  As of December 31, 2018, residential, commercial, industrial and other customers, primarily public and municipal, represented 88.0%, 11.0%, 0.8% and 0.1%, respectively, of Edesur’s total energy sales of 17,548 GWh. In 2018 and 2017, its energy losses were 14.2% and 12.0%, respectively.

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

	Year ended December 31,
	2018	2017	2016
Electricity sales (GWh)	17,548	17,736	18,493
Residential	8,436	8,777	10,202
Commercial	1,340	1,384	1,461
Industrial	4,221	4,217	3,562
Other customers(1)	3,551	3,359	3,268
Number of customers (thousands)	2,530	2,529	2,505
Residential	2,227	2,226	2,200
Commercial	280	273	273
Industrial	21	22	22
Other customers	1	10	10
Energy purchased (GWh)(2)	20,492	20,454	21,039
Total energy losses (%)(3)	14.2	12.0	12.0

(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 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 as well as technical losses.

For the year ended December 31, 2018, 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.

In 2018, the collection rate from customers was 91.1% compared to 94.8%, in 2017.

Enel Distribution Rio (Brazil)

Enel Distribution Rio is the second largest electricity distribution company in the State of Rio de Janeiro, Brazil in terms of number of customers and annual energy sales. Enel Distribution Rio is mainly engaged in the distribution of electricity to 66 municipalities located in the State of Rio de Janeiro, and serves approximately 3 million customers in a concession area of 32,615 square kilometers, with an estimated population of 17.2 million. Enel Distribution Rio operates under a 30-year concession granted by the Brazilian government which will remain in force until December 2026. As of December 31, 2018, residential, commercial, industrial and other customers represented 92.0%, 5.1%, 0.1% and 2.8%, respectively, of Enel Distribution Rio’s total sales of 11,019 GWh. In 2018, its energy losses were 21.0%, compared to 20.4% in 2017.

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

	Year ended December 31,
	2018	2017	2016
Electricity sales (GWh)	11,019	11,091	11,181
Residential	4,755	4,852	4,688
Commercial	1,930	1,892	2,088
Industrial	400	361	638
Other customers(1)	3,934	3,986	3,767
Number of customers (thousands)	2,959	3,030	3,054
Residential	2,721	2,772	2,775
Commercial	152	160	177
Industrial	4	5	5
Other customers	82	93	97
Energy purchased (GWh)	14,490	14,377	14,348
Total energy losses (%)(2)	21.0	20.4	19.4

(1)The data for other customers includes tolls.

(2)Energy losses are calculated as the percent difference between 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 as well as technical losses.

Enel Distribution Ceara (Brazil)

Enel Distribution Ceara is mainly engaged in the distribution of electricity to municipalities located in the State of Ceará, and serves almost 4 million customers in a concession area of 148,920 square kilometers, with an estimated population of 9.1 million. Enel Distribution Ceara operates under a 30-year concession granted by the Brazilian government that will remain in force until December 2027. As of December 31, 2018, residential, commercial, industrial and other customers represented 80.9 %, 4.3 %, 0.1 % and 14.7 %, respectively, of Enel Distribution Ceara’s total sales of 11,019 GWh. In 2018, its energy losses were 13.9 %, compared to 13.6% in 2017.

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

	Year ended December 31,
	2018	2017	2016
Electricity sales (GWh)	11,843	11,522	11,628
Residential	4,372	4,191	4,129
Commercial	2,244	1,923	2,136
Industrial	1,405	748	1,055
Other customers(1)	3,822	4,660	4,308
Number of customers (thousands)	3,933	4,017	3,890
Residential	3,181	2,964	2,861
Commercial	169	239	236
Industrial	5	7	8
Other customers	579	806	786
Energy purchased (GWh)	13,771	13,349	13,298
Total energy losses (%)(2)	13.9	13.6	12.5

(1)The data for other customers includes tolls.

(2)Energy losses are calculated as the percent difference between 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 as well as technical losses.

In 2018, the collection rate from customers was 99.3% compared to 98.9% in 2017.

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Enel Distribution Goias (Brazil)

Enel Distribution Goias is mainly engaged in the distribution of electricity to municipalities located in the State of Goias, and serves almost 3 million customers in a concession area of 337,000 square kilometers, with an estimated population of 6.9 million. Enel Distribution Goias operates under a concession granted by the Brazilian government that will remain in force until December 2045. As of December 31, 2018, residential, commercial, industrial and other customers accounted for 85.5 %, 7.2 %, 0.3 % and 7.0 % respectively, of Enel Distribution Goias’s total energy sales of 13,755 GWh. In 2018, energy losses were 11.6 %, compared to 11.7% in 2017. Enel Distribution Goias was acquired by Enel Brasil in February 2017.

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

	Year ended December 31(1),
	2018	2017	2016
Electricity sales (GWh)	13,755	12,264	—
Residential	4,741	4,195	—
Commercial	2,416	2,036	—
Industrial	3,556	1,110	—
Other customers(2)	3,041	4,923	—
Number of customers (thousands)	3,027	2,928	—
Residential	2,589	2,493	—
Commercial	217	220	—
Industrial	9	10	—
Other customers	211	206	—
Energy purchased (GWh)	13,818	15,270	—
Total energy losses (%)(3)	11.6	11.7	—

(1)We acquired Enel Distribution Goias in February 2017.

(2)The data for other customers includes tolls.

(3)Energy losses are calculated as the percent difference between 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 as well as technical losses.

In 2018, the collection rate from customers was 99.3 % compared to 99.2% in 2017.

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Enel Distribution Sao Paulo (Brazil)

Enel Distribution Sao Paulo is mainly engaged in the distribution of electricity to municipalities located in the Sao Paulo Metropolitan Area, and serves almost 7.2 million customers in a concession area of 4,526 square kilometers, with an estimated population of 18 million. Enel Distribution Sao Paulo operates under a concession granted by the Brazilian government that will remain in force until June 2028. As of December 31, 2018, residential, commercial, industrial and other customers accounted for 38%, 33 %, 20 % and 9 % respectively, of Enel Distribution Sao Paulo’s total energy sales of 42,878 GWh. In 2018, energy losses were 9.5 %. Enel Distribution Sao Paulo was acquired by Enel Brasil in June 2018.

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

	Year ended December 31,
	2018(1)	2017	2016
Electricity sales (GWh)	24,693
Residential	9,455
Commercial	5,880
Industrial	1,814
Other customers(2)	7,542
Number of customers (thousands)	7,224
Residential	6,766
Commercial	410
Industrial	26
Other customers	22
Energy purchased (GWh)	27,370
Total energy losses (%)(3)	9.5

(1)We acquired Enel Distribution Sao Paulo in June 2018.

(2)The data for other customers includes tolls.

(3)Energy losses are calculated as the percent difference between 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 as well as technical losses.

In 2018, the collection rate from customers was 99.8 %.

Codensa (Colombia)

Codensa is a Colombian electricity distribution company that serves a concession area of 35,194 square kilometers in Bogotá and other 130 municipalities of the provinces of Cundinamarca, with approximately 3.4 million customers.

Under Colombian law, since no concessions are granted, an administrative authorization is required to provide distribution service. In the case of Codensa, the authorization is of indefinite duration.

Since 2001, Codensa only provides services to regulated customers. The unregulated market is serviced directly by our generation company, Emgesa, with the exception of public lighting in Bogotá. In 2018, Codensa’s energy losses were 7.7%, compared to 7.8% in 2017.

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

	Year ended December 31,
	2018	2017	2016
Electricity sales (GWh)	14,024	13,797	13,632
Residential	5,055	5,000	4,656
Commercial	2,489	2,453	2,294
Industrial	1,066	1,066	1,047
Other customers(1)	5,414	5,272	5,635
Number of customers (thousands)	3,439	3,340	3,248
Residential	3,062	2,974	2,890
Commercial	317	310	302
Industrial	49	48	48
Other customers	11	8	8
Energy purchased (GWh)(2)	15,269	15,013	14,680
Total energy losses (%)(3)	7.7	7.8	7.1

(1)The data for other customers includes tolls.

(2)The data for energy purchased includes tolls. In 2018, 36.82% of the electricity purchased without tolls was acquired from Emgesa, 44.2% in 2017 and 42 % in 2016.

(3)Energy losses are calculated as the percent difference between 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 as well as technical losses.

In 2018, the collection rate from customers was 100.2% compared to 101.8% in 2017. The 2018 and 2017 collection rate was more than 100% due to the collection of unpaid bills from previous periods.

For the year ended December 31, 2018, Codensa had no unregulated customers.

Enel Distribution Peru (Peru)

Enel Distribution Peru is a Peruvian electricity distribution company that operates in a concession area of 1,517 square kilometers under an indefinite concession granted by the Peruvian government. It has an exclusive concession to distribute electricity in the northern part of the Lima metropolitan area, as well as some provinces in the Lima region, including Huaral, Huaura, Barranca and Oyón, and the adjacent province of Callao. As of December 31, 2018, Enel Distribution Peru distributed electricity to approximately 1.4 million customers, an increase of 1.8% compared to 2017.

As of December 31, 2018, Enel Distribution Peru had total energy sales of 8,045 GWh, an increase of 1.4% compared to 2017. Energy losses decreased to 8.1% in 2018 from 8.2% in 2017.

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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,
	2018	2017	2016
Electricity sales (GWh)	8,045	7,934	7,782
Residential	2,988	2,920	2,818
Commercial	886	1,002	1,353
Industrial	1,847	1,697	1,421
Other customers(1)	2,324	2,315	2,190
Number of customers (thousands)	1,423	1,397	1,367
Residential	1,348	1,324	1,296
Commercial	46	46	42
Industrial	2	1	1
Other customers	27	26	28
Energy purchased (GWh)(2)	8,696	8,608	8,444
Total energy losses (%)(3)	8.1	8.2	7.8

(1)The data for other customers includes tolls.

(2)In 2018, 34% of the electricity purchased was acquired from Enel Generation Peru, Chinango and Enel Generation Piura, compared with 40% in 2017 and 35% in 2016.

(3)Energy losses are calculated as the percent difference between 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 as well as technical losses.

In 2018, Enel Distribution Peru’s primary unregulated customers were (ordered alphabetically): AGP Perú S.A.C, Ajinomoto del Perú S.A., Alicorp SAA, Ceramica Lima S.A., Compañia Industrial Nuevo Mundo S.A., GYM Ferrovuas S.A., Hipermercados Tottus S.A, Lima Airport Partners S.R.L., Minera Colquisiri S.A., Tecnologia Textil S.A.

In 2018, the collection rate from customers was 99.6 % compared to 100.3% in 2017. The 2017 collection rate was more than 100% due to the collection of unpaid bills from previous periods.

For further details regarding 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, 2016 and 2015.”

Seasonality

The distribution business is directly influenced by seasonal changes in energy demand. 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 impact on our profitability since the cost of electricity purchased is passed to end users through tariffs that are set for multi-year periods.

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ELECTRICITY INDUSTRY REGULATORY FRAMEWORK

The following chart shows a summary of the main characteristics of the electricity regulatory framework by business segment in the countries in which we operate.

		Argentina	Brazil	Colombia	Peru
Gx	Unregulated Market	Regulated remuneration scheme (Resolution 19/2017)	Spot markets with prices defined by the regulator	Spot market with auctioned cost (Price- offered)	Spot markets with costs audited. Natural gas prices are declared with limits.
	Regulated	Seasonal Price	Auction Thermal- 20 years / Hydro- 30 years	Auction 3/5 years	Auction up to 20 years and node price
	Capacity	Contributionpeak demand	—	Firm energy contribution (energy auctions for at least 20 years for new projects and 1 year for current projects)	Income based on contributions during peak demand
Tx	Features	Public - Open Access - Regulated TariffMonopoly Regime for Transmission System Operators
Dx	Law	Concession contract		AuthorizationOperation Zone	Administrative Concession (indefinite)
	Expansion	95 years	30 years	—	Undefined
	Tariff review	5 years	4/5 years	5 years	4 years
Td	Unregulated customers	> 0.03 MW	> 0.5 MW to 3MW/ NCRE> 3MW/conventional	> 0.1 MW	> 0.2 to 2.5 MW optional> 2.5 MW mandatory
	Unregulated market (%)	≈ 20%	≈ 25%	≈ 30%	≈ 50%

Gx: Generation Tx: Transmission Dx: Distribution Td: Trading

Argentine Electricity Regulatory Framework

Industry Overview and Structure

In the Argentine Wholesale Electricity Market (“Argentine 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 as well as related products. The Argentine autonomous entity in charge of the operation the MEM is CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico S.A.).

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

i)Generators:

The generation segment is comprised of companies that own electricity generation power plants.  Electricity generators sell their energy to the market at a price established by the regulator. In February 2017, new guidelines for the remuneration of existing generation plants focused on the incentives to enable the availability of the power plants.

ii)Transmitters:

The transmission sector is a public service that operates under monopoly conditions and is comprised of several companies to whom the Argentine government grants concessions. One concessionaire operates and maintains the highest voltage facilities and eight concessionaires operate and maintain high and medium voltage facilities, to which generation plants, distribution systems and large customers are connected.  The international interconnected transmission systems also require concessions granted by the Argentine Secretary of Energy (“SEE”). Transmission companies are authorized to charge different tolls for their services.

iii)Distributors:

Distribution is a public service that operates under monopoly conditions and is comprised of companies that have been granted concessions by the Argentine government.  Distribution companies have the obligation to make electricity available to end customers within a specific concession area, regardless of whether the customer has a contract with the distributor or directly with a generator.  Distributors have regulated tariffs and are subject to quality service specifications.  They may obtain electricity on the Argentine MEM’s spot market at a price called “seasonal price,” which is defined by the SEE as the maximum electricity cost purchased by distributors that can be passed through to regulated customers.  There are two electricity distribution areas in greater Buenos Aires subject to federal concessions, Edesur (our subsidiary) and Edenor (an unrelated company).  The local distribution areas are subject to concessions granted by the provincial or municipal authorities.  However, all distribution companies acting in the Argentine MEM must operate under its rules.

iv)Customers:

Regulated customers are supplied by distributors at regulated tariffs that demand up to 30 kW of capacity and unregulated customers are those who demand at least 30 kW of capacity. The latter are classified into three categories: major large, minor large and private large customers.  Each of these categories has different requirements with respect to purchases of their energy demand. Major large customers are required to purchase 50% of their demand through supply contracts and the remainder in the spot market, while minor large and private large customers are required to purchase all their demand through supply contracts.  Large customers participate in CAMMESA by appointing two directors and two

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acting directors through the Argentine Association of Electric Power for Large Customers.  Large customers buy electricity directly from CAMMESA, following the expiration of their bilateral contracts directly with generators. There is one interconnected system, the Argentine NIS, and smaller systems that provide electricity to remote areas.

Principal Regulatory Authorities

The Argentine Ministry of Energy and Mining is responsible for studying and analyzing the behavior of energy markets, preparing the strategic planning with respect to electricity, hydrocarbons and other fuels, promoting policies to increase competition and improve efficiency in the allocation of resources, leading actions for applying the sector policy, orienting new operators to the general interest, respecting the rational exploitation of the resources and the preservation of the environment.  The Ministry of Energy and Mining, through the Sub-Secretary of Electric Energy, implements the necessary actions to manage the energy industry, resolving issues to avoid emergencies.

The main responsibilities of the Sub-Secretary of Electric Energy include:

·modification of transmission system regulation in terms of connections, use and international interconnections;

·modification of regulations regarding dispatch and pricing procedures;

·definition of the capacity, energy and other technical parameter requirements for distributors and large consumers to enter the MEM;

·definition of rules to operate and enter into contracts in the MEM;

·authorization of electricity imports and exports;

·settlement of complaints filed against the National Regulatory Authority for the Energy Sector;

·carrying out the Ministry’s functions within the Consejo Federal de la Energía Eléctrica ; and

·managing an electricity development fund.

The Argentine National Regulatory Authority for the Energy Sector (“ENRE” in its Spanish acronym) carries out the measures necessary to meet national policy objectives with respect to the generation, transmission and distribution of electricity and directly controls management of Edesur and Edenor as distribution concessions.

ENRE’s principal activities include:

·protection of customer rights;

·promotion of production competitiveness;

·encouragement of investments that assure long-term supply;

·promotion of free access, non-discrimination and the generalized use of the transmission and distribution services;

·regulation of transmission and distribution services to ensure fair and reasonable tariffs, and

·incentives to private investment in production, transmission, and distribution, ensuring competitive markets where possible.

CAMMESA is the Argentine autonomous entity in charge of the operation the MEM and its stockholders are generation, transmission and distribution companies, large users and the Secretary of Energy. CAMMESA’s principal functions are the coordination of dispatch operations, the establishment of wholesale prices and the management of economic transactions made through the Argentine NIS.  It is also responsible for executing the dispatch through economic considerations and rationality in the management of energy resources, the coordination of centralized operation of the Argentine NIS to guarantee its security and quality, and the management of the Argentine MEM, all of which are designed to ensure transparency through the participation and regulation of all players.

The Federal Environmental Council is an institutional branch of the federal government empowered to address environmental problems and solutions in Argentina.  It has legal authority to coordinate the development of environmental policy among member states.  The member states adopt regulations, rules or resolutions issued by the Argentine Assembly. The principal functions of the Argentine Federal Electricity Council are to:

(i)manage specific funds for the electricity sector;

(ii)advise the national executive authority and the provincial governments with respect to the electricity industry, the priorities in performing studies and works, concessions and authorizations, and prices and tariffs in the electricity sector; and

(iii)advise on modifications resulting from legislation referring to the electricity industry.

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The Ministry of Environment and Sustainable Development, a member of the Federal Environment Council, assists the Chief of the Ministers Cabinet in the implementation of environmental measures and assures their insertion in the ministries and other public sector areas. It seeks to foster rational exploitation and sovereignty over Argentina’s natural resources with consideration to fairness and social inclusion.  The Secretary is involved in environmental planning and preservation, planning and implementation of national environmental management in the implementation of sustainable development, rational use of NCRE and the diagnosis of environmental issues in coordination with different branches of the Argentine government.

The Electricity Law

General

The Argentine electricity industry was originally developed by private companies.  The Argentine government began to intervene in the sector in the 1950s and initiated a nationalization process.  In 1960, it organized the sector and established the federal legal framework to begin major transmission and generation projects.  Many government-owned corporations were created within this framework in order to carry out various hydroelectric and nuclear projects.

As a result of the electricity shortage in 1989, the following laws were passed starting in 1990: Law 23,696 (“State Reform”), Law 23,697 (“Economic Emergency”) and Law 24,065 (“Electricity Framework”).  The objective of this legislation was essentially to replace the vertically-integrated system based on a centralized state monopoly with a competitive system based on the market and indicative planning.

FONINVEMEM

FONINVEMEM is a fund created in order to encourage electricity capacity within the Argentine MEM, and is managed by CAMMESA.  Private sector generators in the Argentine MEM were called upon to participate in the construction, operation and maintenance of the electricity generation plants to be built with FONINVEMEM funds, consisting of two combined-cycle generation plants of approximately 825 MW each.

Limits and Restrictions

To preserve competition in the electricity market, participants in the electricity sector are subject to vertical and horizontal restrictions, depending on the market segment in which they operate.

Vertical Integration Restrictions

The vertical integration restrictions apply to companies that intend to participate simultaneously in different sub-sectors of the electricity market. These vertical integration restrictions were imposed by the Electricity Framework (Law 24,065), and apply differently to each sub-sector as described below:

Generators

·Neither a generation company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling entity of a transmission company; and

·Since a distribution company cannot own generation units, a holder of generation units cannot own distribution concessions. However, the shareholders of the electricity generator may own an entity that holds distribution units, either by themselves or through any other entity created with the purpose of owning or controlling distribution units.

Transmitters

·Neither a transmission company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling company of a generation company;

·Neither a transmission company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling company of a distribution company; and

·Transmission companies cannot buy or sell electricity.

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Distributors

·Neither a distribution company nor any of its controlled or controlling companies can be an owner, majority shareholder or the controlling company of a transmission company; and

·A distribution company cannot own generation units. However, the shareholders of an electricity distributor may own generation units either by themselves or through any other entity created with the purpose of owning or controlling generation units.

Horizontal Integration Restrictions

In addition to the vertical integration restrictions described above, distribution and transmission companies are subject to the following horizontal integration restrictions:

Transmitters

·Two or more transmission companies can merge or be part of a same economic group only if they obtain an express approval from the ENRE. Such approval is also necessary when a transmission company intends to acquire shares of another transmission company. Pursuant to the concession agreements that govern the services rendered by private companies operating transmission lines between 132 kW and 140 kW, the service is rendered by the concessionaire on an exclusive basis in certain areas indicated in the concession agreement. Pursuant to the concession agreements that govern the services rendered by the private companies operating the high-voltage transmission services of at least 220 kW, such companies must render the service on an exclusive basis and are entitled to render the service throughout the entire country, without territorial limitations.

Distributors

·Two or more distribution companies can merge or be part of a same economic group only if they obtain an express approval from the ENRE. Such approval is necessary when a distribution company intends to acquire shares of another transmission or distribution company; and

·Pursuant to the concession agreements that govern the services rendered by private companies operating distribution networks, the service is rendered by the concessionaire on an exclusive basis in certain areas indicated in the concession agreement.

Regulation of Generation Companies

Concessions

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 an indefinite term.

Such concession holders have the right to:

(i)take control of the private properties within the concession area (subject to general laws and local regulations) that are necessary to create reservoirs as well as underground or above ground supply-line and release channels;

(ii)flood lands that are necessary to raise water levels; and

(iii)request that the authorities make use of the powers conferred in Article 10 of Law 15,336 in cases where it is absolutely necessary to appropriate the property of a third-party that was not part of the concession and the concession holder has failed to reach an agreement with such third-party.

Dispatch

All generators that are Argentine MEM agents must be connected to the Argentine NIS and are obliged to comply with the dispatch order to generate and deliver energy to the Argentine NIS as determined by CAMMESA.

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Pricing

For generation companies other than biomass/biogas, hydroelectricity, nuclear plants and blocks of energy commercialized through regulated energy contracts, the SEE established, on February 2, 2017, guidelines for the remuneration of existing power plants.  The resolution defines a minimum remuneration for power by technology and size.

Additionally, thermal units have the option to offer commitments of availability with an equal differential remuneration for all technologies. Thermal generators can declare during each summer period the value of firm power to be committed for each unit during a three-year period with the ability to differentiate between summer and winter, with allowed adjustments within a given period.

On March 22, 2016, the SEE called for additional thermal generation capacity for the 2016 and 2017 summer seasons and during the 2017 and 2018 winter seasons.  Therefore, 2,871 MW were tendered and awarded in two stages, 1,915 MW in the first stage and the other 956 MW in the second stage. These tenders were implemented in order the meet the peaks of the demand.

For hydroelectric power plants, remuneration is based on actual power available (implying a higher power value for remuneration compared to the previous regulation).  Hydroelectric power plants also have a base power price and an additional price differentiated for the May-October period, and another for November-April. These remuneration values are denominated in U.S. dollars and are converted into Argentine pesos at the exchange rate published by the Central Bank of Argentina on the last business day of the two aforementioned periods (October and April), with maturity dates established by CAMMESA.

In 2002, the Emergency Law was enacted to handle the economic crisis that was facing the country in 2001. It obliged the renegotiation of public service contracts (such as electricity transmission and distribution concession contracts) and imposed the translation of obligations denominated in U.S. dollars to Argentine pesos at a fixed rate of Ar$ 1.00 for each US$ 1.00. The mandatory translation of transmission and distribution fees from U.S. dollars to Argentine pesos at this fixed rate (compared to the exchange rate at that time of approximately Ar$ 3.00 for each US$ 1.00) and the regulatory measures that limited and reduced spot and seasonality prices had a significant impact on energy prices and made the transfer of the variable generation costs to the tariffs charged to the final customers difficult. The Emergency Law also empowered the Argentine government to implement additional monetary, financial and exchange measures to overcome the economic crisis at medium-term. These measures have been extended periodically. Law 27,200 enacted in November 2015 extended the measures until December 31, 2017. There were no further extensions.

In November 2011, the Argentine MEM’s seasonal reference prices for non-subsidized electricity were published. Seasonal price corresponds to the cost of supply minus the subsidy. It is used to calculate the tariff of the end consumers and to guarantee the pass-through of the generation costs to the distributors.

This resolution also provided for:

(i)the discontinuation of the practice of charging subsidized prices for non-residential customers based on their payment capacity and economic activity;

(ii)the creation of a Register of Exceptions including a list of customers exempt from the subsidy elimination, provided that they can certify their inability to bear the seasonal reference prices for non-subsidized electricity; and

(iii)the identification of the National State Subsidy, requiring CAMMESA to explicitly identify the subsidies that it provides to each level of demand. Under the resolution, distributors are also required to notify residential customers that will be affected by the elimination of subsidies.

As a result of Decree 134, which declared a state of emergency for the Argentine electricity sector, the MEM has to enact a resolution to each change of the seasonal price, which are subsequently transferred to the tariff. The seasonal price is calculated based on the operational programming, dispatch and price calculations. Each resolution allows prices to reflect the actual energy cost, reducing the subsidies and creating differentiated prices for the residential customers based on their efficient energy usage. This was the first step towards the reestablishment of market conditions.

On December 1, 2017, the SEE published Resolution 1091 for the new stabilized prices for energy and transportation, covering the period from December 1, 2017 to April 30, 2018, reducing subsidies and increasing the tariff charged to end consumers.  In May 2018, Provision 44 fixed prices applicable to the MEM for the period from May 1 to October 31, 2018, maintaining prices fixed in 2017.  In July 2018, Provision 75 fixed prices for the period from August 1 to October 31, 2018, increasing wholesale prices, and also reducing subsidies.  In October 2018, Provision 97 fixed prices for the period from November 1, 2018 to April 30, 2019, maintaining prices established in July 2018 through Provision 75.

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Stabilization Fund

The stabilization fund, managed by CAMMESA, was created to absorb the difference between purchases by distributors 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 is required to 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 as a result of the modifications to the spot price and the seasonal price made by the emergency regulations, pursuant to which seasonal prices were set below spot prices resulting in large deficits in the stabilization fund. These deficits have been financed by the Argentine government through loans to CAMMESA and with FONINVEMEM funds, but these continue to be insufficient to cover the differences between the spot price and the seasonal price.

Sales to Distribution Companies and Regulated Customers

In order to stabilize the prices for distribution, the market uses the seasonal price as the energy price to be paid by distributors for their purchases of electricity traded in the spot market. This is a fixed price determined every six months by the Argentine Sub-Secretary of Energy based on CAMMESA’s recommended seasonal price level for the next period according to its estimated spot price. CAMMESA estimates this price by evaluating its expected supply, demand and available capacity, as well as other factors. The seasonal price is maintained for at least 90 days.

The emergency regulations also made significant changes to the seasonal prices charged to distributors in the Argentine MEM, including the implementation of a cap (which varies depending on the category of customer) on the cost of electricity charged by CAMMESA to distributors at a price significantly below the spot price charged by generators.

Specific Regulatory Charges for Electricity Companies

The authority to impose regulatory charges in Argentina is administratively divided among the federal, provincial and the municipal governments. Therefore, the tax charge varies according to where the customer lives.

Incentives and Penalties

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 that had a 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 main objective of the Energy Plus Service Program is to encourage large customers with a demand equal or greater to 300 kW, to sign a contract with a fast installation thermal generation power plants (such as gas turbine) and to penalize those who consume above their historical levels and do not have a contract with a fast installation thermal generations power plants.  Large Customers that do not enter into such contracts are required to pay additional amounts for any consumption that exceeds the Base Demand. The prices under the contracts with the Energy Plus Service Program must be approved by the authorities.  Unregulated customers who are unable to secure an Energy Plus Service contract are able to request CAMMESA to conduct an auction in order to satisfy their demand.

Regulation of Distribution Companies

Concessions

Distributors are companies holding a concession to distribute electricity to customers (concessions are given to distributors by the jurisdiction where they operate - national, provincial or municipal). Distributors are required to supply any and all demand of electricity in their exclusive areas of concession at tariffs and under conditions in accordance with the relevant local regulations. Penalties for failing to supply the electricity demand are included in the concession agreements.  Concessions are issued for distribution and retail sale, with specific terms for the concessionaire stated in the contract.  The concession periods are divided into “management periods” that allow the concessionaire to give up the concession at certain intervals.

Energy Purchases

Distribution companies must satisfy 100% of the demand of the customers in their concession area under specific regulated service quality standard and prices. To do so, distributors must secure their energy supply, reliability and quality.  Distribution

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companies purchase energy in the 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 beginning May 1 and the other beginning November 1.  A stabilized energy price is determined for each season according to the expected costs of generation during those six months.  Distributors purchase energy at that price and later the price difference when 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.

Distribution Tariff-Setting Process

On January 31, 2018, ENRE approved the new Tariffs Chart for Edesur, effective as of February 1, 2018. This Tariffs Chart considers inflation adjustments, the previous quarter’s ex-post adjustments, the 48 installment deferred value added from distribution (“VAD”) revenue, the efficiency factor, and the adjustments related to structural changes.

Additionally, these new tariffs include a decrease of the subsidies to the wholesale price, reaching up to 90% of the seasonal price operated in 2017. These tariffs maintain the Social Tariff subsidies and bonuses for the energy consumption savings of residential customers. The Social Tariff subsidies only apply to the generation component of the tariff and considers a special rate charged to low income consumers, equivalent to a percentage of the billing compared to the regular residential customer, generating a distortion of the tariff formula, which has to be recovered through some ex-post adjustments scheme. Low income consumers received a discount on the first 150 kWh in the month equivalent to the total (100%) value of the generation and 50% for the subsequent 150 kWh. Additionally, a 10% discount on the value of generation is applied on all residential consumers who consume at least 20% less compared to their historical levels.

As a result of the Integral Rate Revision (“RTI” in its Spanish acronym) mechanism, ENRE established the new revenue applicable for Edesur by virtue of its VAD effective as of February 1, 2017. The RTI mechanism determines the remuneration of distributors every five years.  Based on a gradual policy adopted by the Ministry of Energy and Mining, it instructed ENRE to increase VAD by a maximum of 42%. The revenue increase, which corresponds to the increase of the remuneration fixed by the RTI mechanism and the 42% increase of the VAD, was adjusted in two subsequent stages, together with the corresponding updates, on November 1, 2017 and on February 1, 2018.

In the RTI mechanism effective as of February 1, 2018, the following elements corresponding to the VAD component were included in the new Tariffs Chart:

(i)	the third installment of the Distribution Cost Increase associated to the RTI;
(ii)	the proportional part of the deferred revenue associated with gradual grandfathering provisions; and
(iii)	the Cost Monitoring Mechanism corresponding to the period and the application of the Efficiency Factor. The latter reflects the compliance by Edesur of the Investment Plan committed in the RTI whenever the expected value was reached.

The difference between the VAD determined by the RTI and the one currently applied in this gradual process constituted deferred revenue over 48 installments as of February 2018. On July 26, 2017, ENRE determined the specific procedure to bill deferred revenue. The RTI also determined that the VAD will be adjusted according to a “trigger clause”, which will update costs if the semi-annual CPI variation is higher than 5% (otherwise it will be postponed to the subsequent semester) and the adjustment mechanism dispositions, which will consider a semi-annual adjustment formula that considers salaries, wholesale inflation and retail inflation.

In December 2017, the MEM presented its proposal and criteria to consider the treatment of regulatory liabilities. In this proposal, the MEM clarified that the cancelation of the commercial debt for the purchase of energy from CAMMESA, the fines destined to the state and the difference in penalties for adjustments applied according to the interpretation of the ENRE, are all waived. Since then, several proposals were drafted and as of the date of this Report, no final proposal has been approved.

On December 1, 2017, ENRE approved the new values for Edesur’s Distribution Cost by applying the RTI mechanisms along with the new Tariffs Chart that incorporates the new seasonal prices (generation and transmission) included in SEE Resolution 1,091.  It also included the new schemes of Social Tariff subsidies and bonuses for the energy consumption savings of residential customers.

On July 30, 2018, and with the intention to grandfather tariff increases, the MEM signed an agreement with Edesur, committing to pay Edesur 50% of the increase corresponding to the adjustment mechanism foreseen in the tariff effective since August 1, 2018. The remaining 50% will be paid in six adjusted installments starting from February 1, 2018 and maintaining the Investment Plan

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Agreed in the RTI. The same agreement was also signed simultaneously with Edenor.  The Investment Plan Agreed is the proposal presented to the ENRE, based on which the remuneration for both Edesur and Edenor was calculated.

On August 1, 2018 and according to such agreement, 50% of the increase corresponding to the application of the Cost Monitoring Mechanism of August 2018 was applied to the VAD component. The Cost Monitoring Mechanism is a polynomial formula that adjusts the remuneration of distributors every six months, mainly adjusting remuneration by the inflation. With an increase close to 50%, which led to the price of the Large Users of the Distributors (demand greater than 300 kW/month) to approximately Ar$2,700/MWh and to the rest of the demand of the distributors to approximately Ar$1400/MWh.  Additionally, the ex-post adjustments corresponding to (i) the devolution of AT Transportation costs associated to the previous Tariffs Chart (regulatory amendment) and (ii) the amounts recognized as compensation for the Debit/Credit tax and the Health and Safety Taxes, were applied.

At the same time, the MEM took the opportunity to modify the maximum range of the Social Tariff subsidies.

Penalties

The distributors are subject to three types of penalties:

1)Quality of service penalties related to normal operation such as temporary interruptions, technical, and commercial services;

2)Extraordinary penalties, at the discretion of ENRE, apply when distributors do not comply with their service obligations (e.g., blackouts); and

3)Supply penalties related to the system as a whole including generation, transmission, and distribution intended to compensate customers.  The latter are temporarily suspended because the system is not generating enough electricity.

Regulation of Transmission

The transmission sector is regulated based on the principles established in the Electricity Framework and the terms of the concession granted to Transener S.A. (the main 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.  As instructed by Resolution 196 of the Ministry of Energy and Mining, the ENRE completed the RTI before January 31, 2017.

On November 30, 2017, the Secretary of Energy published Resolution 1,085, which approved the new methodology to distribute the remuneration cost of transmission. The resolution states that as of December 1, 2017, the cost of the transmission system is to be proportionately paid for by demand, and generators are to only pay for the direct connection costs.  It instructs CAMMESA to perform the respective calculations of the 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 determines that charges and bonuses no longer depend on the use of the installations but on regional allocation.

Electricity Exports and Imports

In 2018, the Argentine authorities once again enabled the export of natural gas, establishing a new procedure for authorizing exports, which are based on surplus production of natural gas generated from the policies carried out in recent years in terms of incentives for production. The authorized exports were destined for Chile, with a maximum quantity of 750,000 m³ per day and for a total volume of 479,250,000 m(3), under interruptible condition, and for the period from the authorization until June 1, 2020.

Additionally, the export of 600 MW of electricity to Brazil was completed from September 22 to September 28, 2018. The export was agreed by both CAMMESA and the ONS, the Brazilian Electric System National Operator. The export is possible thanks to the surplus of thermal generation and available fuels (mainly natural gas), enabling this transaction. The surplus is generated from the availability of gas resulting from a greater production of Vaca Muerta, which was possible due to private investment made in new electricity generation and the improvement of the availability from the thermal generation power plants which take advantage of the lower energy demand during the spring season. Such integration of operations represents both operating and economic benefits for both Argentina and Brazil.

Environmental Regulation

Electricity facilities are subject to federal and local environmental laws and regulations, including Law 24,051, the “Hazardous Waste Law” and its ancillary regulations.

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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 which, in case of public services, could result in the cancellation of concessions.

The use of NCRE is a national interest. In October 2015, Law 27,191 “National Development Scheme for the Use of Renewable Energy Sources for the production of Electric Power,” defined renewable energy sources as arising from:

(i)	wind energy;
(ii)	solar thermal;
(iii)	solar photovoltaic;
(iv)	geothermal;
(v)	tidal, wave, ocean currents, hydroelectric;
(vi)	biomass;
(vii)	landfill gas;
(viii)	gas treatment plants;
(ix)	biogas and
(x)	biofuels, except for the uses established in Law 26,093.

The new capacity limit for hydroelectric plants that qualify under Law 27,191 was changed from 30 to 50 MW.  The law establishes that large customers should meet their demand with contracts sourced with renewable technologies according to the following values: 12% in 2019, 16% in 2021, 18% in 2023 and 20% in 2025.

A maximum price of US$ 113 per MWh is set for renewable energy contracts in the MEM.  The law does not set a specific commitment to distributors.  It also establishes a penalty for those who do not comply with the rates established by Article 8 to pay a price equal to the variable cost of production of electricity generated with imported diesel fuel for the deficit of contracted renewable energy.  Law 27,191 also establishes incentives for investments including the anticipation of the VAD tax refund, the application of accelerated depreciation, the creation of a common fund for project financing and import duty exemptions.

Resolutions 71 and 72, dated May 17, 2016, of the Argentine Ministry of Energy and Mining extended Law 27,191 and Regulatory Decree 531, which commenced the Ministry’s 1,000 MW tender process for renewable energy. There were 123 offers for a total 6,366 MW (42 for wind energy for 2,870 MW, 50 for solar energy for 2,305 MW, eight for biomass and biogas for 23 MW, and five for small hydroelectric power for 11 MW). On September 30, 2016, offers were made with most falling below the maximum award price stipulated by the Ministry.  For wind energy the minimum price was US$ 49 per MWh and for solar energy US$ 59 per MWh.

On August 17, 2017, the Argentine Ministry of Energy and Mining issued Resolution 275-E which launched an open call to national and international players interested in supplying the MEM with NCRE-based electricity to award 1,200 MW (550 MW wind, 450 MW solar and the rest biogas, mini-hydro and biomass).  Resolution 473 later added an additional 50% of MW to the original call, allowing projects not awarded in the previous stage to participate in order to cover the capacity required by technology (275 MW wind, 225 MW solar and 67.5 MW from biogas and biomass).  On August 18, 2017, the Argentine Ministry of Energy and Mining issued Resolution 281-E establishing the rules of the Renewable Electricity Market, allowing generators with renewable sources to enter into contracts with large customers (above 300 KW).  The Renewable Energy Department later ruled on several administrative aspects through Provision No. 1/18.

Brazilian Electricity Regulatory Framework

Industry Overview and Structure

In the Brazilian Electricity Market, there are five categories of agents: generators, transmitters, distributors, traders and large customers.  According to Brazilian law, generation, transmission, distribution and trading are separated activities in Brazil.

Brazil’s electricity industry is organized into one large interconnected electricity system, the “Brazilian NIS,” which comprises most of Brazil, and several other small isolated systems. The Brazilian NIS is managed by the National Electricity System Operator (“ONS” in its Portuguese acronym) and is divided into four electric sub-systems: South-East/Center-West, South, North-East, and North.  In addition to the Brazilian NIS, there are also isolated systems that are located in northern Brazil and rely only on electricity generated from coal-fired and oil-fueled thermal plants.  According to the October 2018 monthly electricity report issued by the Energy Research Company (“EPE” in its Portuguese acronym), 99.4% of the energy required by Brazil is supplied by the Brazilian NIS and the remaining 0.6% is supplied by isolated systems.

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

i)Generators:

The generation sector is organized on a competitive basis, with independent generators selling their production through private contracts to distributors, traders and unregulated customers.  Differences between production and sales are sold on the short-term market or spot market at the Settlement Price for Differences (“PLD” in its Portuguese acronym).  There is also a special mechanism used by hydroelectric generators that seek to re-allocate hydrological risk by offsetting differences between hydroelectric generators’ assured energy and what is produced, called the Electricity Reallocation Mechanism (“MRE” in its Portuguese acronym).

ii)Transmitters:

The transmission sector operates under monopoly conditions.  Revenues of transmission companies are fixed by the Brazilian regulators.  This applies to all electricity companies with transmission operations in Brazil.  Transmission revenue is a fixed fee that does not depend on the amount of electricity transmitted.

iii)Distributors:

Distribution is a public service that operates under monopoly conditions and is comprised of companies that have been granted concessions.  Distributors in the Brazilian NIS are not allowed to:

(i)	perform activities related to electricity generation or transmission;
(ii)	sell electricity to unregulated customers that demand 3,000 kW or more;
(iii)	hold, directly or indirectly, any equity interest in any other company, corporation or partnership; or
(iv)	develop activities that are unrelated to their respective concessions, except for those permitted by law, approved by the regulator or in the relevant concession agreement.

iv)Traders:

The sale of electricity is governed by laws, decrees and resolutions dating back to 2004, including Law 10,848, Decrees 5,163 and 5,177 of the Electricity Trading Chamber or Wholesale Clearing House (“CCEE” in its Portuguese acronym), the role of the Brazilian National Electric Energy Agency (“ANEEL” in its Portuguese acronym) and Resolution 109, which introduced the Electricity Trading Convention that defines the terms, rules and procedures of CCEE trading.

Two possible scenarios were introduced by these regulations for the execution of energy sales agreements:

(i)	regulated contracts, with the participation of generation and distribution agents; and
(ii)	free market contracts, with the participation of energy generation, trading, importing and exporting agents, and unregulated customers.

Commercial relations between the agents participating in the CCEE are governed by energy sales agreements.  All agreements between agents in the Brazilian NIS are registered with the CCEE.  The register includes the amounts of

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energy and the terms of the agreement.  Energy prices agreed upon by the participating agents are not registered with the CCEE, but instead are specified by the parties involved in the agreements.

The CCEE records the differences between energy produced, consumed and the contracted amount.  The positive or negative differences are settled in the short-term market and priced at the PLD.  They are determined weekly for each level of required energy or load and for each sub-market, based on the system’s marginal operating cost, within a minimum and maximum price range.

v)Large Customers:

The unregulated market includes the sale of electricity between generation concessionaires, independent producers, self-producers, sellers of electricity, importers of electricity, unregulated customers, and special customers.  It also includes existing contracts between generators and distributors until their expiration.

Unregulated customers in Brazil are those who currently:

(i)	demand at least 3,000 kW generated from conventional sources and purchase their energy from generators or traders, but not from distributors; or
(ii)	demand 500-3,000 kW generated from NCRE sources and purchase their energy from any source, including distributors.

Principal Regulatory Authorities

The Brazilian Ministry of Mines and Energy (“Brazilian MME”) regulates the electricity industry and its primary role is to establish the policies, guidelines and regulations for the sector. The Energy Research Company is an entity that reports to the Brazilian MME.  Its purpose is to conduct research and studies to support energy sector planning.

The Brazilian National Energy Policy Council is in charge of developing the national electricity policy.  Its main responsibilities include:

(i)	formulation of energy policy and guideline recommendations to the Brazilian president;
(ii)	promotion of stability and supply security in the country’s energy resources;
(iii)	provision that energy supply must reach all of Brazil, including the most remote areas;
(iv)	directives for specific programs (such as the use of natural gas, biofuel, biomass, coal and thermonuclear energy); and
(v)	directives for the import and export of energy.

The ANEEL is the entity that implements regulatory policies.  Its main responsibilities include:

(i)	supervision of the concessions for electricity sale, generation, transmission and distribution;
(ii)	enactment of regulations for the electricity sector;
(iii)	implementation and regulation of the exploitation of electricity resources, including the use of hydroelectricity;
(iv)	establishment of a bidding process, under MME directive, for new concessions;
(v)	resolution of administrative disputes between electricity sector agents; and
(vi)	establishment of criteria and methodology to determine all tariffs that ensure that customers pay a fair price for energy and preservation of the distribution economic and financial balance so the latter can provide quality service and continuity.

The Energy Sector Monitoring Committee (“CMSE” in its Portuguese acronym), reporting to the Brazilian MME, was created to evaluate the continuity and security of the energy supply across the country.  The CMSE:

(i)	follows the development of the energy generation, transmission, distribution, trading, import and export activities;
(ii)	assesses the supply and customer service as well as the security of the system;
(iii)	identifies difficulties and obstacles that affect supply security and regularity; and
(iv)	recommends preventive measures to help preserve supply security and service.

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The CCEE is a non-profit organization subject to authorization, inspection and regulation by ANEEL and its main purpose is to carry out wholesale transactions and electricity trading in the Brazilian NIS.  It records the agreements resulting from the adjustments among market agents, which are classified into four categories: generation, distribution, trading and customers.

The ONS is comprised of generation, transmission and distribution companies, and independent customers, and is responsible for the coordination and control of the generation and transmission operations of the Brazilian NIS, subject to the ANEEL’s regulation and supervision.

The Brazilian Institute of Environment and Renewable Natural Resources (“IBAMA” in its Portuguese acronym) is an executive body of the National Environmental Policy, which acts as a federal independent organization.  It is part of the Ministry of Environment, responsible for the implementation of the National Environmental Policy and the preservation and conservation of natural heritage, and exercises control and supervision over the use of natural resources.

The Electricity Law

General

The Brazilian electricity law encourages competition and private capital.  Assets owned by the Brazilian government and/or state governments continue to be privatized. The Electricity Sector Law introduced the concept of 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 produce electricity for subsequent sale.

The wholesale energy market is composed of generation 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 the spot market prices as set by the CCEE.   These prices are calculated on a marginal cost basis, modeling future operation conditions and setting a merit order curve with variable costs for thermal units and opportunity cost for hydroelectric plants, resulting in one price for each subsystem set for the week after its determination.

ANEEL regulates and monitors the wholesale energy market structure. It is also responsible for setting wholesale energy market governance rules, including measures to stimulate external investment.  Since 2002, Brazil has been promoting the development of alternative energy sources, the globalization of energy services and subsidies to low-income residential customers.

The current Brazilian electricity sector regulatory framework model has the following primary objectives:

(i)	guarantee the security of the electricity supply and promote reasonable tariffs; and
(ii)	improve social integration in Brazil through programs designed to provide universal access to electricity.

In addition, the model contemplates a series of measures for industry players, such as the obligation of distributors and unregulated customers to satisfy all their electricity supply through contracts.   It also defines a methodology to calculate the actual physical back-up of the generation capacity that guarantees electricity generation contracted sales, ensuring that hydroelectric and thermal plants contract their capacity in proportions that offer the best balance between the cost of such coverage and the cost of supply.  Electricity supply continuity and security are constantly monitored, and there is an emphasis on early detection of occasional imbalances between supply and demand.

In 2016, the existing laws and regulations were improved and included modifications such as:

(i)	a transfer to CCEE of the responsibility of managing Global Reversal Reserve, Fuel Consumption Account and Energy Development Account funds;
(ii)	allowance of the transfer of a company’s control as an option to expiration of the concession;
(iii)	authorization for the sale of contractual surplus energy by distributors to free consumers.

In terms of tariffs, the model requires distributors to purchase electricity in a regulated environment through public auction promoted by the Government and managed by ANEEL in order to obtain the lowest tariffs. This procedure allows for reductions in the cost of electricity that distributors pass on to customers’ tariffs.  The new model also includes a subsidy for low-income customers.

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Regulation of Generation Companies

Concessions

The Concessions Law provides that upon receiving a concession, IPPs and customers will have access to the distribution and transmission systems owned by other concessionaires provided they are reimbursed for their costs as determined by ANEEL.

Companies or consortia that intend to build or operate hydroelectric generation facilities with a capacity exceeding 30 MW or transmission networks in Brazil must resort to a public tender process.  Concessions granted to the holder give the right to generate, transmit or distribute electricity in a given concession area for a certain period of time.

New generation concessions are limited to a maximum of 35 years and up to 30 years for new transmission or distribution concessions.  Existing concessions may be renewed at the Brazilian government’s discretion for a period equal to their initial term.

In 2013, Brazilian Congress authorized the extension of transmission, distribution and both hydroelectric and thermal plant generation concessions that expire between 2015 and 2017 for a maximum of 30 years.

Dispatch and PLD Pricing

The PLD is used to value the differences between purchases and sales of electricity in the short-term market.  The price-setting process of the electricity traded in the short-term market is based on the data used by the ONS to optimize the operation of the Brazilian NIS.

The mathematical models used to compute the PLD consider the preponderance of hydroelectric plants within the Brazilian electricity generation grid.  The purpose is to find an optimal equilibrium between the current benefit obtained from the use of water and the future benefit resulting from its storage, measured in terms of the savings from the use of fuels for thermal plants.

The PLD is an amount computed on a weekly basis for each load level based on the marginal operational cost, which in turn is limited by a maximum and minimum price for each period and submarket.  The intervals set for the duration of each level are determined by the ONS for each month and reported to the CCEE to be included into the accounting and settlement system.

The model used to compute the PLD seeks to achieve an optimal result for any given period and to define both the hydroelectric and thermal power generation for each submarket, first considering the electricity demand, then the hydrological conditions, the prices of fuel, the cost of the deficit, the entry of new projects into operation and the availability of equipment used for generation and transmission.  As a result of this process, the marginal operational costs is obtained for each load level and submarket.

The calculation of the price is based on the ex-ante dispatch that is determined using estimated information existing prior to the actual operation of the system, taking into account the declared availability amounts regarding both the generation and the consumption envisaged for each submarket.  The complete process for calculating the PLD involves the use of models to calculate the marginal operational cost for each submarket on a monthly and weekly basis.

ANEEL defines new limits for the PLD annually.   In December 2018, the range of the PLD for 2019 was established between R$ 40.16-R$ 505.18 per MWh.

Electricity Reallocation Mechanism

The MRE provides financial protection against hydrological risks for hydroelectric generators by ensuring the optimal use of the hydroelectric resources of the interconnected power system.

The mechanism guarantees that notwithstanding the centralized dispatch, all hydroelectric generators that participate in the MRE will have a participation in the overall hydroelectric generation dispatched in proportion to their “assured energy,” or maximum firm energy, which is the electricity that a hydroelectric generation plant is able to deliver on a continual basis during a year, with poor hydrological conditions.  The final value of the energy allocated to a hydroelectric generator can be greater or lesser than its assured energy depending on the actual hydroelectric generation in relation to the overall hydroelectric assured energy.  This mechanism permits each hydroelectric generator, before buying energy in the spot market, to fulfill its contracts, to purchase cheaper energy at a price that covers the incremental costs of operation, the maintenance of hydroelectric plants and the financial compensation for use of water.  The tariff used for trading energy in the MRE, the Optimum Energy Tariff, was set as R$ 11.87 per MWh for 2018.

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The system’s overall hydroelectric generation is more stable than the individual hydroelectric generation of a power plant.   Therefore, the MRE is an efficient mechanism to reduce the volatility of individual power plant generation and hydrological risk. Energy contracts in Brazil are only financial instruments, and electricity generation is totally disassociated from energy contracted.

In November 2015, as a way of mitigating the impacts of a drought, ANEEL approved the conditions for renegotiating hydrological risk with the hydroelectric generators that participate in the MRE and established that from 2017 ANEEL will calculate the valuation, the eligible amount and the payment conditions resulting from the displacement of hydroelectric generation for the MRE participants.

Sales between Market Agents

The current electricity industry model establishes that electricity is traded within two market environments:

·the Regulated Contract Environment (“ACR” in its Portuguese acronym) and

·the Free Market Contract Environment (“ACL” in its Portuguese acronym).

Trading in the ACR is formalized by means of regulated, bilateral agreements, called Electric Power Trading Agreements, carried out between selling agents (sellers, generators, independent producers or self-producers) and purchasing agents (distributors) who participate in electric power purchase and sale tenders.

In the ACL environment, on the other hand, the negotiation among the generating agents, trading agents, free-market customers, importers and exporters of electric power is carried out freely, through bilateral agreements.

Generation agents, regardless of whether they are public generation concessionaires, IPPs, self-producers or trading agents, can sell electricity in both environments.  This maintains the overall competitiveness of the market.  All agreements that have been signed in the ACR or the ACL are registered in the CCEE and used to calculate the settlement of differences in the short-term market.

Sales by Generation Companies to Unregulated Customers

In the unregulated contract environment, the conditions for purchasing energy are negotiable between suppliers and their customers.  As for the regulated environment, where distribution companies operate, energy purchases must be conducted through a bidding process coordinated by ANEEL.

Sales by Generation Companies to Distribution Companies and Regulated Customers

Pursuant to market regulations, all of distributors’ energy demand must be satisfied through regulated tenders coordinated by ANEEL, which are numbered A-i, where i is an integer starting with 0.

There are separate tender processes for:

(i)	existing capacity to adjust the conditions of current contracts or to enter into new power purchase agreements to replace expired agreements; and
(ii)	new capacity to meet future demand.

Tenders for existing capacity are A-i tenders, energy adjustment tenders, to supplement the energy needed to supply distribution customers within the concession area, purchasing energy from all existing generation sources through energy purchase agreements for up to five years.

Future energy needs are covered through A-i tenders, to purchase energy from new generation sources, and reserve tenders that are also carried out to improve the stability of the system to be supplied i years following the tender.  Both types of tenders involve purchase agreements ranging from 20 to 30 years.

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	Plant Types
Tender	New	Existing	NCRES	Indicated by Government(1)	Auctioned together with transmission grids
A-0		X	X
A-1		X	X
A-2		X	X
A-3	X	X	X
A-4	X	X	X
A-5	X	X	X	X	X
A-6	X		X	X	X
A-7				X	X

(1)The Brazilian government determines the type of technology and projects that can participate in each auction.

Tenders A-0 to A-5 were held in 2014-2017.

In 2018, there were two tenders with the following results:

· Tender A-4: 356.19 MW(avg), allocated to hydro (6.6%), biomass (9.7%), wind (16.2%) and solar (67.5%) at an average price of R$ 124.75 MWh.

· Tender A-6: 1,228.59 MW(avg), allocated to gas (26.6%), hydro (18.9%), biomass (0.9%) and wind (53.6%) at an average price of R$ 140.87 MWh.

During 2018, two tenders for the existing power plants (plants in operation) were launched: A-1 and A-2.

Sales of Capacity to Other Generation Companies

Generators can sell their energy to other generators directly, freely negotiating prices, terms and conditions.

Incentives and Penalties

Another change imposed on the electricity sector is the separation of the bidding process for “formerly existing power” and “new power” projects.  The Brazilian government believes that a “new power project” needs more favorable contractual conditions such as long-term power purchase agreements (15-25 years for thermal and 30 years for hydroelectric) and certain price levels for each technology in order to promote investment for the required expansion.  On the other hand, “formerly existing power plants,” which include depreciated power plants, can sell their energy at lower prices under contracts with shorter terms.

Law 10,438 created certain incentive programs, which include a discount of up to 50% on the distribution or transmission tariffs and a special exception for the customers with electricity demand in the range of 500-3,000 kW who decide to migrate to an unregulated environment, provided that such customers purchase electricity only from NCRE sources such as wind power, solar power, small hydro plants and biomass for plants under 30 MW if authorized before January 1, 2016, and up to 300 MW if authorized subsequently (with the exception of the small hydro plants, which are still limited to 30 MW).

Selling agents are responsible for paying the buying agent if they are unable to comply with their delivery obligations.  ANEEL regulations set forth the fines applicable to electricity agents based on the nature and the materiality of the violation (including warnings, fines, temporary suspension of the right to participate in bids for new concessions, licenses or authorizations and forfeiture). For each violation, fines may be imposed for up to 2% of the concessionaire’s revenues arising from the sale of electricity and services

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provided (net of taxes) in the 12-month period immediately preceding any assessment notice.  ANEEL may also impose restrictions on the terms and conditions of agreements between related parties and, under extreme circumstances, terminate such agreements.

Selling agents must assure 100% physical coverage for their energy and power contracts.  This coverage must be made up of physical guarantees from its own power plants or through the purchase of energy or power contracts from third parties.  When these limits are not met, generation companies and traders are subject to financial penalties.  The determination of penalties is based on a 12-month period and the revenue obtained from the penalties are reverted to tariff modality within the ACR.  If the limits on contracting and physical coverage defined in the Trading Rules are not met, the relevant generation companies and traders are notified by the Superintendent of the CCEE.  Pursuant to the specific Trading Procedure, CCEE agents are allowed to file an appeal to be evaluated by the CCEE Board of Directors which then decides whether to collect or to cancel the financial penalty.

Generation agents may sell power through contracts signed within the ACR or the ACL.  IPPs must provide physical coverage from their own power generation for 100% of their sales contracts.  Self-producers generate energy for their own exclusive use and they may sell excess power through contracts with ANEEL’s authorization.  In both cases, the verification of physical coverage is performed monthly, based on generation data and on sales contracts for the last 12 months.  Generation agents must pay penalties if they fail to provide physical coverage.

Regulation of Distribution Companies

Energy Purchases

In the regulated market, electricity distribution companies must buy electricity through public auctions carried out regularly, regulated by ANEEL and organized by CCEE.

There are two types of regulated bids that contract:

(i)

existing capacity to adjust the conditions of the current contracts or enter into new power purchase agreements to replace expired agreements; and

(ii)

new capacity, including renewable electricity (biomass, mini-hydroelectric, solar and wind power) to meet future demand. Please refer to “Item 4. Information on the Company— B. Business Overview — Electricity Industry Regulatory Framework —Brazilian Electricity Regulatory Framework — Regulation of Generation Companies — Sales by Generation Companies to Distribution Companies and Regulated Customers.”

Authorities define a cap price and all the participating distributors who call for bids enter into contracts on a prorated basis with each of the bidding generators.

Distribution Tariffs to End Customers

Distribution tariffs to end customers are subject to reviews performed every 3, 4 or 5 years, adjustments performed annually and extraordinary reviews by ANEEL in response to changes in energy purchase costs and market conditions.

Distribution Tariff-Setting Process

When adjusting distribution tariffs, ANEEL divides the Annual Reference Value, the costs of distribution companies, into: (i) costs that are beyond the control of the distributor, such as energy purchases and taxes (“Parcel A costs”), and (ii) costs that are under the control of distributors (“Parcel B costs”), the Value-Added Distribution. Each distribution company’s concession agreement provides for an annual adjustment.

The Concessions Law establishes three kinds of reviews for end customer tariffs:

(i)	ordinary tariff review according to the concession contract of each distributor;
(ii)	annual inflation adjustments less an “X” factor (a unique value for each distributor which reflects its recent efficiency gains, the management of its operating costs, and its service quality); and
(iii)	extraordinary tariff reviews.

Distribution companies’ pricing is intended to maintain constant operating margins for the concessionaire by allowing for tariff gains due to Parcel A costs and by permitting the concessionaire to retain any efficiency gains achieved for defined periods of time. Tariffs to end customers are also adjusted according to the variation in costs incurred in purchasing electricity.

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The value adjustment account (“CVA” in its Portuguese acronym) is a mechanism that helps to maintain stability in the energy market and enables the creation of deferred Parcel A costs, which are compensated through annual tariff adjustments based on fees to offset the deficits/surpluses of the previous year.

In December 2014, distributors in Brazil signed an amendment to the concession contracts that allowed deferred costs, including CVA, to become part of the assets to be compensated at the end of the concession, if they were not previously compensated through tariffs.  IFRS allows the recognition of deferred revenue by ensuring that the amounts are recoverable.

Ordinary tariff reviews take into account the entire tariff-setting structure for the company, including the costs of providing services and purchasing energy, as well as a return for the investor.  Distributors define the tariff review period at the time their respective concession agreements are executed.  Some distributors have three years, most have four years and some have five-year periods.  This means the tariff review applies to all distributors, but spanning different periods.

Since 2003, ANEEL has carried out periodic tariff revisions every 4-5 years, and these define the methodology to be applied during ordinary tariff reviews.

The law guarantees an economic and financial equilibrium for a company in the event that there is a substantial change in its operating costs.  In the event that the Parcel A cost components increase significantly within the period between two annual tariff adjustments, the concessionaire may request that ANEEL pass those costs through to end customers.

Governmental Tariff Reduction Plan

In the third and fourth cycles of periodic tariff revisions, ANEEL applied a benchmarking methodology in order to define the efficient regulatory operating costs, which observes a relation between the products that a distributor delivers (such as network, energy delivered, consumers, quality and losses) and its operational costs.

The new rate was published in the Normative Resolution 648 on March 2, 2015, effective retroactively as of February 5, 2015.  The methodology for the fourth tariff cycle was applied to all distributors in their ordinary tariff reviews.   In March 2018, ANEEL decided to maintain the 12.3% WACC until 2019.  The WACC is applied over the net regulatory asset base of distribution companies in order to ensure the return of shareholder’s investment. In 2018, ANEEL should have updated the series for the WACC calculation but due to a significant decrease to approximately 7.5%, which would had severely impacted distribution companies’ revenues, the regulator decided to maintain the WACC at the same value and discuss the methodology entirely in 2019.

Revenue from Tariff Flags

Since January 2015, ANEEL has applied an additional monthly charge to the customers’ tariffs, whenever the actual marginal cost of the system is 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 three main levels color coded green, yellow and red. Since its creation, the cost ranges and the additional tariffs have been changing according to new expectations of the marginal cost of generation:

	Description	Additional Tariff Rate(R$/kWh)
Green	Favorable generation conditions	No additional rate
Yellow	Less favorable generation conditions	+0.010
Red level 1	Expensive generation conditions	+0.030
Red level 2	Most expensive generation conditions	+0.050

On September 12, 2016, ANEEL approved Resolution 733, establishing the application of an hourly tariff to low voltage customers and defined where they may monitor the value of energy during consumption.  This new tariff is called a white tariff and became effective in January 2018.

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Energy Development Account (Cuenta de Desarrollo Energético or “CDE”)

In September 2015, ANEEL allowed distributors to discount the lost contribution from the payments to the CDE fund.

The CDE is a sector charge that is used by the government to for fund public policies of the Brazilian electric sector, such as: electric energy service universalization; discount on tariffs to several customers (low-income customers, rural customers, public service of water, etc.).

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

In 2018, the CDE quota increased (51%) and it was mainly due to:

i)	fund deficit;
ii)	the increase of energy costs in isolated areas; and
iii)	the increase of tariff subsidies granted to customers.

Between January 1, 2017 and December 31, 2029, CDE’s annual charges will decrease gradually until they are fully satisfied.  As of January 1, 2030, the annual cost per MWh will be prorated according to the level of customer’s connected tension.

Extension of Distribution Concession Contracts

Since September 2012, the distribution concessions may be extended by the Brazilian government only one time, for a period of up to 30 years, to ensure continuity, efficient service, feasible rates and profitability for the distributors.

In 2018, Enel Distribution Río S.A underwent its tariff review process, with the following results: the average adjustment for low voltage customers increased by 21.5% and for medium and high voltage customers by 19.9%.  These results were not definitively established and will be reviewed again in 2019 since the regulatory asset base and the loss trend were provisional.

On February 13, 2017, ANEEL issued Resolution No. 758 establishing the conditions required to transfer installations with a voltage under 230 kV (Basic Network referred to as “DIT”) that pertain to transmissions from electricity transmission companies to distribution concessionaires. Enel Distribution Rio S.A. will receive DITs in its first ordinary tariff review to take place after January 1, 2019. Enel Distribution Ceara S.A. will not receive any DIT.

Regulation of Transmission Companies

Transmission lines in Brazil are usually very extensive since most hydroelectric plants are usually located far away from the large centers of energy consumption.  Today, the country’s system is almost entirely interconnected.  Only the states of Amazonas, Roraima, Acre, Amapá, Rondônia and a part of the state of Pará do not have access to the interconnected power system.  In these states, electricity is supplied by small thermal plants or hydroelectric plants located close to their respective capitals, but the Brazilian government is gradually connecting these areas as well.

The interconnected electricity system provides for the exchange of electricity among the different regions when any region faces problems, such as a reduction in hydroelectric generation due to a drop in reservoir levels.  As the rainy seasons are different in the south, southeast, north and northeast of Brazil, the higher voltage transmission lines (500 kV or 750 kV) allow locations with insufficient energy production to be supplied by generation centers located in areas with more favorable conditions.

Any electricity market agent that produces or consumes energy is entitled to open access to use the basic network, and such access is guaranteed by law and ANEEL.  Unregulated customers also have an open access right provided that they comply with certain technical and legal requirements.

The ONS is responsible for the operation and management of the basic network, as well as for managing energy dispatched from plants in optimized conditions involving use of the interconnected power system hydroelectric reservoirs and thermal plants’ fuel.

Transmission revenue is a fixed fee that does not depend on the amount of electricity transmitted. Similar to distribution companies, transmission companies have three tariff reviews:

(i)an ordinary tariff review every four years;

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(ii)	an annual tariff adjustment due to inflation and the annual allowed revenues (a fixed amount paid by consumers and generators); and
(iii)	an extraordinary tariff review.

Environmental Regulation

The Brazilian constitution gives the federal, state and local governments power to enact laws designed to protect the environment, and to issue regulations under such laws.  While the Brazilian government is empowered to enact environmental regulations, the state governments are usually more stringent.  Most of the environmental regulations in Brazil are at the state and local level rather than the federal level.

Hydroelectric facilities are required to obtain concessions for water rights and environmental approvals.  Thermal electricity generation, transmission and distribution companies are required to obtain environmental approvals from environmental regulatory authorities.

Colombian Electricity Regulatory Framework

Industry Overview and Structure

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

There are two categories of agents, generators and traders, who are allowed to buy and sell electricity as well as related products in the Colombian MEM.  All of the electricity supply offered by generation companies connected to the Colombian National Interconnected System (“NIS”) and all of the electricity requirements of end-customers, whose demand is represented by trading companies, are traded on the Colombian MEM.

There is one interconnected system, the Colombian NIS, and several isolated regional and smaller systems that provide electricity to specific areas.  According to the Colombian Mining and Energy Planning Unit, 98% of the Colombian population in 2018 received electricity through the public network.

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

Generation activity consists of the production of electricity through hydroelectric, thermoelectric and NCRE plants connected to the Colombian NIS.

A summary of key generation sector provisions includes the following:

·Generators are organized on a competitive basis, with independent generators selling their output on the spot market or through private contracts with large customers, other generators and traders.

·Generators with generation capacities of at least 20 MW are required to participate in the Colombian MEM with all of their generation plants or units connected to the Colombian NIS. Plants with installed capacity lower than 20 MW are called “minor plants” or “not centrally dispatched plants” and they are dispatched at the base, meaning they are the first to be dispatched.

·Generators declare their energy availability and the price at which they are willing to sell it. This electricity is centrally dispatched by the CND.

Trading consists of intermediation between the market participants that provide electricity generation, transmission and distribution services and the customers of these services, whether or not that activity is carried out together with other electricity-sector activities.

Electricity transactions in the Colombian MEM are carried out under the three following modes:

1.Energy spot market: short-term daily market

2.Bilateral contracts: medium- and long-term markets; and

3.“Firm Energy.”

“Firm Energy” refers to the maximum electric energy that a generation plant is able to deliver on a continual basis during a year, with poor hydrological conditions.  The generator who acquires a Firm Energy Commitment (“OEF” in its Spanish acronym) will receive a fixed remuneration during the commitment period, which is described under “— Incentives and Penalties” below.

Transmission operates under monopoly conditions with a guaranteed annual fixed income that is determined by the new replacement value of the networks and equipment, and by the resulting value of bidding processes awarding new projects for the

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expansion of the National Transmission System.  This value is allocated among the traders of the National Transmission System in proportion to their energy demand.

Distribution is defined as the operation of local networks below 220 kV.  Any customer may have access to a distribution network for which the customer pays a connection charge.

Principal Regulatory Authorities

The Colombian Ministry of Mines and Energy (“Colombian MME”) is responsible for electricity sector policy, which aims for a better use of the mining and energy resources available in Colombia, and in turn contributes to the country’s social and economic development.  The Colombian Mining and Energy Planning Unit is responsible for planning the expansion of the generation and transmission networks.

The Energy and Gas Regulatory Commission (“CREG” in its Spanish acronym) implements the principles of the industry set out by the Colombian Electricity Act. This commission is constituted by eight experts named by the Colombian President, the MME, the Colombian Ministry of Finance and Public Credit and the director of the Colombian National Planning Department or their delegates. The Superintendent of Domiciliary Public Services participates in discussion but without a vote on topics that correspond to domiciliary public services. Such principles are:

·efficiency (the correct allocation and use of resources and the supply of electricity at minimum cost);

·quality (compliance with technical requirements);

·continuity (continuous electricity supply without unjustified interruptions);

·adaptability (the incorporation of modern technology and administrative systems to promote quality and efficiency);

·impartiality (equal treatment for all electricity customers);

·solidarity (the provision of funds by high-income customers to subsidize the subsistence consumption of low-income customers); and

·fairness (an adequate and non-discriminatory supply of electricity to all regions and sectors of the country).

CREG is empowered to issue regulations that govern technical and commercial operations and to set charges for regulated activities. CREG’s main functions are to:

(i)establish conditions for gradual deregulation of the electricity sector toward an open and competitive market;

(ii)approve charges for transmission and distribution networks and for regulated customers;

(iii)establish the methodology for calculating maximum tariffs for supplying the regulated market;

(iv)regulations for planning and coordination of operations of the Colombian NIS;

(v)technical requirements for quality, reliability and security of supply; and

(vi)protection of customers’ rights.

The National Operations Council is responsible for establishing technical standards to facilitate the efficient integration and operation of the Colombian 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 entity that assists CREG with the commercial aspects of the Colombian MEM.

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

The Colombian Ministry of Environment and Sustainable Development (“MADS” in its Spanish acronym) is responsible for the management of the environment and renewable natural resources. It is also responsible for guiding and regulating environmental

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planning as well as developing policies and regulations. Its goal is to recover, preserve, protect, and promote sustainable use of renewable natural resources and the environment, as well as ensure sustainable development.

The MADS, together with the Colombian President, seek to develop national environmental and renewable natural resource policies to ensure the right of Colombians to a healthy environment in which natural heritage and national sovereignty are protected.

The Electricity Law

General

In 1994, the basic legal framework that currently governs the electricity sector in Colombia was enacted. The most significant reforms included:

(i)	the opening of the electricity industry to private sector participation;
(ii)	the functional segregation of the electricity sector into four distinct activities (generation, transmission, distribution and trading); and
(iii)	the creation of an open and competitive wholesale electricity market, the regulation of transmission and distribution activities as regulated monopolies and the adoption of universal open access principles applicable to transmission and distribution networks.

The Colombian Electricity Act regulates electricity generation, trading, transmission, and distribution (collectively, the “Activities”). Under the law, any company existing before 1994, domestic or foreign, may undertake any of the Activities. Companies established subsequent to such date can engage exclusively in only one of such Activities. Trading, however, can be combined with either generation or distribution.

In 2014, the Colombian government published Renewable Energy Law 1,715, which promotes the development of renewable energy and energy efficiency projects. The law proposes tax reductions for projects involved with renewable energies. It also establishes the development of a national fund that promotes research on related topics and defines the methodology for self-generation. Several regulations related to renewable energy were published since then.

Limits and Restrictions on Market Share

Market share for generators and traders is capped at certain maximum levels.  The limit for generators is 25% of the Colombian system’s Firm Energy. The principal market share metric used by CREG to regulate the generation market is the percentage of Firm Energy that a market participant holds.  Additionally, if an electricity generation company’s share of Colombia’s total Firm Energy ranges from 25% to 30% and the market’s Herfindahl Hirschman Index, a measure of market concentration, is at least 1,800, such company becomes subject to monitoring by the Colombian 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 trading activity in the Colombian NIS. Limitations for traders take into account international energy sales.  Market share is calculated on a monthly basis 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 are applied to economic groups, including companies that are controlled by, or under common control with, other companies.  In addition, generators may not own more than a 25% interest in a distributor, and 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 over 25% of an integrated company’s equity if the market share of the latter company 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.

Regulation of Generation Companies

Concessions

Since 1994, economic activities related to the supply of the electricity service are governed by the

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(i)	constitutional principles of free market economic activity;
(ii)	free market private initiative;
(iii)	freedom to enter and leave the market;
(iv)	corporate freedom;
(v)	free market competition and private property, with regulation and inspection, surveillance and control by the state.

These constitutional principles of freedom are the general rule in the electricity industry, while the concession is the exception.  Different economic, public, private or mixed agents may participate in the sector’s activities, which agents shall enjoy the freedom to develop their functions in a context of free market competition.  To operate or start up projects, agents must obtain from the competent authorities the necessary environmental, sanitation and water-right permits as well as other municipal permits and licenses.  All economic agents may build generation plants and their respective connection lines to the interconnection and transmission networks.

The Colombian government is not legally allowed to participate in the execution and exploitation of generation projects. As a general rule, such projects are to be carried out by the private sector.  The Colombian government is only authorized to enter into concession agreements on its own behalf relating to generation when there are no agents prepared to assume these activities on comparable conditions.

Dispatch and Pricing

The purchase and sale of electricity can take place between generators, distributors acting in their capacity as traders, traders (who do not generate or distribute electricity) and unregulated customers.  There are no restrictions for new entrants into the market as long as the participants comply with the applicable laws and regulations.

The Colombian MEM facilitates the sale of surplus energy that has not been committed under contracts.  In the wholesale market, an hourly spot price for all dispatched units is established based on the offer price of the highest priced energy dispatched unit for that period.

The National Dispatch Center (“CND”) receives price bids each day from all the generators participating in the Colombian MEM. These bids indicate prices and the hourly available capacity 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 in order to satisfy expected demand.  The price for all generators is set as the most expensive generator dispatched in each hourly period under the 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.

Additionally, the CND plans for the dispatch, which takes into consideration the limitations of the network, as well as other conditions necessary to satisfy the energy demand expected for the following day in a safe, reliable and cost-efficient manner. The cost differences between the “planned dispatch” and the “optimal dispatch” are called “restriction costs.”  The net value of such restriction costs is assigned proportionally to all the traders within the Colombian NIS, according to their energy demand, and these costs are passed through to the end customers. Some generators have initiated legal proceedings against the government arguing that recognized prices do not fully cover the costs associated with these restrictions because current regulations do not take into account all the costs of safe, reliable generation.

Sales by Generation Companies to Unregulated Customers

In the unregulated market, generation companies and unregulated customers sign contracts in which terms and prices are freely negotiated. Typically, these agreements establish that the customer pays for the energy that it consumes each month without a minimum or maximum.  The prices are fixed in Colombian pesos indexed monthly to the Colombian PPI. To be considered “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.

Sales by Generation Companies to Traders for the Regulated Market

Traders in the regulated market are required to buy energy through procedures that ensure free market competition.  For evaluating the bids, the buyer takes into account price factors as well as other technical conditions and commercial objectives to be defined before the contracting process.  These agreements can be signed with different terms, such as for amounts contracted, demanded with or without a limit, or actually consumed, etc. Prices are denominated in Colombian pesos indexed monthly to the Colombian CPI.

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Sales to Other Generation Companies

Generators can sell their energy to other generators at freely negotiated prices and conditions.

Regulatory Charges

Generation companies are obliged to pay monthly payments based on their generation to the regional autonomous corporations for environmental protection in areas where the plants are located and to the municipalities where the generation plants are situated. For more information, see “— Environmental Regulation” below.

Generation contribution to the Financial Support Fund for Energy for Non-Interconnected Zones: generators must make a contribution of one Colombian peso to the Financial Support Fund for Energy for Non-Interconnected Zones for every kilowatt dispatched on the Wholesale Energy Exchange. This requirement was extended to 2021.

Generation Income

Generators connected to the Colombian NIS can also receive “reliability payments” which are a function of the OEF that they provide to the system.  The OEF is a commitment on the part of generation companies backed by their physical resources capable of producing 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.  To receive reliability payments, generators have to participate in firm energy bids by declaring and certifying such firm energy.  The OEF assignation auctions are oriented to generation projects with construction periods under four years and projects with long construction periods (“GPPS” in its Spanish acronym).  In addition, CREG can carry out OEF reconfiguration auctions oriented to adjust the differences between the assigned OEF and expected demand.  When demand is higher or lower than expected, CREG can organize auctions in which it can acquire more firm energy, or on the contrary, agents with excess OEF can sell their commitments.

CREG regulates the reconfiguration auction scheme, under the methodology of reliability charge that allows agents to change the beginning of the OEF by renouncing the “reliability payments” and paying a premium.

·In 2014, CREG enacted the “Statute for situations of scarcity in the MEM as part of the operative regulations,” which defines the rules of operation under critical supply conditions. This statute ensures the reliability of the system during crises and ensures an income at an adequate price for both the generators and the demand.

·In 2015, CREG presented the methodology to calculate firm energy for wind plants.  The new resolution allows projects without wind measurements for 10 years, to use proxy data in order to calculate the power-wind curve.  The results of the approximation must be certified by the National Operations Council. This new resolution will favor the use of new technologies whose generation costs are lower than those related to traditional technologies. Additionally, this new resolution brings benefits such as the increase of the reliability on the system and the complementarity of resources. In addition, it ensures an efficient price of energy for demand and gives flexibility to the system, which allows to better face periods of low hydrology.

·In 2015, CREG declared through Resolution 177 that existing firm energy was enough to supply the expected demand until 2019.  Auctions for an expansion process was therefore not required and the CREG instead assigned the OEF to existing plants for the periods 2016-2017, 2017-2018 and 2018-2019, signaling that the energy demand is adequately covered.

·In 2016, CREG declared through Resolution 115 that there was no need for a reliability charge auction to supply demand during 2019-2020. This situation negatively affects potential new generators since they will not receive income for reliability charge concept.

·In 2017, CREG presented a document that analyzed an anonymous and standardized contracts market, in which standard contracts will be traded and the price resulting from these transactions can be included in the regulated tariff to final customers.

·In 2017, CREG modified the scarcity price, calculating it according to the real fuel costs of local thermal plants. This regulation mitigates the risk thermal plants faced during the El Niño events in 2015-2016, in which the scarcity price did not cover all of their variable costs.

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·In 2018, CREG issued Resolution 114 which set the principles and general conditions that must be met by the mechanisms for the commercialization of electricity so that their prices are recognized in the cost component of energy purchases to the regulated customers.

·In 2018, CREG issued Resolution 064 concerning the opportunity for carrying out an auction for the allocation of firm energy obligations for the period 2022-2023.  It recommended allocation of OEF through a reliability charge auction for such period to the extent that a deficit is recorded to cover the demand, derived mainly from the uncertainty before the entrance of the Ituango project. Subsequently, a new resolution was published in order to assign OEF for the period 2022-2023 with an objective demand of 82.8 TWh/year. A deficit is expected to cover approximately 4 TWh/year. This auction will enable new projects and will favor the use of new technologies.

Gas Market

Natural gas is important for the Colombian electricity sector, as natural gas is a key fuel for generation.  The Colombian natural gas market operates under near monopolistic conditions and consists of a primary market, secondary market and short-term market. Supply contracts depend on a balance between supply and demand for the following five years, which is calculated by the regulatory authority every year.  If demand exceeds supply, auctions take place; if the opposite happens, bilateral negotiations are carried out. Transportation contracts are traded under bilateral negotiation schemes or through auctions.

This regulatory framework is the result of a former proposal that sought to reform the wholesale market for natural gas and ensure that it operates under the principles of transparency and liquidity.  This framework also outlines entities that are eligible to participate in each market, the types of permitted transactions, and the kind of contracts that may be entered into.  It seeks to create standardized force majeure provisions for such contracts in order to clarify the responsibilities of the parties.  In 2015, the gas Market Manager was chosen and started operations.  Its main responsibilities are the validation and monitoring of participant registration, the primary and secondary market supply and transport contract registration, and the implementation of long-term and short-term auctions.

During 2015, CREG presented the final scheme for supply contract indexation, which considers two methodologies: bilateral negotiation and regulated formula application. The price update of long-term natural gas contracts allows sector agents (i.e. sellers and buyers) to freely agree on the price update rule that will apply since December 1, 2015 and that should correspond to deterministic values for each of the remaining years of the term of the contract or depending on a public management index determined by an independent third party. Special provisions apply in the absence of an agreement among agents.

As a mechanism to supply thermal demand and improve the reliability of the national electricity supply, the first LNG plant located in the Caribbean started commercial operation in December 2016.  The developments in the natural gas regulatory framework during 2017 include:

(i)	adjustments to the natural gas wholesale market, the creation of new types of contracts and the respective definition of terms and conditions;
(ii)	a regulation associated with the development of natural gas transportation infrastructure and investor selection mechanisms such as calls and open season procedures to select the agents interested in participating in projects; and
(iii)	a regulation associated with the reliability and supply of natural gas, specifically regarding the development of the Pacífico regasification plant and the Buenaventura - Yumbo transportation connection.

In 2018, CREG issued a Resolution to modify the natural gas regulatory framework. This Resolution considers the need to adjust the handling of information regarding the volume of surplus and missing quantities derived from the primary market.

Regulation of Distribution Companies

Distributors (or network operators) are responsible for planning, investing, operating, and maintaining electricity networks below 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.

Distribution Tariff-Setting Process

CREG regulates distribution prices that allow distribution companies to recover costs, including operating, maintenance and capital costs under efficient operations.  Distribution charges are set by CREG for each company based on the replacement cost of the existing distribution assets, the cost of capital, as well as operational and maintenance costs that depend on the voltage level.

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The methodology for remunerating the distribution business segment was defined by CREG in 2008. The methodology is calculated by the Weighted Average Cost of Capital (WACC). In the case of National Transmission System, the methodology of the maximum income is applied at a rate equivalent to 13%. In the case of the Local Distribution System, the methodology of the Maximum Price is applied at the rate equivalent to 13.9%.

The variables that are taken into account to determine these rates are:

·risk of an industry in relation to the market where it is developed;

·inflation;

·cost of debt;

·cost of capital;

·rate of debt;

·rate associated with a risk-free asset;

·rate showing market performance;

·market risk premium; and

·income tax rate charged to agents.

CREG also defined a methodology for the calculation of distribution charges by creating an incentive scheme for administrative, operating and maintenance costs, service quality and energy losses.  A resolution with new distribution charges was issued during the first quarter of 2018.  The new charges will not be applicable until after the information reported by companies has been audited, which is expected to take place in 2019.

Distribution charges are set for a five-year period and are updated monthly according to the PPI, and defined for four different voltage levels, which are applied depending on the customer’s connection point as follows:

·Level 1: less than 1 kV;

·Level 2: at least 1 kV but less than 30 kV;

·Level 3: at least 30 kV but less than 57.5 kV; and

·Level 4: at least 57.5 kV but less than 220 kV.

In February 2018, CREG published Resolution 015/2018 and Resolution 016/2018.   Resolution 015/2018 establishes the final distribution remuneration methodology, providing current and future stability to Codensa’s revenues. Resolution CREG 015 is a key piece of regulation given that it respects the remuneration of the existing asset base, recognizes future investments, sets the remuneration of operation and maintenance expenses, and defines profitable paths of loss and quality of service.

Resolution 016/2018 determines the rate of return of electricity distribution on the NIS to be 12.4% before taxes for 2018 and 11.8% before taxes for the 2019-2023 period. The resolution establishes that whereas the value of income tax is modified, the rate of return determined in the resolution will be adjusted. In February 2019, CREG issued Resolution 015, which modified the rate of return.

Since 2011, CREG defined a coverage mechanism requiring traders who are the end customers, to guarantee distributors the payment of the regional transmission system and local distribution system tariffs.  CREG established that these kinds of traders must use one of the following instruments, in order to provide security of payment to distributors: bank guarantees, stand-by letters of credit letters (either domestic or international) and monthly prepayments.

At the same time, CREG defined new regulations related to non-technical losses.  It defined that the companies that have higher losses than those approved in current regulation should design a plan to reduce them.  CREG approved new criteria for losses that will be included in the tariff for companies that control losses at an efficient level and established that non-technical losses above the efficient level must be assumed by distributors.

The distribution business has tariff incentives contingent on the quality of service. Distributors also have to make compensatory payments to customers when they cannot meet the established continuity criterion.

In 2012, CREG defined the power quality regulation.  It established minimum quality standards and designed a mechanism in which customers can present their claims to distribution companies and receive compensation if standards are not met by the company.  This mechanism introduces new measurement requirements.

In January 2018, the Colombian MME established Resolution 40072 defining the policy for implementation of Advanced Metering Infrastructure (AMI), aiming to implement AMI for 95% of urban consumers and 50% of rural consumers before 2030.

Sales by Distribution Companies to Regulated Customers

The regulated market is served by traders and by distributors acting as traders, who bill all service costs, according to prices regulated by CREG.  The scheme allows distributors to pass through the average purchase price of all the market transactions that affect the regulated market into the customer’s tariff, thereby mitigating spot price volatility and providing an efficiency signal to the

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market.  Additionally, CREG established a formula for the total cost of service, which transfers transmission, distribution, marketing costs, and physical losses costs to the regulated market.

Regulation of Transmission Companies

Transmission companies which operate at least 220 kV grids constitute the National Transmission System (“NTS”).  They are required to provide access to third parties on equal conditions and are authorized to collect a tariff for their services.  The transmission tariff includes a connection charge that covers the cost of operating the facilities, and a usage charge, which applies only to traders.

CREG guarantees an annual fixed income to transmission companies.  Income is determined by the new replacement value of the network and equipment and by the resulting value of the bidding processes of awarding new projects for the expansion of the NTS.  This value is allocated among the traders of the NTS in proportion to their energy demand.

In 2012, CREG established the new quality of service regulation for the NTS.  It defined incentives to reduce failure to provide energy and required companies to compensate customers, by reducing their charges, for service interruptions in the NTS.

The expansion of the NTS is conducted according to model expansion plans designed by the Colombian Mining and Energy Planning Agency and pursuant to bidding processes opened to existing and new transmission companies, which are handled by the MME in accordance with the guidelines set by CREG.  The construction, operation and, maintenance of new projects is awarded to the company that offers the lowest present value of future cash flows needed for carrying out the project.

Trading Regulation

The retail market is divided into regulated and unregulated customers.  Customers in the unregulated market may freely and directly enter into electricity supply contracts with a generator or a distributor, acting as traders, or with a pure trader.  The unregulated customer, which represented about 31% of the market in 2018, consists of customers with a peak demand in excess of 0.1 MW or a minimum monthly energy consumption of 55 MWh.

Trading involves reselling the electricity purchased in the wholesale market.  It may be conducted by generators, distributors or independent agents, which comply with certain requirements.  Parties freely agree upon trading prices for unregulated customers.

Trading on behalf of regulated customers is subject to the “regulated freedom regime” under which tariffs are set by each trader using a combination of general cost formulas given by CREG and individual trading costs approved by CREG for each trader. Since CREG approves limits on costs, traders in the regulated market may set lower tariffs for economic reasons.  Tariffs include, among other things, energy procurement costs, transmission charges, distribution charges and a trading margin.

Since 2015, the tariff formula considers a fixed monthly charge covering operating cost plus a variable income for traders covering credit risk, working capital subsidies, and other selling costs.

Derivex was created in 2010 in order to incorporate an energy derivatives market. Its main purpose is to administrate an operations trading system on derivative financial instruments that are the quality of value in the terms of Law. The underlying assets are electricity, fuel gas and any other energy commodities. Derivex records the operations on these instruments.

Tariffs to End Customers

The energy trader is responsible for charging the electricity costs to end customers and for transferring their payments to the industry’s agents.  The tariffs applied to regulated customers are calculated according to a formula established by CREG.  This formula reflects the costs of the industry (generation, transmission, distribution), depending on the customer’s connection level, trading losses, constraints, administrative costs, and market operating costs.  The pricing formula is currently under review and CREG Resolution 240B/2015 establishes the basis of the studies to determine the unit cost formula of providing service to regulated customers.  It is expected that the commission will issue the formula during 2019. There are different factors that affect the final costs of the service.  Subsidies and/or contributions are applied according to the socio-economic level of each customer, and when subsidies exceed contributions, the Colombian government compensates for the difference.  Another factor that affects the final tariff is the distribution area, which establishes a single distribution tariff for the distribution companies in adjacent geographic zones.

In addition, to subsidize the value of electricity for the most financially vulnerable residential customers residing in the least developed rural areas, the MME established the Social Energy Fund (“FOES” in its Spanish acronym). FOES offsets CP$ 46 kWh of the price of electricity for the above mentioned customers.

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Law 1,873/2017 determined energy and gas subsidies for low-income customers whose consumption does not exceed 150% of the basic subsistence consumption level.

Penalties

In the case of the transmission sector, CREG established the new quality of service regulation for the regional transmission systems.  Specifically, it defined compensations for energy that was not provided and service interruptions in the regional transmission systems.

Renewable Energy and Energy Efficiency

Since 2001, energy efficiency has been promoted in Colombia, through Law 697, which has been the framework for efficiency programs including the program for rational and efficient use of energy.  On May 13, 2014, the Renewable Energy Law (Law 1,715) was enacted.  This new law establishes a general legal framework and created a fund intended to promote the development of NCRE, 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, in order to reduce energy costs and greenhouse gas emissions.

In 2016, MADS published Resolution 1,283, which establishes the procedure and requirements applicable to new investments in NCRE and energy efficiency plans, in order to obtain tax benefits.  Similarly, MADS published Resolution 1,312 adopting the Terms of Reference for the elaboration of Environmental Impact Assessments required to obtain the respective license for onshore wind projects.

During 2017, the MME issued Decree 1,543 to regulate NCRE and the Efficient Energy Management Fund (“FENOGE” in its Spanish acronym) to promote and create the incentives for the development of projects in these areas to be managed by a fiduciary trust.  An Operations Manual of FENOGE was also issued through MME Resolution 41407.  Such document contains information regarding financial sources, allocation of resources, organizational structure, and project selection and execution methodologies.

In 2018, Decree 570 of 2018 was enacted and it is related to the public policy guidelines for the long-term contracting of power generation projects, with the main purpose to focus on the following:

·Need to supply domestic demand;

·Ensure an efficient, safe and reliable operation in the sector’s activities;

·Incorporation of advances in science and technology;

·Diversification of the Colombian electric power generation mix due to the high degree of concentration of hydro power generation;

·Support the compliance of the commitments acquired by Colombia regarding to the reduction of its greenhouse gas emissions by 20% with respect to the projected emissions for the year 2030 in the Business as Usual scenario; and,

·The complementary relationship between non-conventional sources of renewable energy such as wind, solar and biomass with conventional hydroelectric resources, especially during seasonal and interannual periods of low hydrology.

MME also issued Resolution 40971 to regulate the long-term mechanism in compliance with Decree 570 and Resolution 40975 to announce the first auction, to be launch by the Colombian Mining and Energy Planning Unit, and to detail the main conditions of the tender.

Environmental Regulation

Any entity planning to develop projects or activities relating to generation, interconnection, transmission or distribution of electricity that may result in environmental deterioration must first obtain environmental permits (emissions, dumping, exploitation and collections, among others) and licenses and also establish environmental management plans, as established in Decree 1076 of 2015.  Depending on the nature of the projects, licenses are conferred by ANLA (National Authority of Environmental Licenses), Regional Autonomous Corporations, Municipalities, districts and metropolitan areas whose urban population is greater than one million (1,000,000) inhabitants.   For the licensing process, studies of environmental diagnosis of alternatives (DAA) and environmental impact studies must be submitted to the relevant environmental authority according to Terms of Reference established by the authorities. These studies are subject to the issuance of technical concepts by the competent environmental authorities.

Additionally, any project that requires an environmental license and that involves the use of 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.

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All hydro generation plants with an installed capacity higher than 10 MW in its operation stage are required to contribute to the conservation of the environment. These resources are called “Transfers” and consist of a payment by each of these plants of 6% of their annual production at a rate established by CREG, of which half goes to the municipalities where the project is located and the other half to the Regional Autonomous Corporation to fund hydro basin recovery plans and páramo ecosystems where water comes from.  In the case of thermal generation, “Transfers” represent 4% of their annual production, of which 1.5% goes to municipalities where the project is located and 2.5% goes to Regional Autonomous Corporations to protect the environment of the area where the plant is located.

MADS continues to develop regulation to reduce natural resources contamination and depletion caused by contaminant discharges to natural environments.  It has updated parameters and limits of specific maximum allowable discharges to surface water and public sewer systems. With regard to water, since 2017 MADS has been developing a methodology to estimate the environmental flow (which, in addition to sustaining aquatic ecosystems consider the subsistence and well-being of the people who depend on such ecosystems) in Colombian rivers, which seeks to calculate the available water supply in basins.

MADS is also concerned with climate change issues.  In 2015, it committed to reducing greenhouse gas emissions in Colombia by 20% by 2030 (compared to the 2010 baseline), and subject to the provision of international support, Colombia could increase that goal from 20% to 30% by 2030.  In 2018, the National Law of Climate Change (Law 1931) was declared, which guides the decisions of public and private entities, territorial entities and environmental authorities of the country for climate change management.

Peruvian Electricity Regulatory Framework

Industry Overview and Structure

In the Peruvian Wholesale Electricity Market (“Peruvian MEM” in its Spanish acronym) there are four categories of local agents: generators, transmitters, distributors and large customers. Trading is carried out by generators and distributors.

The 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.

i)Generators:

The generation segment is comprised of companies that own electricity generation power plants.  This segment is a competitive market in which prices tend to reflect the marginal cost of production.  Electricity generators, as energy producers, have capacity and electricity sale commitments with their contracted customers.  Generators may sell their capacity and electricity to both distributors and unregulated customers.

The electricity received by a generator’s customers does not necessarily match the electricity produced by that generator since power plant production is allocated by the COES, the Peruvian entity in charge of coordinating the efficient operation and centralized dispatch of generation units to satisfy demand.  The variable production costs of each power plant are considered for the spot price calculation, regardless of their contractual commitments.  The only exception to this rule applies to natural gas plants.  For dispatch purposes, natural gas prices are established once a year in June, and apply from July through June of the following year.  In 2017, the mechanism was modified to include a minimum natural gas price according to natural gas contracts and plant parameters, such as fuel consumption and effective power capacity.  The spot market is managed by the COES, where an economic balance is reached between the electricity produced by a generator and the demand from the generators’ customers.  The participants authorized to trade in the spot market are generators to meet their supply contracts, distributors to serve their unregulated clients for up to 10% of the maximum demand, and large clients for up to 10% of their maximum demand.

The generation plants’ electricity production and the customers’ energy consumption are valued at an hourly marginal cost.  Generators that have deficits buy energy from the generators that have surpluses.  This principle regarding energy sales balances also applies to capacity charges.  Osinergmin, the Peruvian regulatory electricity authority, regulates the capacity price.

Since October 1, 2017, the spot price is obtained from the real dispatch model. The settlements made by the COES also include payments and/or collections for ancillary services such as frequency and voltage regulation.  They also consider compensation for operating cost overruns, such as the operation at minimum load, random operational tests, among others.

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ii)Transmitters:

The transmission system is made up of transmission lines, substations and equipment for the transmission of electricity from the power plants to the consumption centers or distribution points.  Transmission in Peru is defined as all lines or substations with a voltage higher than 60 kV.  Some generation and distribution companies also operate sub-transmission systems at the transmission level.

iii)Distributors:

Electricity distribution is an activity carried out in the concession areas granted to different distribution companies.   Distributors buy energy through tender processes under regulated prices or directly from generators under freely negotiated terms and they sell energy mainly to residential and large customers.

iv)Large Customers:

Customers with a capacity demand lower than 200 kW are considered regulated customers, and their energy supply is considered a public service.  Customers whose capacity demand is within the range of 200 - 2,500 kW are free to choose whether to be considered regulated or unregulated customers.  Once this type of customer chooses an option, the customer must remain in that category for at least three years.  If customers want to change their category from regulated to unregulated, or vice versa, at least one-year notice must be provided.

Principal Regulatory Authorities

The Peruvian Ministry of Energy and Mining (“MINEM” in its Spanish acronym) defines energy policies applicable nationwide, 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.

The General Electricity Authority of the MINEM is the technical regulatory entity responsible for evaluating the electricity sector, and proposes the necessary regulations for the development of the electricity generation, transmission and distribution activities.

The Peruvian Investment Promotion Agency is a public entity responsible for attracting private investment in public utilities and infrastructure works.  It also advises investors on their investment decisions.

Osinergmin is an autonomous public regulatory entity that controls and enforces compliance with legal and technical regulations related to electrical, hydrocarbon and mining activities, controls and enforces compliance with the obligations stated in the concession contracts and is responsible for the preservation of the environment in connection with the development of these activities. Osinergmin’s Tariff Regulatory Bureau has the authority to publish the regulated tariffs.  It also controls and supervises the bidding processes required by distribution companies to purchase energy from generators.

The COES coordinates the SEIN’s short, medium and long-term operations at minimum cost, maintaining the security of the system and optimizing energy resources.  It also plans for the SEIN’s transmission development and manages the spot market.

The Peruvian Ministry of Environment defines environmental policies applicable nationwide and is the head of the National Environmental Management System, which includes the National Environmental Impact Assessment System, the National Environmental Information System, the Protected Natural Areas System, as well as the management of natural resources in its respective area of competence, such as biodiversity and climate change, among others.

The Peruvian Electricity Law

General

The general legal framework applicable to the Peruvian electricity industry includes:

·the Electricity Concessions Law (Decree Law 25,844/1992) and its ancillary regulations;

·the Law to Secure the Efficient Development of Electricity Generation (Law 28,832) and its ancillary regulations;

·the Technical Regulation on Electricity Supply Quality (Supreme Decree 020);

·the Electricity Import and Export Regulation (Supreme Decree 049);

·the Antitrust Law for the Electricity Sector (Law 26,876);

·the law that regulates the activity of Osinergmin (Law 26,734, together with Law 27,699);

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·the Decree Law 1,002 that promotes NCRE investments; and

·Decree Law 1,221 that improves electricity distribution regulation to promote electricity access in Peru.

The regulatory framework includes:

·the separation of the three main activities, namely generation, transmission and distribution;

·freely-determined prices for the supply of energy in competitive market conditions;

·a system of regulated prices based on the principle of efficiency together with a bidding regime for sales of generators to distributors; and

·private operation of the interconnected electricity systems based on the principles of efficiency and quality of service.

Law 29,852 and Regulation 021-2012-EM created the Hydrocarbons Energy Security System and the Social Energy Inclusion Fund.  These laws also created a social compensation system and a universal service for the most economically vulnerable sectors of the population, who are subsidized by surcharges on the electricity bills of unregulated customers (equivalent to the surcharge that currently exists for regulated customers on the Electrical Social Compensation Fund), transportation surcharges for hydrocarbon-derivate liquids and natural gas multi pipelines and surcharges on the use of the natural gas pipeline.

Osinergmin and distribution companies manage the Social Energy Inclusion Fund, which directs funds to the widespread use of natural gas by vulnerable sectors, develops new energy sources like photovoltaic cells, solar panels, etc., and supplies liquefied petroleum gas to economically vulnerable sectors.

Law 29,969 provides for the universal use of natural gas. State electricity distributors are authorized to carry out natural gas programs, including the distribution of natural gas in their concession area. They are also able to associate with companies specializing in the development of gas distribution projects.  The MINEM promotes private investment by granting gas distribution concessions through the pipeline network.

Law 29,970 guarantees energy security and promotes the development of the petro chemical complex in the southern region of the country and the participation of state-owned companies in those projects.  Within the framework of this law, the following have been declared matters of national interest: (i) the guarantee of energy security; (ii) the transportation of ethane to southern Peru; and (iii) the construction of regional pipelines in Huancavelica, Junín, and Ayacucho and their connection to existing gas pipelines. This law creates a subsidy mechanism to finance natural gas infrastructure (including transportation, storage, and backup) and natural gas fueled electricity generation.

Law 1,221, in force since 2016, establishes the following main modifications:

·In the distribution tariffs, the VAD and the internal rate of return (IRR) calculations are defined for each distribution company with over 50,000 customers.

·The MINEM defines a technical responsibility area (“ZRT” in its Spanish acronym) for each distributor, given its operational areas with the possibility to extend its concession areas by adding nearby rural areas, whose works can be financed by the Peruvian government.  The investments in the ZRT, which can be carried out either by a distributor or by a third party, should be approved by the distributor.  Investment and audited costs (with a cap) will be recognized through the VAD.

·The VAD includes a technology innovation charge and/or a distribution energy efficiency component. The VAD is adjusted to encourage service quality improvements.  This charge is equivalent to a maximum percentage of a distributor´s annual revenue.

·Distributors are obligated to guarantee their regulated demand for 24 months.

·Distributors are required to execute the urban electrification investments or repay the contribution, if the investment is carried out by a third party, when the rate of occupancy is over 40%.

·Generation and transmission concessions originating in bidding processes are restricted to a 30-year term.  In the case of hydroelectric generation concessions, a favorable report for the watershed, as issued by the MINEM, is required.

·Set conditions to NCRE sources and co-generation that enable them to inject surplus energy to the distribution system without affecting operating security.

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Limits and Restrictions

Since the enactment of the Electricity Concessions Law, vertical integration is restricted, and activities in the generation, transmission and distribution segments must be developed by different companies.  The Antitrust Law for the Electricity Sector regulates the cases in which vertical and horizontal integration is admissible.

An antitrust authorization is compulsory for those electricity companies that hold more than a 5% interest of another business segment, either before or as a result of a merger or integration.  An authorization is also required for the horizontal integration of generation, transmission and distribution activities which result in a market share of 15% or higher of any business segment, either before or as a result of any operation.  Such authorizations are granted by the Institute for Defense of the Consumer and Intellectual Property, based on the market share information provided by Osinergmin.

Regulatory Charges

In addition to taxes applicable to all industries (mainly an income tax and a value added tax), the electricity industry operators are subject to a special regulated contribution that finances the costs incurred by the regulator related to regulation, supervision and monitoring of the electricity industry.  The applicable rate is up to 1% of the annual billing of each company and the collected funds are distributed proportionally between the MINEM and Osinergmin.

Regulation of Generation Companies

Concessions

Generation companies that own or operate a power plant with an installed capacity greater than 500 kW require a concession granted by the MINEM.  A concession for electricity generation activity is a unilateral permit granted to the generator.  Authorizations are granted for an unlimited period of time, although their termination is subject to the same considerations and requirements as the termination of concessions under the procedures set forth in the Electricity Concessions Law, and its related regulations.

To be granted a concession, the applicant must first request a temporary two-year concession and must subsequently apply for a long term concession. To receive an authorization, the applicant must file a petition before the MINEM.  If the petition is admitted and no opposition is presented, the MINEM grants the authorization to develop generation activities for an unlimited time, subject to compliance with applicable regulations.

Dispatch and Pricing

The coordination of electricity dispatch operations, the setting of spot prices and the control and management of economic transactions that take place in the SEIN are controlled by the COES.  Generators can sell energy to large customers and buy the deficit or transfer the surplus between contracted energy and actual production in the pool market at the spot price

Sales by Generation Companies to Unregulated Customers

Sales to unregulated customers are carried out at mutually agreed prices and conditions, which include tolls and compensation to transmission companies for the use of their transmission systems and, if necessary, to distribution companies for the use of their network.

Sales by Generation Companies to Distribution Companies and Certain Regulated Customers

Sales to distributors can be governed by:

·Bilateral contracts at a price no greater than the regulated price in the case of regulated customers (calculated as the weighted average of prices under contracts resulting from tenders and prices under contracts not resulting from tender processes), or at an agreed price in the case of unregulated customers.

·A tender process, allowed under Law 28,832; the purpose of this provision is to establish a mechanism that promotes investments in new generation capacity through long-term electricity supply contracts and firm prices with distribution companies.

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Sales of Capacity by Generation Companies to Other Generation Companies

COES determines a firm capacity for each power plant on an annual basis.  Firm capacity is the highest capacity that a generator may supply to the system at certain peak hours, taking into consideration statistical information and accounting for time out of service for maintenance purposes and for extremely dry conditions in the case of hydroelectric plants.

Depending on the relationship between the firm capacity and the contractual requirements of a generation company, the generation company may be required to purchase or sell capacity in the spot market.

Regulatory Charges

Generators that own hydroelectric plants, also pay a water royalty based on the hydroelectric energy produced and the regulated energy tariff at peak hours.

Tenders Promoted by the State

Since 2009, the MINEM has recommended the construction of new electricity plants that would serve as backup to guarantee the flow of electricity to the system, avoiding blackouts.  As a result, the Peruvian Investment Promotion Agency (“PROINVERSION”) carried out a public bid in August 2010, seeking to secure investments for three projects located in Reserva Fría de Talara, Trujillo and Ilo that would add another 800 MW to the system.  The bid resulted in two of the projects being awarded, Reserva Fría de Talara (200 MW, for Enel Generation Piura, our subsidiary) and Ilo (400 MW, for Enersur, an unrelated company). These plants receive regular payments for being permanently available to operate and provide energy to the SEIN whenever the COES calls on them and will also be reimbursed for the fuel costs incurred for generating electricity.  The Trujillo generation facility was later replaced by the Eten generation facility and awarded to Planta de Reserva Fría de Generación de Eten S.A. (200 MW).

Electricity Exports and Imports

A 220 kV transmission line has been implemented for the interconnection with Ecuador.  However, the line has not operated continuously due to regulatory issues.  In 2018, the net electricity exports to Ecuador amounted to 21.2 GWh.  Internal regulations were also approved for the application of CAN Decision 757, which establishes that when bilateral electricity transactions are carried out with other Andean Nation Community countries, the Economic Operation Committee of the SEIN should send weekly reports to the MINEM and to Osinergmin demonstrating that priority has been given to supplying the domestic market (Supreme Decree 011-2012-EM).

The governments of Peru and Chile have established a bilateral working group to discuss energy matters.  The purpose of the working group is to identify and take advantage of the potential synergies between the two countries.  At the request of the presidents of both nations, the working group is expected to propose a framework for an agreement related to the electricity integration of both countries and to establish the general rules for electricity exchanges among them.  As of the date of this Report, both countries have conducted negotiations, but a final agreement is still pending.

Regulation of Distribution Companies

Bids for Supplying Regulated Customers

The Law to Secure the Efficient Development of Electricity Generation established a bidding regime for the acquisition of energy and capacity by distributors through competitive tenders and firm prices. The regulator approves the general conditions and establishes a price cap for the bidding process.  In addition, distributors can sign bilateral short-term contracts with generators to buy electricity blocks not covered by tenders and to fill any future imbalance.

The new contracts to sell energy to distribution companies for resale to regulated customers must be made at fixed prices determined by public bids.  Only a small part of the electricity purchased by distribution companies (included in old contracts) is still maintained at node prices.  These node prices are set annually by Osinergmin and are the maximum prices for electricity purchased by distribution companies that can be transferred to regulated customers in those contracts.

Distribution Tariffs to End Customers

The tariff applicable to regulated customers includes charges for capacity and electricity for generation and transmission and for the VAD which considers a regulated return on investments, operating and maintenance fixed charges and a standard percent for energy distribution losses.

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Distribution Tariff-Setting Process

The VAD is set every four years and for every distribution company with 50,000 or more customers.  The tariff revision for private distribution companies was in November 2018.

Actual return on investment for a distribution company depends on its performance relative to the standards chosen by the 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.  Tariff studies are performed by the distribution companies.  Preliminary tariffs are tested to ensure that they provide an average annual internal rate of return (IRR) between 8%-16% on the replacement cost of electricity-related distribution assets.

Incentives and Penalties

Law 28,832 and Supreme Decree 052-2007-EM (“General Regulations of the Supply Auctions”) state that if auctions are called for over three years in advance, distributors will receive payment incentives which will be added to the generator’s auction price, and then passed through to customers.  This incentive cannot be higher than 3% of the tariffs applied.

The distribution concessionaire may lose its concession if it does not provide evidence of a guaranteed supply for at least the following 24 months, unless it has called for public auctions according to the current norm and has not received offers sufficient to comply with its total requirements for the established period.

Supreme Decree No. 018-2016-EM amends the Regulations of the Electricity Concessions Law to include the use of company-owned intelligent meters, the respective investment and O&M expenses of intelligent meters in the VAD, and the technological innovation projects in the VAD to be covered by a capacity charge, and to disclose a ZRT proposal.

Regulation in Transmission

Transmission activities are divided in two categories, “principal,” which are for common use and allow the flow of electricity through the national grid, and “secondary,” which are those lines that connect a power plant with the national grid that connects principal transmission with the distribution network, or that connect directly to certain end customers.  Law 28,832 also defined “guaranteed transmission systems” and “supplementary transmission systems,” applicable to projects commissioned after the enactment of that law.  Guaranteed system lines are the result of a public bid and supplementary system lines are freely constructed and exploited as private projects.  Principal and guaranteed system lines are open to all generators and allow electricity to be delivered to all customers. Transmission concessionaires receive an annual fixed income, as well as variable tariff revenues and connection tolls per kW.  The secondary and supplementary system lines are open to all generators but are used to serve only certain customers who must pay for using the system.

Environmental Regulation

The environmental legal framework applicable to energy related activities in Peru is established in the Environmental Law, Law 28,611, and in the Regulation for Environmental Protection regarding Electricity Activities, Supreme Decree 029-94-EM.

The MINEM dictates the specific environmental legal dispositions applicable to electricity activities, and Osinergmin is in charge of supervising certain aspects of their application and implementation.  According to the Environmental Law, the Peruvian Ministry of Environment has the principal duties of: (i) designing the general environmental policies applicable to every productive activity; and (ii) establishing the main guidelines of the different government authorities for their specific environmental sector regulations.  Currently, the Peruvian Ministry of the Environment is the responsible of the supervision functions regarding the application and implementation of the Environmental Law’s dispositions.

NCRE sources, referred to in Peruvian regulations as Renewable Energy Resources, for electricity generation are considered to originate from the following power sources: biomass, wind, solar, geothermal and tidal sources, as well as hydroelectric plants with an installed capacity lower than 20 MW.

In 2008, Decree Law 1,002 was issued to promote the use of NCRE. The principal investment incentives established by these regulations include:

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(i)	An objective percentage of national electricity consumption, set every five years, to be covered by NCRE generation, excluding hydroelectric plants (the percentage was 5% for the first and second five-year periods and remains unchanged);
(ii)	Tenders of energy to be covered by NCRE, in which the investor awarded the tender is guaranteed a firm price for the energy injected into the system during the supply contract period of up to 20 years. These tenders establish quotas by type of technology and limit prices; and
(iii)	Priority in the dispatch of load and access to transmission and distribution networks.

In addition, other regulations established tax incentives, including accelerated asset depreciation for income tax purposes, and the advanced recovery of the sales tax.  In 2011, the permanent congressional commission approved Law 29,764, extending these tax benefits through 2020.

Law 29,968 created the National Environmental Certification Service for Sustainable Investments (“SENACE” in its Spanish acronym), a specialized public organization with technical autonomy and incorporated as a separate legal entity, which reports to the Peruvian Ministry of the Environment.  This organization is responsible for reviewing and approving detailed environmental impact studies of public, private or mixed capital investment projects, whether national or multi-regional, that involve activities, construction and other commercial and service activities whose characteristics, importance and/or location can result in significant environmental impacts, except for those expressly excluded by a Supreme Decree with the consenting vote of the Council of Ministers.

SENACE seeks to implement a single system of environmental administrative procedures to guarantee sustainable investments through the implementation of a sole process for environmental certification.

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C.Organizational Structure.

Principal Subsidiaries and Affiliates

We are part of an electricity group controlled by Enel, an Italian company and our ultimate controlling shareholder, which beneficially owned 51.8% of our shares as of December 31, 2018, and owns a beneficial interest of 56.4% as of the date of this Report, after making additional purchases in 2019. Enel is an energy company with multinational operations in the power and gas markets, with a focus on Europe and Latin America. Enel operates in 34 countries across five continents, produces energy through a managed installed capacity of almost 90 GW, which includes 43 GW of renewable sources, and distributes electricity and gas through a network covering 2.2 million kilometers. With over 73 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enel shares trade on the Milan Stock Exchange.

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Enel Américas Simplified Organizational Chart(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 its economic interest in such consolidated subsidiary. Please refer to “Presentation of Information” for an explanation of the calculation of economic interest.

(2)As of December 31, 2018, Enel SpA owned 51.8% Enel Américas. As of the date of this Report, Enel SpA owns a 56.4% beneficial interest in Enel Américas.

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The companies listed in the following table swere consolidated by us as of December 31, 2018.  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	% EconomicOwnership ofEnel Américas	ConsolidatedAssets of EachMain Subsidiary	Revenues and Other Operating Income of EachMain Subsidiary
	(in %)	(in billions of US$)
Electricity Generation and Transmission
Electricity Generation
Dock Sud (Argentina)(1)	40.2	320	95
Enel Generation El Chocón (Argentina)	65.7	466	67
Costanera (Argentina)	75.6	401	163
Fortaleza (Brazil)	100	330	212
Cachoeira Dourada (Brazil)	99.8	405	540
EGP Volta Grande (Brazil)	100	450	82
Emgesa (Colombia)	48.5	2,855	1,260
Enel Generation Peru (Peru) (2)	83.6	1,391	708
Enel Generation Piura (Peru)	96.5	260	89
Electricity Transmission
Cien (Brazil)	100	304	83
Electricity Distribution
Edesur (Argentina)	72.1	1,694	1,190
Enel Distribution Rio (Brazil)	99.7	2,576	1,511
Enel Distribution Ceara (Brazil)	74.1	1,748	1,411
Enel Distribution Goias (Brazil)	99.9	3,174	1,542
Enel Distribution Sao Paulo (Brazil)	95.9	5,962	2,459
Codensa (Colombia)	48.3	2,102	1,714
Enel Distribution Peru (Peru)	83.2	1,323	913

(1)We own 57.1% of Inversora Dock Sud S.A., an investment vehicle through which we hold Dock Sud.

(2)The Consolidated Assets and the Revenues and Other Operating Income of Enel Generation Peru include Chinango.

Generation and Transmission Segment

The following companies include generation and transmission companies consolidated by us as of December 31, 2018.

Costanera (Argentina)

Costanera is a publicly-held Argentine electricity generation company, with 2,210 MW of installed capacity in Buenos Aires.  Costanera consists of six steam turbines with an aggregate capacity of 1,062 MW, which burn oil and gas, and two natural gas combined-cycle facilities with a total capacity of 1,148 MW.  Costanera was acquired from the Argentine government after the privatization of Servicios Eléctricos del Gran Buenos Aires S.A. in 1992.  We own a 75.6% economic interest in Costanera.

Dock Sud (Argentina)

Dock Sud owns and operates an 846 MW generation facility consisting of two plants.  Dock Sud’s power station has four gas turbines and one steam turbine.  Two of the gas turbines and the steam turbine comprise a combined-cycle power plant. We own 57.1% of Inversora Dock Sud S.A., an investment vehicle through which we hold Dock Sud.  Our economic interest in Dock Sud is 40.3%.

Enel Generation El Chocón (Argentina)

Enel Generation El Chocón is an Argentine electricity generation company.  It has two hydroelectric power stations with an aggregate installed capacity of 1,328 MW located between Neuquén and Río Negro provinces, in the Comahue Basin in southern Argentina.  A 30-year concession, which expires in 2023, was granted by the Argentine government to our subsidiary, Hidroinvest S.A., which bought 59.0% of Enel Generation El Chocón’s shares in July 1993 during the privatization process.  Enel Generation El

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Chocón also has four diesel engines with a total installed capacity of 34 MW, which began commercial operations in 2016. These engines are located in and operated by our Costanera thermal plant (due to an agreement between both companies).  We acquired the company in 1993 and currently own a 65.7% economic interest in Enel Generation El Chocón.

Cachoeira Dourada (Brazil)

Cachoeira Dourada owns and operates a run-of-river hydroelectric plant using the flows from the Paranaiba River, located in the state of Goias, consisting of ten generating units totaling 655 MW of installed capacity.  Cachoeira Dourada began its operations in 1997, and has a concession that expires in 2027.  We have a 99.8% economic interest in Cachoeira Dourada.

Cien (Brazil)

Cien is a Brazilian transmission and trading company wholly owned by Enel Brasil.  It transmits electricity through two owned transmission lines that connect Argentina and Brazil, covering a distance of 1,006  kilometers, with a total interconnection capacity of 2,100 MW.  Cien-Line 1 has a concession that expires in 2020, and Cien-Line 2 has a concession that expires in 2022.  Cien consolidates CTM and TESA, which operate the Argentine side of the interconnection line with Brazil.  We wholly owned Cien.

EGP Volta Grande (Brazil)

EGP Volta Grande is a generation company that owns the concession to operate the 380 MW Volta Grande hydroelectric power plant located between the states of Minas Gerais and Sao Paulo. We wholly own EGP Volta Grande through Enel Brasil.

Enel Brasil (Brazil)

In 2005, Enel Brasil was formed in order to manage all Brazilian generation, transmission and distribution assets that Enel owned jointly with us.  Enel Brasil consolidates operations of three generation companies, Cachoeira Dourada, Fortaleza and EGP Volta Grande, and a transmission company, Cien, as well as four distribution companies, Enel Distribution Sao Paulo, Enel Distribution Rio, Enel Distribution Ceara, and Enel Distribution Goias.

Fortaleza (Brazil)

Fortaleza owns and operates a 319 MW natural gas combined-cycle power plant, with a capacity to generate one-third of the electricity requirements of the state of Ceará, with a population of almost 9 million people.  Fortaleza has a concession that expires in 2031. Fortaleza is wholly owned by Enel Brasil, and we hold a 100% economic interest in Fortaleza.

Emgesa (Colombia)

Emgesa has an installed capacity of 3,499 MW, of which 87% is from hydroelectric power plants and 13% is from thermoelectric power plants.  Empresa de Energía de Bogotá S.A. directly holds a 51.5% equity interest in Emgesa.  We own 48.5% of Emgesa’s shares, which represents 56.4% of the voting rights in Emgesa.  As a result of our ownership in Emgesa and pursuant to a shareholders’ agreement, we appoint the majority of the Board members and, therefore, control Emgesa.  For more information, see “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.”

Enel Generation Peru (Peru)

Enel Generation Peru (formerly known as Edegel), an electricity generation company, owns and operates seven hydroelectric plants, two of which are owned and operated by Chinango, Enel Generation Peru’s subsidiary, and two thermal plants, with a consolidated installed capacity of 1,985 MW.  We hold an economic interest of 83.6% in Enel Generation Peru.

Enel Generation Piura (Peru)

Enel Generation Piura has 337 MW of generation capacity, consisting of three thermal plants, Malacas, Malacas II, Malacas III,  which are located in the province of Talara-Piura and operate using locally produced natural gas and diesel.  We beneficially own 96.5% of Enel Generation Piura.

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Distribution Segment

The following companies include distribution companies consolidated by us as of December 31, 2018.

Edesur (Argentina)

Edesur is one of the largest electricity distribution companies in Argentina in terms of energy purchases.  Edesur operates in a concession area of 3,309 square kilometers in the south-central part of the Buenos Aires metropolitan area, serving approximately 2.5 million customers under a concession that expires in 2087.  Our economic interest in Edesur is 72.1%.

Enel Distribution Ceara (Brazil)

Enel Distribution Ceara (formerly known as Coelce) is the sole electricity distributor of the state of Ceará, located in northeastern Brazil, and serves over four million customers within a concession area of 148,921 square kilometers.  Enel Distribution Ceara has a concession that expires in 2028. Our economic interest in Enel Distribution Ceara is 74.1%.

Enel Distribution Goias (Brazil)

Enel Distribution Goias distributes electricity in the state of Goias, located in the center-west of Brazil and serves  three million customers within a concession area of 377 thousand square kilometers. The company was acquired from the Brazilian government as part of its privatization program. Enel Distribución Goias was founded in 1956 and has a concession that expires in 2045.  We wholly own Enel Distribution Goias.

Enel Distribution Rio (Brazil)

Enel Distribution Rio (formerly known as Ampla) is the second largest electricity distribution company in the state of Rio de Janeiro, Brazil, in terms of the number of customers and annual energy sales.  Enel Distribution Rio is mainly engaged in the distribution of electricity to 66 municipalities located in the state of Rio de Janeiro, and serves over three million customers in a concession area of 32,615 square kilometers.  Enel Distribution Rio has a concession that expires in 2026.  We have a 99.7% economic interest in Enel Distribution Rio.

Enel Distribution Sao Paulo (Brazil)

Enel Distribution Sao Paulo (formerly known as Eletropaulo) is a distribution company located in the state of Saỡ Paulo, with a concession area of 4,526 square kilometers centered around the state capital. It covers the largest metropolitan area of the most developed and industrialized state in Brazil, including 24 municipalities, 7.2 million clients and 43 TWh of energy distributed. Enel Brasil has a 95.9% ownership interest in Enel Distribution Sao Paulo and our economic interest is 95.9%.  We acquired control of Enel Distribution Sao Paulo in June 2018.

Codensa (Colombia)

Codensa is a Colombian electricity distribution company that serves a concession area of 26,093 square kilometers in Bogotá, Cundinamarca and 13 other municipalities in the departments of Meta, Tolima, Caldas and Boyacá, serving approximately 3.4 million customers.  Our economic interest in Codensa is 48.3%, which represents 57.2% of the voting rights in Codensa, and as a result of this and pursuant to a shareholders’ agreement we appoint the majority of Codensa’s Board members, and therefore, have control over Codensa.  For more information regarding the control and consolidation of Codensa, see “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.”

Enel Distribution Peru (Peru)

Enel Distribution Peru, a Peruvian electricity distribution company, operates in a concession area of 1,550 square kilometers.  It has an exclusive concession to distribute electricity in the northern Lima metropolitan area, as well as some provinces in the Lima region, including Huaral, Huaura, Barranca and Oyón, and the adjacent province of Callao.  As of December 31, 2018, Enel Distribution Peru distributed electricity to approximately 1.4 million customers.  We hold a 83.2% economic interest in Enel Distribution Peru.

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D.Property, Plants and Equipment.

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

Property, Plant and Equipment of Generating Companies

Property, plant and equipment consolidates the electricity generation power plants owned by our generation subsidiaries Costanera, El Chocón and Dock Sud in Argentina, Cachoeira Dourada, EGP Volta Grande and Fortaleza in Brazil, Emgesa in Colombia, and Enel Generation Piura, Enel Generation Peru, and its subsidiary, Chinango, in Peru.  As of December 2018, through these subsidiaries, we own a total 35 power plants in South America, including four mini hydro plants in Colombia (totaling 110 MW), reaching a total 11,257 MW of installed capacity.

The following table identifies the power plants that we own, at the end of each year, by country and their basic characteristics:

			Installed Capacity(1)As of December 31,
Country/Company	Power Plant Name	Power Plant Type(2)	2018	2017	2016
				(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		2,210	2,210	2,210
El Chocón
	Chocón	Reservoir	1,200	1,200	1,200
	Arroyito	Run-of-the-river	128	128	128
	Costanera DE	Diesel Engines (Diesel Oil + Fuel Oil)	34	34	34
	Total		1,362	1,362	1,362
Dock Sud
	Dock Sud CC	Combined Cycle/Natural Gas+Diesel Oil	775	775	775
	Dock Sud TG	Gas Turbine/Natural Gas+Diesel Oil	72	72	72
	Total		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
Fortaleza	Fortaleza	Combined Cycle/Gas	319	319	319
EGP Volta Grande	Volta Grande(3)	Run-of-the-river	380	380	—
Total capacity in Brazil			1,354	1,354	974

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			Installed Capacity(1)As of December 31,
Country/Company	Power Plant Name	Power Plant Type(2)	2018	2017	2016
				(in MW)
Colombia
Emgesa
	Guavio(4)	Reservoir	1,260	1,260	1,260
	Menor Guavio(4)	Reservoir
	Paraíso	Reservoir	276	276	276
	La Guaca	Run-of-the-river	324	324	324
	Termozipa	Steam Turbine/Coal	224	224	224
	Cartagena	Steam Turbine/ Natural Gas	184	187	187
	Minor plants(5)	Run-of-the-river	110	75	75
	Betania	Reservoir	540	540	540
	Dario Valencia	Run-of-the-river	150	150	150
	Salto II	Run-of-the-river	35	35	35
	Quimbo	Reservoir	396	396	396
Total capacity in Colombia			3,499	3,467	3,467
Peru
Enel Generation Peru
	Huinco	Reservoir	276	266	266
	Matucana	Run-of-the-river	133	137	137
	Callahuanca(6)	Run-of-the-river	83	84	84
	Moyopampa	Run-of-the-river	69	69	69
	Huampani	Run-of-the-river	31	31	31
	Santa Rosa(7)	Gas Turbine/Diesel Oil	389	414	418
	Ventanilla	Combined Cycle/Natural Gas	467	479	479
	Her1	Run-of-the-river	1
	Total		1,449	1,449	1,453
Chinango
	Yanango	Run-of-the-river	42	42	42
	Chimay	Reservoir	157	154	154
	Total		199	196	196
Enel Generation Piura	Malacas(7)(8)	Gas Turbine/Natural Gas+Diesel Oil	337	333	286
	Total		337	333	286
Total capacity in Peru			1,985	1,979	1,935
Consolidated capacity			11,257	11,219	10,974

(1)The installed capacity corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its own 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” refer to thermal power plants that use either diesel or natural gas to produce gas that moves the turbines. “Combined Cycle” refers to a thermal power plant fueled with natural gas, diesel oil, or fuel oil to generate gas that first moves a turbine and then recovers the gas from that process to generate steam to move a second turbine.

(3)The 380 MW Volta Grande hydroelectric power plant was purchased on November 30, 2017.

(4)In April 2016, the two auxiliary units started commercial operations as a separate power plant (Menor Guavio of 13 MW in total).  This plant also feeds Guavio’s auxiliary services.  In December 2016, both Guavio and Menor Guavio, together, increased capacity by 50 MW after some capacity tests.

(5)Minor plants have an aggregate capacity of 110 MW. As of December 31, 2018, Emgesa owns and operates four minor plants: Charquito (19.4 MW), El Limonar (18 MW), Laguneta (18 MW) and Tequendama (54.7 MW). Laguneta was previously reported as a separate power plant.

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(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 the catastrophic event (flooding of the facilities) that occurred on March 16, 2017. The Callahuanca hydroelectric power plant resumed full commercial operations in March 2019.

(7)The variation in the installed capacity of this power plant in 2017 was the result of tests performed by COES.

(8)Includes the installed capacity (189 MW) of the Reserva Fría de Talara power plant. On February 25, 2017, unit TG6 of the Malacas thermal plant started commercial operations with 51 MW. In addition, the variation in the installed capacity of this power plant in 2017 was the result of tests performed by COES.

A substantial portion of our generating subsidiaries’ cash flow and net income is derived from the sale of electricity produced by these electricity generation facilities. Significant damage to one or more of our main electricity generation facilities or interruption in the production of electricity, whether as a result of an earthquake, flood, volcanic activity, severe and extended droughts or any other such natural disasters, could have a material adverse effect on our operations.

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 description of distribution and transmission companies and their business are included in this “Item 4. Information on the Company.”

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	2018	2017	2016
		(in km2)		(in kilometers)
Edesur	Argentina	3,309	619	619	1,123
Enel Distribution Rio(2)	Brazil	32,615	1,990	1,999	1,990
Enel Distribution Ceara	Brazil	148,920	5,197	5,082	5,127
Enel Distribution Goias(3)	Brazil	337,002	5,936	5,748	—
Enel Distribution Sao Paulo(4)	Brazil	4,526	926	—	—
Codensa(5)	Colombia	26,093	1,012	1,011	928
Enel Distribution Peru	Peru	1,550	697	660	648
Total		554,015	16,378	15,119	9,816

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

(2)The figure was standardized to 34.5 kV, previously considered high voltage rather than medium voltage.

(3)Enel Distribution Goias was acquired by us in February 2017.

(4)Enel Distribution Sao Paulo was acquired by us in June 2018.

(5)The concession area decreased by 1,160 km compared to 2017 figures since it was recalculated.

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Power and Interconnection Substations and Transformers (1)

	Year ended December 31,
	2018			2017			2016
	Number of Substations	Number ofTransformers	Capacity(MVA)	Number ofSubstations	Number ofTransformers	Capacity(MVA)	Number ofSubstations	Number ofTransformers	Capacity(MVA)
Edesur(2)	68	185	12,478	71	180	12,526	71	184	12,504
Enel Distribution Rio (3)	136	289	5,617	135	297	5,361	117	291	5,127
Enel Distribution Ceara	118	190	3,331	114	185	3,144	113	183	3,026
Enel Distribution Goias(4)	345	466	5,434	345	465	5,399	—	—	—
Enel Distribution Sao Paulo(5)	231	463	15,422	—	—	—	—	—	—
Codensa(6)	173	435	11,295	171	434	11,231	169	414	10,433
Enel Distribution Peru	46	143	4,510	43	141	4,380	37	138	4,119
Total	1,117	2,171	58,087	879	1,702	42,041	507	1,210	35,209

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

(2)Medium voltage (mv/mv) transformers in substations will be removed and replaced by high voltage (hv/mv).

(3)2017 and 2016 figures include backup transformers that are not in operation.

(4)Enel Distribution Goias was acquired by us in February 2017.

(5)Enel Distribution Sao Paulo was acquired by us in June 2018. Number of Substations includes 69 units of hv/hv without capacity of transformation, only capacitive installation.

(6)In October 2016, Codensa merged with its subsidiaries DECSA and Cundinamarca. Codensa is the surviving company. Figures for 2016 include DECSA and Cundinamarca.

Distribution Network - Medium and Low Voltage Lines(1)

	Year ended December 31,
	2018		2017		2016
	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage
			(in Kilometers)
Edesur	8,182	17,761	8,307	17,181	8,002	17,152
Enel Distribution Rio	36,601	19,561	36,694	18,936	35,942	18,668
Enel Distribution Ceara	89,232	55,529	87,910	52,934	86,024	51,423
Enel Distribution Goias(2)	181,274	32,651	179,535	32,028	—	—
Enel Distribution Sao Paulo (3)	21,258	20,554	—	—	—	—
Codensa(4)	29,217	41,973	26,682	41,358	28,507	41,307
Enel Distribution Peru(5)	4,858	23,743	4,742	23,460	4,597	22,826
Total	370,622	211,773	343,870	185,897	163,072	151,376

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

(2)Enel Distribution Goias was acquired by us in February 2017.

(3)Enel Distribution Sao Paulo was acquired by us in June 2018.

(4)In October 2016, Codensa merged with its subsidiaries DECSA and Cundinamarca. Codensa is the surviving company. Figures for 2016 include DECSA and Cundinamarca.

(5)The low voltage network includes street lighting.

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Transformers for Distribution (1)

	Year ended December 31,
	2018		2017		2016
	Number ofTransformers	Capacity(MVA)	Number ofTransformers	Capacity(MVA)	Number ofTransformers	Capacity(MVA)
Edesur	19,126	6,466	19,218	6,355	19,814	6,280
Enel Distribution Rio	126,063	5,548	124,410	5,329	122,384	5,043
Enel Distribution Ceara	146,389	3,802	142,910	3,544	138,060	3,357
Enel Distribution Goias(2)	220,610	6,419	217,117	5,663	—	—
Enel Distribution Sao Paulo(3)	140,320	14,983	—	—	—	—
Codensa(4)	67,652	6,748	67,107	6,637	65,607	6,361
Enel Distribution Peru	11,223	1,992	11,056	1,934	10,900	1,865
Total	731,383	45,958	581,818	29,462	356,765	22,907

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

(2)Enel Distribution Goias was acquired by us in February 2017.

(3)Enel Distribution Sao Paulo was acquired by us in June 2018.

(4)In October 2016, Codensa merged with its subsidiaries DECSA and Cundinamarca. Codensa is the surviving company. Figures for 2016 include DECSA and Cundinamarca.

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 a period of 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 is approved by each company’s management, taking into account the quality of the insurance companies and the needs, conditions and risk evaluations of each facility, and is based on general corporate guidelines. All insurance policies are purchased from reputable international insurers. We continuously monitor and meet with the insurance companies in order to obtain, yearly, what is the most commercially reasonable insurance coverage.

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

Project Investments

We are continuously analyzing potential opportunities for growth in the countries in which we participate.

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 quicker, allow greater flexibility to activate or deactivate according to system needs, and are generally preferred by the community.  We are favoring renewable energy technology for our new power plant investments.  We seek opportunities, either by building new greenfield projects or by modernizing existing brownfield assets and improving (operationally and/or environmentally) performance.  The expected start-up for each project 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.  Below we list our most important projects under development; however, any decision related to

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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.

A.Projects Completed in 2018

Peru - Huampani Hydroelectric Project Expansion

Huampani is a hydroelectric power plant owned by our subsidiary Enel Generation Peru, located in Lurigancho Chosica, district of Lima, Peru.  The Hydro Energy Recovery Huampani Project consists of the expansion of the installed capacity of the power plant (currently 31 MW) through the installation of two new turbines (a total of 0.7 MW) within the discharge channel of the existing Huampani hydroelectric power plant, using its own generator and auxiliary equipment. It will be connected to the Huampani substation through a 10kV line 140 meters in length.

The environmental permit for the project, as well as the archaeological permit, or Certificate of Non-Existence of Archaeological Remains (“CIRA” in its Spanish acronym) and the Pre-operativity Study (“EPO” in its Spanish acronym) were approved in 2016.  In September 2016, the Water to Wire contract was assigned to the Consortium Kössler-GCZ and the contract became effective in November 2016.  During the first half of 2017, the engineering was completed and manufacturing of the mechanical components (streamdivers, shut off valves, flapgate and auxiliaries) were carried out.  Construction started in August 2017 and as of December 31, 2018, the project was substantially completed; however, we are making improvements meant to enhance efficiency.

The total investment estimate for the project is US$ 3.1 million, of which US$ 237,862 was incurred as of December 31, 2018.

B.Projects under Construction

Colombia - Termozipa Thermoelectric Power Plant. Best Environmental Practices and Life Extension Project

Termozipa is a coal-fired power plant owned by our subsidiary Emgesa, located about 40 km from Bogotá, Colombia, alongside a river with the same name. Currently, it consists of four units (units 2, 3, 4 and 5) with a total installed capacity of 336 MW, supplied with coal from local mines.

The environmental upgrade aims to achieve the best environmental standards for gas emissions among coal-fired power plants in Latin America by reducing the following components: Nitrogen oxide (NOx) emissions to less than 330 mg/Nm3 (milligrams per cubic meter); Sulfur dioxide (SO2) emissions to less than 400 mg/Nm3 and particulate emissions to less than 35 mg/Nm3.  The project also includes improvements to the ash extraction system and to the refrigeration water discharge system.

The project foresees improvements to the boilers, mills, turbines, generators, demi plant, water intake, medium and low voltage systems, electrostatic precipitators and ancillary systems, which will extend the power plant life an additional 15 years (or 100,000 hours) of operation. The activities will also improve the heat rate (power plant efficiency) and reduce its unavailability.

The relevant permits for performing the works were obtained in 2017 and the main progress in 2018 include:

·In January 2018, the outsourced contract for site supervision was mobilized to site and during 2018 the project team was completed.

·The DeNOx contract for reducing NOx was awarded in January 2018 to AFW Energía (Spain). The activities in 2018 focused on engineering and base line tests.

·Four dry ash extraction systems were installed under units 2, 3, 4 and 5. They started operating between July 2018 and December 2018.

·The supply for DeSOx (desulphurizer) and the fiber filter system was awarded to General Electric on June 2018.

·During 2018, the supply for the water production plant was completed.

·Revamping of existing unit 2 and 3 MV Switchgear was awarded on September 2018 to Schneider.

The works are expected to be completed by 2022. The total investment in this project is US$ 158.6 million, of which US$ 48.8 million was incurred as of December 31, 2018, mainly related to engineering and supervision; supply, construction and commissioning of dry ash extraction systems in the four units; supply of water production plant and DeSOx, DeNOx and Medium Voltage systems engineering.

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C.Projects under Development

Argentina - Costanera New Combined-Cycle Unit

Within the context of the regulatory changes implemented by the Argentine government and the series of tenders that have already been carried out and others that are expected to be carried out in the upcoming years, we are analyzing the possible installation of a new combined-cycle unit for our subsidiary Costanera.  The intention is to compete for electric power contracts through tenders offered by the Argentine Ministry of Energy and Mining.

The project would involve installing a 450 MW combined-cycle unit connected to the 220 kV and 132 kV bars of the existing Costanera substation.  The combined-cycle unit could operate either with natural gas or diesel.  Both the environmental permit and the connection pre-authorization (Stage 1) were granted during 2017.

The construction period is estimated to last 30 months depending on the technical configuration.  The estimated total investment in the project is US$ 514 million.  As of December 31, 2018, US$ 2.4 million has been accrued.

Peru - Ventanilla Battery Energy Storage System

Ventanilla is a 479 MW thermal power plant located in the Callao province, Peru.  It consists of three units, two turbines that generate with gas and the third turbine that generates with steam in a combined-cycle plant.  The project involves the installation of a 14 MW / 8 MWh battery energy storage system (BESS) in the Ventanilla power plant, connected to the 16 kV bar of one of the existing turbines, in order to provide the primary frequency regulation that will optimize operations and reduce expected penalties associated with primary frequency regulation and secondary frequency regulation costs.

The environmental permit was granted in 2017, while the connection pre-authorization by the system operator was issued during the first quarter of 2018.

The construction period is estimated to be about 12 months and is expected to be completed in 2019.  The estimated total investment in the project is US$ 8.7 million, of which none has been accrued as of December 31, 2018.

Colombia — Termozipa Battery Energy Storage System

The project involves the installation of a 7 MW/ 4MWh BESS within the Termozipa power plant perimeter, connected to the 13.8 kV bars of the four existing turbines, to provide primary frequency regulation services on behalf of the power plant units.  In this way, the power plant spinning reserve can be released and the 7 MW of additional power can be sold, optimizing overall plant revenues.

The project construction period is expected to be about 12 months, to be carried out during 2019 for a total estimated investment of US$ 5.8 million, of which none has been accrued as of December 31, 2018.

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 October 2014. The value of the assets pledged to secure this debt was US$ 7.7 million as of December 31, 2018.

Enel Generation Piura has pledged a turbine that is financed through a lease, with a purchase option once the debt is fully paid. The value of the assets pledged to secure this debt was US$ 18.4 million as of December 31, 2018.

Item 4A.                Unresolved Staff Comments

None

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Item  5.  Operating and Financial Review and Prospects

A.Operating Results.

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 “Selected Financial Data,” included in Item 3 herein. Our audited consolidated financial statements as of December 31, 2018 and 2017 and for the three years ended December 31, 2018, have been prepared in accordance with 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 and Peru. Substantially all of 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. In addition, 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.

The goal of our diversification strategy is to balance the impact of significant changes in one country with opposing changes in other countries, and with the risk profiles of our businesses within the generation and transmission business and distribution business, in order to mitigate adverse impacts that may affect our consolidated operating results. The impact of these factors on us, for the years covered by this Report, is discussed below.

We directly hold 48.5% and 48.3% of the equity interests and 56.4% and 57.1% of the voting shares of Emgesa and Codensa respectively. We exercise control over Emgesa and Codensa through shareholder agreements with Empresa de Energía de Bogotá S.A., which owns the remaining equity interests of both entities. We have the right to appoint the majority of Emgesa’s and Codensa’s Board members and, therefore, we consolidate Emgesa and Codensa in our consolidated financial statements.

On February 14, 2017, our subsidiary Enel Brasil acquired Enel Distribution Goias, formerly CELG Distribuição S.A., a Brazilian distribution company located in the state of Goias, for R$ 2,187 million (US$ 640 million at that time). On November 30, 2017, Enel Brasil acquired the 380 MW EGP Volta Grande hydroelectric power plant located in the State of Minas Gerais, for R$ 1,419 million (US$ 445 million at that time). To finance these transactions, we carried out capital increases in Enel Brasil.

On June 4, 2018, we completed a tender offer to acquire Enel Distribution Sao Paulo (legally known as Eletropaulo Metropolitana Eletricidade de Sao Paulo S.A.), the main distribution company in Sao Paulo, Brazil.  As of December 31, 2018, we owned 95.9% of the company.  The total investment to acquire Enel Distribution Sao Paulo was US$ 1,829 million, using the prevailing exchange rate at that time.  For further information regarding the acquisition of these three recent Brazilian companies in 2017 and 2018, please refer to “Item 4. Information on the Company — A. History and Development of the Company. — History.”  The effects of these transactions on our consolidated financial statements as of December 31, 2018 are described in Note 7.2 of the Notes to our consolidated financial statements.

a.Generation and Transmission Business

Our electricity generation and transmission business is conducted in Argentina through Costanera, El Chocón and Dock Sud, in Brazil through Cachoeira Dourada, EGP Volta Grande and Fortaleza, in Colombia through Emgesa, and in Peru through Enel Generation Peru and Enel Generation Piura. A substantial part of our generation capacity depends on the hydrological conditions prevailing in the countries in which we operate. Our net installed capacity as of December 31, 2018, 2017 and 2016 was 11,257 MW, 11,219 MW and 10,794 MW, respectively. In those years, our hydroelectric installed capacity represented 55%, 55% and 54% of our total net installed capacity, respectively. See “Item 4. Information on the Company — D. Property, Plants and Equipment.”

Our hydroelectric generation was 23,690 GWh, 22,618 GWh and 22,250 GWh in 2018, 2017 and 2016, respectively. In 2018, our hydroelectric generation increased by 4.7% when compared to 2017 due primarily to better hydrological conditions in Argentina, and to a lesser degree in Brazil and Colombia, offset by lower availability of some of our hydroelectric plants in Peru because of inferior hydrological conditions.

In the countries in which we operate, hydrological conditions can range from very wet to extremely dry. In between these two extremes, there are a wide range of possible hydrological conditions and their final effect on us may depend on the accumulated

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hydrology. For instance, a new year with drought conditions has less of an impact on us if it follows several periods of abundant rainfall instead of exacerbating a prolonged drought.  Likewise, a good hydrological year has less marginal impact if it comes after several wet years than after a prolonged drought.

In Argentina, the months that typically have the most precipitation are May through August, and the months when snow and ice melts typically occur from October through December, providing flow to the Collon Cura and Limay Rivers which feed El Chocón’s reservoir and hydroelectric plant, located in southwestern Argentina, in the Comahue region.

Brazil has several river basins, with waterfalls that are used for hydroelectric generation. Most of Brazil’s rivers are fed primarily from rainfall. Due to its tropical weather, rainfall is mostly concentrated in the summer months, from November through May, and it is lightest during the winter. These hydrological conditions prevail in southern Brazil at the Paranaiba River at the Parana basin, where our Cachoeira Dourada and EGP Volta Grande hydroelectric plants are located.

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, in the Andean region and in the center of the country, the most populated area and the center of economic activity, 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 (eastern part of the country), where our largest hydroelectric plant, Guavio (1,263 MW) is located.

Hydrological conditions in Peru also vary significantly depending on the location. The coast, which concentrates most of the population and economic activity, typically has less rainfall than the rest of the country. In the Andean mountains, rainfall is most abundant from December through March, providing flow to the basin of the Rimac River, feeding five of our seven hydroelectric plants. The jungle area also has most of its rainfall in the same period but in larger volumes, feeding the Tarma and Tulumayo River basins, where our other two hydroelectric plants are located.

For purposes of discussing the impact of hydrological conditions on our business, we generally classify our hydrological conditions into either dry or wet, although there are several other intermediate scenarios. Extreme hydrological conditions may materially affect our operating results and financial conditions. However, it is difficult to calculate the effects of hydrology on our operating income without also taking into account other factors because our operating income can only be explained by looking at a combination of factors and not individually on a stand-alone basis.

Hydrological conditions affect electricity market prices, generation costs, spot prices, tariffs and the mix of conventional hydroelectric, thermal or NCRE generation, which is constantly being defined by the market operator to minimize the operating cost of the entire system. Run-of-the-river hydroelectric and NCRE generation are almost always the least expensive generation technologies and normally 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 cost of thermal generation does not depend on hydrological conditions but instead 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 NCRE availability. Under most circumstances, abundant hydrological conditions lower spot prices while dry conditions normally increase spot prices. Spot market prices affect our results because we must purchase electricity in the spot market when our contracted energy sales are greater than our generation, and we can sell electricity in the spot market when we have electricity surpluses.

There are many other factors that 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 plants, plant locations in relation to urban demand centers, and transmission system conditions, among others.

Hydrological conditions do not have an isolated effect but need to be evaluated in conjunction with other factors to better understand the impact on our operating results.

Argentina is a controlled market, with a defined tariff or remuneration scheme and no energy and commodity trading. The scheme defines the regulated remuneration of generation companies, which provides for a compensation based on fixed and variable costs plus an additional amount for operational and maintenance costs. Market prices are unrelated to hydrological conditions or commodity prices. There is a small electricity market (around 3.9 TWh, or 3%, of total demand per year during 2018 and 2017) since 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 and our results depend mainly on the amount of electricity we generate. Hydrological conditions during 2018 were better than in 2017, but still dry. In 2018, El Chocón’s generation increased compared to 2017, primarily as a result of better hydrological conditions in the Limay River. Hydrological conditions during 2017 were better than in 2016, but were still dry, and our hydroelectric generation was lower since CAMMESA, who manages reservoirs, set higher-level reservoir requirements, so the water availability was lower. In 2016, El Chocón’s generation decreased compared to 2015 due to lower hydrological levels of the Limay River, where our plants are located, because of less accumulated precipitation during the winter months. Costanera and Dock Sud are thermal plants, and therefore their operating results depend on their own thermal generation.

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In Brazil, there is an electricity reallocation mechanism that provides financial protection against hydrological risks for hydroelectric generators. The market operator defines which hydroelectric plants generate electricity to minimize the system cost and the generators with deficits buy energy from the generators with surpluses at a defined price with a marginal operating cost set annually by ANEEL. All hydroelectric generators that participate in the Electricity Reallocation Mechanism (“MRE” in its Portuguese acronym), participate in the overall hydroelectric generation dispatched in proportion to their assured energy, regardless of their contracted sales. In 2018, Cachoeira Dourada and EGP Volta Grande’s hydroelectric generation was lower than in 2017 due to lower dispatch allowed by the ONS based on the reservoirs condition (the objective of the dispatch is the best use of the reservoirs in the country). In the case of EGP Volta Grande’s, we sell 70% of our generation through a quota system with a fixed monthly revenue and the other 30% is sold on the unregulated market through the MRE as Cachoeira Dourada. In 2018 and 2017, droughts affected all hydroelectric generators that participated in the MRE.  This increased spot prices by approximately 300 reais per MWh and led to higher thermoelectric plant dispatch.

Our participation in EGP Volta Grande as of November 2017 allowed us to partially compensate for lower Cachoeira Dourada  hydroelectric generation in 2017. In 2016, hydrological conditions were better in most of the country compared to previous years, and this was reflected in lower prices in the spot market.  Most of the hydroelectric generators were able to cover the assured energy, or maximum firm energy, which is the electricity that a hydroelectric generation plant is able to deliver on a continual basis during a year, with poor hydrological conditions for the long-term and at lower prices. Fortaleza is a thermal plant, and its results depend mainly on its thermal generation, its generation costs, energy purchase costs and its commercial policy. Fortaleza’s results for 2018 were affected by a dispute with the gas supplier, Petrobras, regarding a Gas Supply Agreement (“GSA”), following Petrobras’s suspension of gas deliveries in February 2018. Since December 11, 2018, the GSA has been in force based on a legal injunction obtained by Fortaleza. Besides the legal dispute, discussions are in place with the Brazilian government to solve the issue, as the power plant commercial scheme (PPA and GSA) is part of a governmental program.

In Colombia, hydrological conditions of the rivers that supply the Emgesa hydroelectric plants in 2018 were less favorable than in 2017 mainly as a result of lower water contributions of the Betania and Bogotá Rivers, which were below the historical average. This produced an average energy spot price during 2018 of CP$116 per KWh, approximately 9.9% higher than in 2017. In 2017, hydrological conditions were more favorable when compared to 2016, which produced an average energy spot price during 2017 of CP$106 per KWh, approximately 64% lower than in 2016. Hydrological conditions in 2016 were more favorable than in 2015, although both years were below the historical averages. The first half of 2016 and all of 2015 were influenced by El Niño phenomenon that resulted in drought conditions for the whole system and very high spot prices. However, hydrological conditions affecting our Guavio hydroelectric plant during that period were better than the historical average, and the commissioning of El Quimbo hydroelectric plant in November 2015 allowed Emgesa to compensate for lower hydroelectric generation in its other hydroelectric plants affected by the drought.

In Peru, 2018 was a normal year in hydrology in the Rímac River basin, with flows close to the historical average. In January 2018, we experienced a normal hydrology in January, shortfalls in February, and a marked improvement for the rest of the first half of the year. During the second half of the year, normal hydrological conditions prevailed, and in December, there was again a decrease in the rainfall and in the water flow. The Tarma River, where our Yanango power plant is located, presented a performance similar to that of the Rímac River, closing 2018 with a normal hydrology and even close to the range of humid hydrology. On the other hand, the Tulumayo River, where our Chimay power plant is located, had a better performance during 2018, ending the year with extremely humid conditions. During 2018, two events altered the normal operation of the electrical system. In February, there was a failure in the liquid transport pipeline that restricted the natural gas production of Camisea. By the end of July, the maintenance of the Camisea Malvinas plant had occured, which led to an increase in the spot price from US$ 8 to US$ 112 per MWh in February and from US$ 10 to US$ 127 per MWh during the 7 days of the plant maintenance. Close to 50% of the energy demand is supplied by power plants that used the Camisea natural gas and in the cases when the Camisea natural gas is not available, the energy demand is supplied by diesel power plants, which are more expensive.

During the first half of 2017, hydrological conditions were better than in 2016 due to the presence of “El Niño Costero”, which led to heavy rains in the Rimac River basin. The Tarma and Tulumayo River basins were less affected by this phenomenon, but still showed better performances. For the rest of the year, the three rivers were closer to their historical averages; however, during the last two months of 2017, the three rivers were even lower than the historical averages. In 2016, hydrological conditions were worse than the historical average with some rain deficits, especially towards the end of the year. Until October 1, 2017, spot prices were calculated based on restrictions to gas and transmission with a maximum price of US$95/MWh (known as “ideal marginal cost”). Currently, the marginal cost is not limited and may eventually increase in some seasons of the year, predominantly between June and December, mainly due to hydrological conditions. Enel Generation Piura is a thermal plant, and its results depend mainly on revenues from its own generation.

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b.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, 2018, electricity sales increased by 35.8% compared to 2017, totaling 100,927 GWh, mainly due to the acquisition and consolidation of Enel Distribution Sao Paulo and higher sales of Enel Distribution Goias. Our distributors serve important South American cities, providing electricity to over 24.5 million customers. These companies face growing electricity demand, partly because of demographic growth and partly because of higher consumption, which requires continous investment.

In the distribution business, 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 revenue from the Value Added from Distribution, which is associated with the recovery of costs and the return on the investment with respect to the distribution assets, plus the physical energy losses permitted by the regulator. Other revenues derived from our distribution services consist of charges for new connections and the maintenance and rental of meters, among other things; however, recently, it also includes public lighting, infrastructure projects mainly associated with real estate development and energy efficiency solutions, including air conditioning equipment, LED lights, among other things.

Although these other sources of revenue 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 intervene with directly regulated customer tariffs, or affect the price at which distributors can buy their energy. Our ability to buy electricity relies highly on generation availability and on regulation to a lesser degree. In addition, we are focusing on reducing physical losses, especially those due to illegally tapped energy, especially in Brazil and Argentina, improving our collection indices and our efficiency, primarily through new automation technologies.

c.Selective Regulatory Developments

The regulatory framework governing our businesses in the countries in which we operate has a material effect on our operating results. In particular, regulators set (i) energy prices in the generation business, taking into consideration factors such as fuel costs, reservoir levels, exchange rates, future investments in installed capacity and demand growth, and (ii) distribution tariffs taking into account the costs of energy purchases paid by distribution companies (which distribution companies pass on to their customers) and the Value Added from Distribution, all of which are intended to reflect investment and operating costs incurred by distribution and generation companies and to allow our companies to earn a regulated level of return on their investments and guarantee service quality and reliability. The earnings of our electricity subsidiaries are determined to a large degree by regulators, mainly through the tariff setting process. In Argentina, Resolution 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.

Our distribution companies are generally subject to annual tariff adjustments and integral tariff setting processes, or tariff reviews, carried out according to calendars defined by the regulators in each country. In Argentina, during 2017, ENRE updated the distribution tariff. In Brazil, during 2018 Enel Distribution Rio finished its tariff setting process in March 2018 and Enel Distribution Goais in October 2018, in both cases with an 18% increase to final customers and a 33% increase in the VAD (Parcel B) with respect to the previous review. The next integral tariff setting process for Enel Distribution Ceara is expected in April 2019 and for Enel Distribution Sao Paulo in July 2019. In Colombia, the CREG approved a new methodology to determine electricity distribution remuneration in January 2018, but Codensa’s tariff is still under review and expected to be disclosed during 2019. With the application of Resolution 015/18, a new distribution remuneration methodology is consolidated giving stability to Codensa’s current and future revenues. Enel Distribution Peru’s tariff review process finished in October 2018, resulting in a similar VAD rate with respect to the previous period. This result was achieved after an appeal process made through a reconsideration resource, since at the beginning a decrease of 8.8% in the VAD was taken into account, which would have implied a 2.8% decrease in the rate to the final customer. Each of these reviews is unique and presents challenges, since tariff reviews seek to capture distribution efficiencies and economies of scale based on economic growth.

For additional information relating to the Argentine regulatory frameworks or 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 periods of recession, changes in employment levels and inflation or deflation in the countries in which we operate, may have a significant effect on 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 the cost of capital expenditure plans and the cost of servicing U.S. dollar debt. For additional information, see “Item 3. Key Information — D. Risk Factors — South American economic fluctuations, political

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instability and corruption scandals may affect our results of operations and financial condition as well as the value of our securities.” and “—Foreign exchange risk may adversely 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 have an impact on 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 also the translation of financial statements of our foreign subsidiaries for consolidation purposes to the presentation currency, which is the U.S. dollar.

As of December 31, 2018, our consolidated debt totaled US$ 8,917 million (including US$ 2,652 million in debt that Enel Brasil has with with EFI, a Dutch finance affiliate and subsidiary of Enel), of which 51.8% was denominated in Brazilian reais, 21.9% in U.S. dollars, 20.4% in Colombian pesos, 5.6% in Peruvian soles, 0.3% in Chilean pesos (including the Chilean UF, which is inflation-indexed), and none in Argentine pesos.

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
	2018		2017		2016
	Average	Year End	Average	Year End	Average	Year End
Argentina (Argentine pesos per U.S. dollar)	36.54	37.70	16.59	18.65	14.76	15.89
Brazil (Brazilian reais per U.S. dollar)	3.65	3.87	3.19	3.31	3.48	3.26
Colombia (Colombian pesos per U.S. dollar)	2,952.39	3,249.75	2,953.19	2,984.00	3,051	3,001
Peru (Peruvian soles per U.S. dollar)	3.29	3.38	3.26	3.24	3.37	3.36
Chile (Chilean pesos per U.S. dollar)	640.95	694.77	648.51	614.75	676.19	669.47

Sources: Central Bank of each country

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)
	2018		2017		2016
			in thousands of US$
Argentina	(631,105	)	(68,925	)	(89,310	)
Colombia	(184,701	)	9,240		6,656
Brazil	(668,638	)	(100,485	)	364,926
Peru	(90,110	)	58,964		(68,009	)
Chile	(580	)	5,705		624
Total	(1,575,134	)	(95,501	)	214,887

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 prevailing 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 recognition of the country as a hyperinflationary economy, the treatment is different as explained in further details 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 U.S. dollar per any given foreign currency. It is a measure of the percent change in 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 means that the foreign currency devaluated with respect to the U.S. dollar.

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The following table shows the appreciation or devaluation of 2018 versus 2017 and 2017 versus 2016 for the closing and average local currencies per U.S. dollar:

	Appreciation/(Devaluation) per U.S. dollar (in %)
	2018/2017				2017/2016
	Average		Year End		Average		Year End
Argentine pesos	(120.3	)	(102.2	)	(11.0	)	(14.8	)
Brazilian reais	(14.3	)	(17.1	)	9.1		(1.5	)
Colombian pesos	0.0		(8.9	)	3.3		0.6
Peruvian soles	(0.7	)	(4.3	)	3.3		3.7

In the analysis of results of operations included below, when the impacts of the appreciation or devaluation are significant, they are disclosed and explained below.

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 a series of qualitative and quantitative criteria that include the presence of an accumulated inflation rate of over 100% in three years.

The general price indices at January 1, 2018, and December 31, 2018, are as follows:

	General price index
Historical inflation accumulated from February 2003 to December 2017	652.29	%
From January to December 2018	47.83	%

According to IAS 29, the financial statements of the Argentine companies in which we participate have been restated by applying a general price index to the historical cost, in order to reflect the changes in the purchasing power of the Argentine peso on the closing date of the financial statements. Non-monetary assets and liabilities were indexed from February 2003, the last date on which an inflation adjustment was applied for accounting purposes in Argentina.

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 the closing exchange rate (Ar$/US$) as of December 31, 2018, pursuant to IAS 21 “Effects of variations in foreign currency exchange rates” when it comes 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 conversion of the results for the rest of our subsidiaries in other countries whose economies are not considered hyperinflationary.

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

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The table below summarizes the effects of the application of IAS 29 and IAS 21 on our Argentine operations in our consolidated income statement:

	Enel Américas proforma without hyperinflation		Application effect by IAS 29		Application effect by IAS 21		Adjustments		Enel Américas reported
CONSOLIDATED INCOME STATEMENT	(i)		(ii)		(iii)		(iv)		(v)
					(in millions of US$)
Revenues	12,266		279		(426	)	(147	)	12,119
Other Operating Income	1,070		3		(8	)	(5	)	1,065
Revenues and Other Operating Income	13,336		283		(434	)	(152	)	13,184
Raw materials and consumables used	(8,229	)	(137	)	223		86		(8,143	)
Contribution Margin	5,107		146		(212	)	(66	)	5,041
Other work perfomed by the entity and capitalized	185		9		(16	)	(7	)	178
Employee benefits expenses	(868	)	(49	)	76		28		(840	)
Depreciation and amortization expense	(743	)	(134	)	14		(120	)	(862	)
Impairment loss recognized in the period’s profit or loss	(143	)	63		19		82		(61	)
Other expenses	(1,034	)	(27	)	40		12		(1,021	)
Operating Income	2,505		8		(79	)	(70	)	2,435
Other gains (losses)	1		—		(0	)	(0	)	1
Financial Income	378		13		(33	)	(20	)	358
Financial Costs	(1,106	)	(34	)	68		34		(1,072	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	3		0		(1	)	(0	)	2
Foreign currency exchange differences	148		(0	)	(38	)	(38	)	111
Income (Loss) for indexed assets and liabilities	—		270		—		270		270
Income (loss) before taxes	1,929		259		(82	)	176		2,105
Income tax expenses	(351	)	(117	)	30		(87	)	(438	)
NET INCOME	1,578		141		(52	)	89		1,667
Net Income attributable to:
Shareholders of Enel Américas	1,105		119		(23	)	96		1,201
Non-controlling interests	472		22		(29	)	(7	)	466
NET INCOME	1,578		141		(52	)	89		1,667

i.This column reflects what our consolidated net income would have been for the year ended December 31, 2018, if the Argentine economy had not been considered hyperinflationary as defined by IAS 29.

ii.This column includes IAS 29 adjustments (i.e. those arising from the indexation of non-monetary liabilities and assets), as well as those accounts of results that do not specify a base already updated by inflation.

iii.This column corresponds to the difference between converting the results of our Argentine subsidiaries at a closing exchange rate, as defined by IAS 21 for hyperinflationary economies, versus average exchange rates, which is the methodology previously applied to our Argentine subsidiaries and which is the current methodology for the rest of our subsidiaries operating in other countries in the region (non-hyperinflationary economies).

iv.Sum of (ii) + (iii).

v.Our results for the year ended December 31, 2018.

For further information, please refer to Note 8 to our consolidated financial statements.

Our Argentine operations do not affect our consolidated liquidity. Our Argentine cash and cash equivalents were US$ 182.6 million as of December 31, 2018, which represents 9.6% of our total cash and cash equivalents. Of the total Argentine cash and cash equivalents, 55.3% is denominated in local currency, 43.4% is denominated in U.S. dollars and the remaining 1.3% is denominated in euros.

e.Critical Accounting Policies

Critical accounting policies are those that reflect significant judgments and uncertainties, which would potentially result in materially different results under different assumptions and conditions. We believe that our most critical accounting policies with reference to the preparation of our combined financial statements under IFRS are those described below.

For further detail of the accounting policies and the methods used in the preparation of the consolidated financial statements, see Notes 2, 3 and 4 of the Notes to our consolidated financial statements.

Impairment of Long-Lived Assets

During the year, and principally at year-end, we evaluate whether there is any indication that an asset has become impaired. Should any such indication exist, we estimate the recoverable amount of that asset to determine, where appropriate, the amount of impairment. In the case of identifiable assets that do not generate cash flows independently, we estimate the recoverability of the cash generating unit 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, in the case of cash generating units to which goodwill or intangible assets with an indefinite useful life have been allocated, a recoverability analysis is performed routinely at each period end.

The recoverable amount is the greater of (i) the fair value less the cost needed to sell the asset and (ii) the value in use. “Value in use” is the present value of the estimated future cash flows. In order to calculate the recoverable value of property, plant and equipment, goodwill and intangible assets, that form part of a cash-generating unit, we use value in use criteria in nearly all cases.

To estimate the value in use, we prepare future pre-tax cash flow projections based on the most recent budgets available. These budgets incorporate management’s best estimates of cash generating units’ revenues and costs using sector projections, past experience and future expectations.

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In general, these projections cover the next five years, estimating cash flows for subsequent years based on the application of reasonable growth rates, between 2.5% and 10.4%, and a unique growth rate for the entire forecasted period that is in line with the average long-term growth rates for the electricity sector.

These cash flows are discounted at a given pre-tax rate in order to calculate their present value. This rate reflects the cost of capital of the business and the geographical area in which the business is conducted. The discount rate is calculated taking into account the current time value of money and the risk premiums generally used by market participants for the specific business activity and the country involved.

The pre-tax nominal discount rates applied in 2018, 2017 and 2016 are as follows:

		Year ended December 31,
		2018		2017		2016
Country	Currency	Minimum	Maximum	Minimum	Maximum	Minimum	Maximum
				(in %)
Argentina	Argentine peso	22.9	36.4	25.5	39.6	29.8	40.6
Brazil	Brazilian reais	9.1	21.3	9.7	21.1	11.0	21.8
Colombia	Colombian peso	7.9	12.9	8.7	11.0	10.0	10.7
Peru	Peruvian sol	7.2	12.1	7.7	11.1	7.2	11.5

If the recoverable amount is less than the net carrying amount of the cash-generating unit, the corresponding impairment loss provision is recognized for the difference, and charged to “Reversal of impairment loss (impairment loss) recognized in profit or loss” in the consolidated statement of comprehensive income.

Impairment losses recognized for an asset in prior periods are reversed when their estimated recoverable amount changes, increasing the asset’s value with a credit to earnings, limited to the asset’s carrying amount if no adjustment had occurred. In the case of goodwill, any impairments made are not reversible.

Litigation and Contingencies

We are currently involved in certain legal and tax proceedings. As discussed in Note 25 of the Notes to our consolidated financial statements as of December 31, 2018, we have estimated the probable outflows of resources for resolving these claims to be US$ 1,691.7 million. We have reached this estimate after consulting our legal and tax advisors who are defending us in these matters and after an analysis of potential results, assuming a combination of litigation and settlement strategies.

Hedge of Revenues Directly Linked to the U.S. Dollar

We have established a policy to hedge the portion of our revenues directly linked to the U.S. dollar by obtaining financing in U.S. dollars. These revenues are generated by certain of our subsidiaries that have a functional currency different to U.S. dollar. Exchange differences related to this debt, as they are cash flow hedge transactions, are charged net of taxes to an equity reserve account that forms part of Other Comprehensive Income and recorded as income during the period in which the hedged cash flows are realized. This term has been estimated at ten years.

This policy reflects a detailed analysis of our future U.S. dollar revenue streams. Such analysis may change in the future due to new electricity regulations limiting the amount of cash flows tied to the U.S. dollar.

Pension and Post-Employment Benefit Liabilities

We have various defined benefit plans for our employees. These plans pay benefits to employees at retirement and use formulas based on years of service and the compensation of the participants. We also offer certain additional benefits for particular retired employees.

The liabilities shown for the pensions and post-employment benefits reflect our best estimate of the future cost of meeting our obligations under these plans. The accounting applied to these defined benefit plans involves actuarial calculations which contain key assumptions including employee turnover, life expectancy, retirement age, discount rates, the future level of employee compensation and benefits, the claims rate under medical plans and future medical costs. These assumptions change as economic and market conditions vary and any change in any of these assumptions could have a material effect on the reported results from operations.

The effect of an increase of one percentage in the discount rate used to determine the present value of the post-employment defined benefits would decrease the liability by US$ 349.4 million, US$ 88.5 million and US$ 70.3 million as of December 31, 2018, 2017 and 2016, respectively, and the effect of a decrease of one percentage in the rate used to determine the present value of the post-

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employment defined benefits would increase the liability by US$ 414.4 million, US$ 105.3 million and US$ 82.3 million as of December 31, 2018, 2017 and 2016, respectively.

Change in Functional and Reporting Currency for Financial Reporting

We reviewed our functional currency in accordance with IFRS. We concluded that as a result of the 2016 Reorganization, the economic environment in which we operate changed and the cash inflows and outflows are now primarily denominated in U.S. dollars. Therefore, we changed our functional and reporting currency from Chilean Pesos to U.S. dollars as of January 1, 2017. This conclusion was discussed and approved by the Board of Directors at its meeting held on October 28, 2016 and approved by the ESM held on April 27, 2017.

See Note 3 of the Notes to our consolidated financial statements.

Recent Accounting Pronouncements

Please see Note 2.2 of the Notes to our consolidated financial statements for additional information regarding recent accounting pronouncements.

2.Analysis of Results of Operations for the Years Ended December 31, 2018 and 2017.

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, 2018 and 2017:

	Electricity sales during the year ended December 31,
	2018	2017	Change		Change
		(in GWh)			(in %)
Costanera (Argentina)	7,101	7,852	(752	)	(9.6	)
El Chocón (Argentina)	2,901	2,055	846		41.2
Dock Sud (Argentina)	3,951	4,945	(995	)	(20.1	)
Cachoeira Dourada (Brazil)	18,098	9,526	8,571		90.0
Fortaleza (Brazil)	2,763	2,923	(161	)	(5.5	)
EGP Volta Grande (Brazil)	1,376	137	1,239		904.5
Emgesa (Colombia)	18,544	18,156	388		2.1
Enel Generation Peru (Peru)	9,994	9,817	177		1.8
Enel Generation Piura (Peru)	603	640	(37	)	(5.8	)
Total	65,329	56,051	9,277		16.6

 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, 2018 and 2017:

	Electricity sales during the year ended December 31,
	2018	2017	Change		Change
	(in GWh)				(in %)
Edesur (Argentina)	17,548	17,736	(188	)	(1.1	)
Enel Distribution Rio (Brazil)	11,019	11,091	(72	)	(0.6	)
Enel Distribution Ceara (Brazil)	11,843	11,522	321		2.8
Enel Distribution Goias (Brazil)	13,755	12,264	1,491		12.2
Enel Distribution Sao Paulo (Brazil)	24,693	—	24,693		n.a.
Codensa (Colombia)	14,024	13,790	234		1.7
Enel Distribution Peru (Peru)	8,045	7,934	111		1.4
Total	100,927	74,337	26,590		35.8

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The following table sets forth the revenues and other operating income from continuing operations, by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2018 and 2017:

	Year ended December 31,
	2018		2017		Change		Change
	(in millions of US$)						(in %)
Generation and Transmission Business in Argentina	328		300		28		9.4
Costanera	163		152		10		6.9
El Chocón	67		58		9		14.8
Dock Sud	95		88		7		7.6
Other	3		1		2		n.a.
Generation and Transmission Business in Brazil	854		829		25		3.1
Cachoeira Dourada	540		503		37		7.4
Fortaleza	212		261		(50	)	(19.1	)
Cien	83		89		(6	)	(6.9	)
EGP Volta Grande	82		9		73		n.a.
Other	(62	)	(33	)	(29	)	89.1
Generation and Transmission Business in Colombia	1,260		1,160		100		8.6
Emgesa	1,260		1,160		100		8.6
Generation and Transmission Business in Peru	790		730		60		8.2
Enel Generation Peru	708		646		61		9.5
Enel Generation Piura	89		87		2		2.4
Other	(7	)	(3	)	(4	)	n.a.
Total Generation and Transmission Business reportable segment	3,231		3,020		211		7.0
Distribution Business in Argentina	1,190		1,223		(33	)	(2.7	)
Edesur	1,190		1,223		(33	)	(2.7	)
Distribution Business in Brazil	6,922		4,613		2,309		50.0
Enel Distribution Rio	1,511		1,646		(135	)	(8.2	)
Enel Distribution Ceara	1,411		1,450		(40	)	(2.7	)
Enel Distribution Goias	1,542		1,517		25		1.6
Enel Distribution Sao Paulo	2,459		—		2,459		n.a
Distribution Business in Colombia	1,714		1,538		176		11.4
Codensa	1,714		1,538		176		11.4
Distribution Business in Peru	913		879		34		3.8
Enel Distribution Peru	913		879		34		3.8
Total Distribution Business reportable segment	10,739		8,253		2,486		30.1
Less: consolidation adjustments and non-core activities	(786	)	(834	)	48		(5.8	)
Total Revenues and other operating income	13,184		10,438		2,746		26.3

Generation and Transmission Business: Revenues

In Argentina, revenues increased by US$ 28 million, or 9.4%, primarily explained by:

·Revenues and other operating income from Costanera increased in 2018, despite lower physical sales of 752 GWh, or 9.6%, compared to 2017 generation, mainly due to (i) US$ 76 million of higher revenues attributable to increase in tariff remuneration due to Resolution 19, which was applied as of February 2017, and (ii) US$ 23 million of revenues from the CPI update, as a result of the application of IAS 29 in Argentina.  This was partially offset by US$ 85 million of lower revenues as a result of the devaluation of the Argentine peso against the U.S. dollar experienced during 2018 and to the change in the conversion methodology due to the application of IAS 29 in Argentina moving from average exchange rate to closing exchange rate, as indicated by IAS 21 for hyperinflationary economies.

·Revenues and other operating income from El Chocón increased in 2018, mainly due to (i) a US$ 25 million increase in tariff remuneration associated with Resolution 19 and contracted prices indexed to the U.S. dollar, (ii) a US$ 5 million increase due to higher physical sales of 846 GWh explained by better hydrological conditions and generation, and (ii) a US$ 11 million increase from the CPI update, as a result of the application of IAS 29 in Argentina.  This was partially offset by a US$ 32 million decrease as a result of the devaluation of the Argentine peso against the U.S. dollar and to the application of IAS 29.

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·Revenues and other operating income from Dock Sud increased in 2018, despite the lower physical sales of 994 GWh due to the unavailability of unit 9 for five months. The increase is principally due to a US$ 45 million increase attributable to higher tariffs due to Resolution 19 in effect since 2017 and the recognition of other operating income from fire insurance compensation of US$ 11 million associated with unit 9.  This was partially offset by US$ 49 million of lower revenues as a result the devaluation of the Argentine peso against the U.S. dollar and the application of IAS 29.

In Brazil, revenues and other operating income increased by US$ 25 million, or 3.1%, largely explained by:

·Revenues from EGP Volta Grande increased by US$ 73 million due to higher energy sales of 1,239 GWh, compared to 2017. In 2017, EGP Volta Grande contributed only US$ 9 million because it reflected only one month of income given its acquisition on November 30, 2017.

·This increase was partially offset by US$ 50 million lower revenues from Fortaleza in 2018 mostly due to a (i) US$ 33 million decrease as a result of the 14.3 % devaluation of the Brazilian reais against the U.S. dollar, (ii) US$ 15 million lower revenues as a result of a lower recognition of Provin, a tax incentive for industrial developments, and (iii) US$ 5 million decrease as a result of lower energy sales of 161 GWh. This was partially offset by recognition of other operating income of US$ 3 million from insurance compensation.

·Physical energy sales of Cachoeira Dourada increased by 8,571 GWh, or 90% higher than in 2017, an increase of US$ 100 million, explained by much higher trading activity with purchases in the spot market and prices in reais.  However, revenues increased by only 7.4% because of the accounting effect of the 14.3% devaluation of the reais in relation to the U.S. dollar.

In Colombia, revenues and other operating income from Emgesa increased in 2018 mainly due to (i) a US$ 64 million associated with tariff increases, (ii) US$ 24 million due to higher physical sales of 388 GWh and (iii) a US$ 12 million increase due to compensations for lost profits for an accident in the Chivor tunnel, which affected the Guavio plant.

In Peru, revenues and other operating income increased by US$ 61 million, or 8.2%, explained by higher revenues from Enel Generation Peru. This is mostly explained by (i) a US$ 44 million increase in toll revenues due to more unregulated customers, (ii) a US$ 16 million increase in energy sales, of which US$ 13 million correspond to higher physical sales of 177 GWh and US$ 3 million to higher average prices, (iii) a provision for material damage and loss of profits associated with the Ventanilla power plant rotor totalling US$ 8 million and an insurance provision of US$ 6 million associated with turbine TG-7 of the same power plant, and (iv) provision for the accident in the Callahuanca loading chamber of US$ 2 million.  This was offset by a lower provision for material damage and loss of profits of US$ 17 million, related to the weather emergency in 2017, affecting several of our plants.

Distribution Business: Revenues

In Argentina, revenues and other operating income from Edesur decreased in 2018 mainly due to US$ 685 million of lower revenues as a result of the devaluation of the Argentine peso against the U.S. dollar and the change in the conversion methodology due to the application of IAS 29.  This was partially offset by the recognition of (i) US$ 431 million of higher revenues from energy sales as a result of the application of the new tariff review in effect since February 1, 2017 and (ii) a US$ 221 million increase from the CPI update as a result of the application of IAS 29.

In Brazil, revenues and other operating income increased by US$ 2,309 million, or 50.0%, explained by:

·Revenues and other operating income from Enel Distribution Sao Paulo contributed US$ 2,459 million to our consolidated revenues and other operating income as a result of our acquisition and consolidation of the company since June 2018. Enel Distribution Sao Paulo’s revenues were mainly comprised of (i) US$ 2,023 million in energy sales equivalent to 24,693 GWh of physical sales, (ii) other service provision of US$ 192 million corresponding to revenues from toll services and (iii) US$ 244 million from other operating income of which US$ 225 million is mainly explained by revenues related to concession contracts accounted for under IFRIC 12, and US$ 19 million of client fines.

·This increase was partially offset by lower revenues and other operating income from Enel Distribution Rio in 2018, principally due to (i) a US$ 204 million decrease as a result of the devaluation of the Brazilian reais against the U.S. dollar, (ii) a US$ 86 million in lower tax revenue received from research and development in energy efficiency, (iii) a US$ 78 million decrease in revenues related to concession contracts accounted for under IFRIC 12, which was compensated by (x) a US$ 194 million increase due to tariff recovery, (y) a US$ 30 million increase from tolls and (z) a US$ 11 million increase from higher non-billed energy sales.

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In Colombia, revenues and other operating income from Codensa increased in 2018 mainly due to a (i) a US$ 18 million increase related to 234 GWh higher physical sales, (ii) a US$ 140 million increase mainly due to higher average prices of energy, and (iii) a US$ 16 million increase associated with contracts of electrical works, posts and pipeline rental, lines and networks and infrastructure rental and others.

In Peru, revenues and other operating income from Enel Distribution Peru increased in 2018 mainly due to a US$ 33 million increase related to a tariff increase and a US$ 17 million increase due to 111 GWh higher physical sales.  This was offset by a US$ 9 million decrease due to lower services mainly in network movements and US$ 6 million due to the 0.7% depreciation of the Peruvian Sol against the U.S. dollar.

Total Operating Costs

Total operating costs from continuing operations consist primarily of energy purchases from third parties, fuel consumption, depreciation, amortization and impairment losses, maintenance costs, tolls paid to transmission companies, employee salaries and administrative and selling expenses.

The following table sets forth consolidated operating costs for the years ended December 31, 2018 and 2017:

		Year ended December 31,
	2018		2017	Change		Change
	(in millions of US$)					(in %)
Energy purchases	5,738		3,940	1,797		45.6
Fuel consumption	227		229	(2	)	(1.1	)
Transportation costs	1,055		634	421		66.4
Other raw materials and combustibles	1,123		1,079	44		4.0
Other expenses(1)	1,021		943	78		8.3
Employee benefit expense and other(1)	662		665	(2	)	(0.3	)
Depreciation, amortization and impairment losses(1)	923		728	195		26.8
Total Operating Cost from Continuing Operations	10,750		8,219	2,531		30.8

(1)Corresponds to selling and administration expenses

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The following table sets forth our total operating costs (excluding selling and administrative expenses) from continuing operations by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2018 and 2017:

	Year ended December 31,
	2018		2017		Change		Change
	(in millions of US$)						(in %)
Generation and Transmission Business in Argentina	40		25		15		60.0
Costanera	15		9		7		77.3
El Chocón	5		7		(2	)	(31.6	)
Dock Sud	21		12		9		74.3
Other	(1	)	(3	)	2		(61.1	)
Generation and Transmission Business in Brazil	574		490		84		17.1
Cachoeira Dourada	418		372		45		12.2
Fortaleza	207		147		61		41.5
Cien	2		3		(1.0	)	(38.7	)
EGP Volta Grande	11		1		10		n.a
Other	(63	)	(32	)	(21	)	65.9
Generation and Transmission Business in Colombia	478		396		82		20.7
Emgesa	478		396		82		20.7
Generation and Transmission Business in Peru	383		348		35		10.1
Enel Generation Peru	352		314		39		12.3
Enel Generation Piura	37		38		(1	)	(1.6	)
Other	(6	)	(3	)	(3	)	85.6
Total Generation and Transmission Business reportable segment	1,475		1,259		216		17.2
Distribution Business in Argentina	729		687		42		6.1
Edesur	729		687		42		6.1
Distribution Business in Brazil	5,084		3,323		1,761		53.0
Enel Distribution Rio	1,027		1,190		(163	)	(13.7	)
Enel Distribution Ceara	1,037		1,019		18		1.7
Enel Distribution Goias	1,106		1,114		(8	)	(0.7	)
Enel Distribution Sao Paulo	1,914		—		1,914		100.0
Distribution Business in Colombia	1,033		867		166		19.1
Codensa	1,033		867		166		19.1
Distribution Business in Peru	611		579		32		5.5
Enel Distribution Peru	611		579		32		5.5
Total Distribution Business reportable segment	7,457		5,456		2,001		36.7
Less: consolidation adjustments and non-core activities	(789	)	(832	)	43		(5.2	)
Total operating costs (excluding selling and administrative expenses)	8,143		5,883		2,260		38.4

Generation and Transmission Business: Operating Costs

In Argentina, operating costs increased US$ 15 million, or 60%, mainly due to:

·Operating costs of Dock Sud increased in 2018 mainly due to US$ 9 million of higher gas consumption costs due to Resolution 70, which established that the commercial management of the fuel is no longer a CAMMESA dispatch, and now it is managed by generation companies themselves.

·Operating costs of Costanera increased during 2018, mainly explained by US$ 10 million higher gas consumption, as a consequence of Resolution 70, partially offset by a US$ 3 million reduction due to the application of IAS 21 in hyperinflationary economies, which also decreased El Chocón’s operating costs by US$ 2 million.

In Brazil, operating costs increased by US$ 84 million, or 17.1%, which is explained by:

·Operating costs of Fortaleza increased in 2018 mainly attributable to a US$ 124 million increase in energy purchases due to the gas supply interruption caused by Petrobras, which forced Fortaleza to buy the energy in the market in order to fulfill client contracts. This was partially offset by lower fuel consumption of US$ 43 million and a US$ 20 million decrease stemming from the depreciation of the Brazilian reais against the U.S. dollar.

105

·Operating costs of Cachoeira Dourada increased in 2018 mostly comprised of a US$ 90 million increase due to higher energy purchases for 8,465 GWh as a result of higher sales to unregulated customers, offset by a US$ 45 million decrease due to the depreciation of the Brazilian reais against the U.S. dollar.

In Colombia, Emgesa operating costs increased in 2018 mainly due to (i) US$ 27 million in increased energy purchases explained by US$ 68 million due to higher energy purchases of 1,100 GWh in the spot market, offset by US$ 41 million in purchase price reduction in the spot market (ii) a US$ 22 million increase in fuel consumption, related to higher thermal generation, (iii) a US$ 15 million increase in transportation costs due to client increase in the unregulated market and (iv) a US$ 18 million increase from other supplies mainly from higher gas costs.

In Peru, Enel Generation Peru operating costs increased in 2018 mostly associated with (i) a US$ 31 million increase in energy purchases in the spot market of which US$ 21 million is attributable to the effect of a higher average price and (ii) US$ 7 million in higher fuel costs due to higher oil consumption for thermal production stemming from a higher client demand.

Distribution Business: Operating Costs

In Argentina, operating costs of Edesur increased in 2018 primarily due to (i) a US$ 383 million increase in energy purchases of which US$ 264 million are related to the price increase and US$ 119 million to higher costs from the update of the CPI due to the application of IAS 29, (ii) a US 27 million increase in higher transportation costs mainly due to price increases and (iii) a US$ 16 million increase in generator equipment rentals.  These increases were partly offset by US$ 384 million from the depreciation of the Argentine Peso against the U.S. dollar and the application of IAS 21 for a hyperinflationary economy.

In Brazil, operating costs increased by US$ 1,761 million, or 53.0%, explained by:

·Operating costs from Enel Distribution Sao Paulo contributed US$ 1,914 million to our consolidated operating costs as a result of our acquisition. Enel Distribution Sao Paulo’s operating costs were mainly comprised of: (i) US$ 1,439 from energy purchases to cover higher demand, (ii) US$ 249 million of transport cost and (iii) US$ 225 million of construction costs related to the concession contracts accounted for under IFRIC 12.

·This higher operating costs were partially offset by lower operating costs from Enel Distribution Rio in 2018, which are mainly explained by: (i) a US$ 63 million decrease in energy purchases attributable to a US$ 95 million decrease due to the devaluation of the Brazilian reais against the U.S. dollar, partially offset by a US$ 32 million increase due to higher prices for regulated industrial tariffs and hydrological risks costs; (ii) a US$ 122 million decrease in other variable supplies corresponding to (a) US$ 78 million lower construction costs related to concession contracts accounted for under IFRIC 12, (b) a US$ 39 million decrease due to the depreciation of the Brazilian reais against the U.S. dollar and (c) US$ 5 million reduction associated to  loss energy preventions.  These decreases were partially offset by a US$ 22 million increase in energy transport costs due to the increased thermal generation of US$ 37 million offset by US$ 15 million due to the depreciation of the Brazilian reais against the U.S. dollar.

In Colombia, operating costs of Codensa increased in 2018 predominantly due to a (i) a US$ 152 million increase in higher energy purchases of which US$ 12 million corresponds to 178 GWh higher physical purchases and US$ 140 million to higher energy prices, (ii) a US$ 11 million increase in transportation costs, and (iii) a US$ 2 million increase as a result of higher costs linked to the installation of measuring equipment.

In Peru, operating costs of Enel Distribution Peru increased in 2018 compared to 2017 mainly attributable to a US$ 23 million increase in energy purchases due to a higher purchase average price and US$ 8 million in higher physical purchases and US$ 5 million in higher costs corresponding to contractors for line connections and maintenance charges. This was partly offset by a US$ 3 million decrease due to the 0.7% devaluation of the Peruvian Sol against the U.S. dollar.

Selling and Administrative Expenses

Selling and administrative expenses relate to salaries, compensation, administrative expenses, depreciation, amortization and impairment losses, and office materials and supplies.

106

The following table sets forth the selling and administrative expenses by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2018 and 2017:

	Year ended December 31,
	2018		2017	Change		Change
	(in millions of US$)					(in %)
Generation and Transmission Business in Argentina	132		160	(28	)	(17.4	)
Costanera	58		104	(45	)	(43.7	)
El Chocón	29		17	13		76.4
Dock Sud	40		37	3		7.9
Other	4		2	1.9		82.6
Generation and Transmission Business in Brazil	68		78	(9	)	(11.7	)
Cachoeira Dourada	20		24	(3	)	(13.2	)
Fortaleza	21		26	(5	)	(20.8	)
Cien	25		28	(3	)	(10.3	)
EGP Volta Grande	3		0	2		n.a.
Other	0		0	(0	)	(99.3	)
Generation and Transmission Business in Colombia	148		153	(4	)	(2.9	)
Emgesa	148		153	(5	)	(3.0	)
Generation and Transmission Business in Peru	139		154	(16	)	(10.2	)
Enel Generation Peru	116		131	(15	)	(11.3	)
Enel Generation Piura	22		23	(1	)	(2.6	)
Other	(0	)	0	(0	)	n.a.
Total Generation and Transmission Business reportable segment	487		544	(57	)	(10.5	)
Distribution Business in Argentina	383		385	(3	)	(0.7	)
Edesur	383		385	(3	)	(0.7	)
Distribution Business in Brazil	1,230		947	283		29.8
Enel Distribution Rio	311		346	(35	)	(10.1	)
Enel Distribution Ceara	234		239	(6	)	(2.5	)
Enel Distribution Goias	278		362	(84	)	(23.1	)
Enel Distribution Sao Paulo	407		—	407		100.0
Distribution Business in Colombia	292		259	34		13.0
Codensa	292		259	34		13.0
Distribution Business in Peru	126		126	0		0.1
Enel Distribution Peru	126		126	0		0.3
Total Distribution Business reportable segment	2,031		1,718	314		18.3
Less: consolidation adjustments and non-core activities	87		74	13		17.7
Total selling and administrative expenses	2,606		2,336	270		11.6

Selling and administrative expenses increased in 2018 as compared to 2017, mainly due to the acquisition of Enel Distribution Sao Paulo. Otherwise our selling and administrative expenses would have decreased. The main changes are explained below.

Generation and Transmission Business

In Argentina, selling and administrative expenses decreased during 2018, mainly due to:

·Costanera’s selling and administrative expenses decreased mainly due to a US$ 63 million lower impairment losses of which US$ 71 million corresponded to reversal of an impairment charge for fixed assets recorded on January 1, 2018, as a result of the application of IAS 21 in hyperinflationary economies, partially offset by higher impairment losses associated with accounts receivable of US$ 8 million. Costanera’s payroll expenses decreased by US$ 19 million mainly explained by US$ 22 million due to the application of IAS 21 partially offset by US$ 3 million salary cost increase related to the country’s internal inflation. These decreases were partially offset by US$ 41 million of higher depreciation mainly from the application of IAS 21.

·These decreases were partially offset by an increase in development, El Chocón’s selling and administrative expenses, which increased by US$ 13 million as a result of the application of IAS 21 to the depreciation.

107

In Brazil, selling and administrative expenses decreased during 2018 by US$ 9 million, which is explained by:

·Lower depreciation of US$ 5 million in Fortaleza as a result of US$ 3.4 million of lower charges associated to the current base of fixed assets and US$ 1.8 million decrease due to the depreciation of the Brazilian reais against the U.S. dollar.

·A US$ 3 million decrease of Cachoeira Dourada’s selling and administrative expenses due to the depreciation of the Brazilian reais against the U.S. dollar.

In Colombia, selling and administrative expenses of Emgesa decreased mainly due to a US$ 9 million decrease associated to write-offs of non-profitable projects carried out in 2017 such as the Campo Hermoso project for US$ 2 million, the Agua Clara project for US$ 5 million and the Guaicaramo project for US$ 3 million. This was partially offset by a (i) US$ 2 million increase in payroll expenses mostly due to higher salary costs and bonuses, and (ii) a US$ 2 million increase in depreciation expense due to higher capitalizations of works in progress.

In Peru, selling and administrative expenses of Enel Generation Peru decreased in 2018 mainly due to (i) a US$ 10 million impairment loss recorded in 2017 due to the deterioration of the Callahuanca power plant as a consequence of a weather emergency in March 2017, and (ii) a US$ 6 million decrease in depreciation expenses, of which US$ 3.9 million were related to lower depreciation expenses associated with the rotor of Ventanilla and US$ 1 million of lower depreciation (only 3 months in 2017) associated with Callahuanca.

Distribution Business

In Argentina, selling and administrative expenses of Edesur remained relatively stable in comparison to 2017 despite the application of IAS 21 and 29.

In Brazil, selling and administrative expenses increased primarily due to the inclusion of Enel Distribution Sao Paulo, which were comprised of US$ 156 million in payroll expenses, which include salaries and social security laws, US$ 145 million in other expenses, mainly to third party services costs associated to the maintenance of lines, networks and other services, and US$ 113 million in depreciation expenses. This was partially offset by:

·Lower selling and administrative expenses in Enel Distribution Goais, mainly due to (i) US$ 63 million lower payroll expenses, of which US$ 50 million correspond to voluntary retirement plan provision which took place in February 2017 and US$ 13 million to the devaluation of the Brazilian reais against the U.S. dollar; and (ii) US$ 14 million decrease in other expenses explained mainly by US$ 20 million associated to the devaluation of the Brazilian reais against the U.S. dollar offset by US$ 6 million higher meter reading services expenses and customer services; and

·Lower selling and administrative expenses in Enel Distribution Rio, mainly due to (i) US$ 22 million lower other expenses, mainly due to the devaluation of the Brazilian reais against the U.S. dollar.

In Colombia, selling and administrative expenses of Codensa increased as compared to 2017, mainly due to: (i) US$ 14 million higher in depreciation expense due to the increase in the substations, lines and networks, (ii) a US$ 10 million increase in impairment losses of accounts receivables, and (iii)  US$ 10 million in higher other expenses, mostly due to a US$ 4 million increase due to higher services costs for lines and networks maintenance, US$ 3 million for advertising costs and US$ 3 million for other expenses of contractor services.

In Peru, selling and administrative expenses of Enel Distribution Peru remained stable in comparison to 2017.

108

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, 2018 and 2017:

	Year ended December 31,
	2018		2017		Change		Change
	(in millions of US$)						(in %)
Generation and Transmission Business in Argentina	156		115		41		35.6
Costanera	89		40		49		122.3
El Chocón	33		55		(22	)	(39.8	)
Dock Sud	34		39		(5	)	(13.2	)
Other	(0	)	(19	)	19		(97.5	)
Generation and Transmission Business in Brazil	211		262		(51	)	(19.6	)
Cachoeira Dourada	102		107		(5	)	(4.7	)
Fortaleza	(16	)	89		(105	)	(118.6	)
Cien	56		58		(2	)	(3.9	)
EGP Volta Grande	69		7		61		n.a.
Other	—		—		—		n.a.
Generation and Transmission Business in Colombia	633		611		22		3.6
Emgesa	633		611		22		3.6
Generation and Transmission Business in Peru	269		229		41		17.7
Enel Generation Peru	239		201		38		18.7
Enel Generation Piura	30		27		3		12.0
Other	0.1		0.4		(0.4	)	(88.4	)
Total Generation and Transmission Business reportable segment	1,269		1.216		53		4.4
Distribution Business in Argentina	78		151		(73	)	(48.3	)
Edesur	78		151		(73	)	(48.3	)
Distribution Business in Brazil	608		342		266		77.7
Enel Distribution Rio	173		109		63		57.9
Enel Distribution Ceara	140		191		(51	)	(26.9	)
Enel Distribution Goias	158		42		116		n.a.
Enel Distribution Sao Paulo	138		—		138		n.a.
Distribution Business in Colombia	389		412		(23	)	(5.5	)
Codensa	389		412		(23	)	(5.5	)
Distribution Business in Peru	176		174		2		0.9
Enel Distribution Peru	176		174		2		0.9
Total Distribution Business reportable segment	1,251		1,079		172		15.9
Less: consolidation adjustments and non-core activities	(85	)	(76	)	(9	)	11.9
Total operating income	2,435		2,219		216		9.7

Generation and Transmission Business

Operating income in 2018 was higher than in 2017 mainly due to the inclusion of EGP Volta Grande and better results of Costanera and Enel Generation Peru.

In Argentina, operating income of Costanera increased, despite its lower physical sales. The increase was due to the application of IAS 21 and the reversal of impairments registered on January 1, 2018 in Costanera plus the new remuneration scheme in place since February 2017. El Chocón experienced a decrease in operating income due to the application of IAS 21, which was not compensated by the new remuneration scheme and the slightly better hydrological conditions during 2018.

In Brazil, Fortaleza considerably decreased its operating income as a result of its higher operating costs due to the interruption of the gas supply. Its energy purchases increased more than the decrease of its fuel consumption, which coupled to the effect of the depreciation of the Brazilian reais against the U.S. dollar in its revenues led to this result. This was partially offset by better results of EGP Volta Grande associated to its higher physical sales (2 months in 2017 versus a complete year in 2018).

In Colombia, Emgesa’s operating income increased mainly as a consequence of higher physical sales and tariff increase due to better hydrological conditions in 2017, in addition to a one-time effect registered in 2017 regarding write-offs of some projects.

109

Enel Generation Peru increased its operating income mainly due to higher sales to unregulated customers, higher physical sales as well as the non-recurrent effect of impairment losses registered in 2017 associated to the weather emergencies and lower depreciation associated to insurance claims.

Distribution Business

Operating income increased by 16% in 2018 compared to 2017, mainly due to better results of our Brazilian subsidiaries and the inclusion of Enel Distribution Sao Paulo.

In Argentina, Edesur’s operating income was negatively affected by the devaluation of the Argentine peso against the U.S. dollar, the application of IAS 29 and higher energy purchase prices.

In Brazil, Enel Distribution Goais improved its operating income mainly due to lower workface expenses and to a lesser degree to the impact of the devaluation of the Brazilian reais against the U.S. dollar in its selling and administrative expenses. Operating revenues also increased, but to a lesser extent, as a result of higher energy sales explained by higher physical sales of 1,491 GWh and tariff recovery. This was also improved by the inclusion of Enel Distribution Sao Paulo into our consolidation perimeter as of June 2018.

In Colombia, Codensa’s operating income decreased, despite its higher physical sales and sale prices mainly due to higher selling and administrative expenses due to the activation of fixed assets, which increase its depreciation, and impairment losses on account receivables.

Enel Distribution Peru´s operating income remained stable in 2018 when compared to 2017.

Other Results

The following table sets forth the other results for the years ended December 31, 2018, and 2017:

	Year ended December 31,
	2018		2017		Change		Change
	(in millions of US$)						(in %)
Financial results
Financial income	358		294		64		21.8
Financial costs	(1,072	)	(870	)	(202	)	23.3
Results for Hyperinflation	270		—		270		100.0
Results from indexed assets and liabilities	—		—		—		—
Net foreign currency exchange gains (losses)	111		(7	)	118		n.a.
Total	(333	)	(582	)	249		(42.9	)
Other
Other gains (losses)	1		6		(5	)	(89.3	)
Share of the profit of associates and joint ventures accounted for using the equity method	2		3		(1	)	(25.9	)
Total	3		9		(6	)	(65.8	)
Total other results	(330	)	(574	)	244		(42.5	)

Financial Results

Our net total financial results in 2018 were a lower net loss when compared to the loss registered in 2017. The variation is mainly explained by:

·a US$ 270 million increase in results from readjustments correspond to the profit generated by the application of IAS 29 in Argentina and reflect the net balance arising from implementing inflation to non-monetary assets and liabilities and result accounts that are not determined on a current basis converted to U.S. dollars at year-end exchange rate;

·better results in foreign currency exchange gains of US$ 118 million mainly in Argentina due to: a US$ 125 million difference of positive exchange related to accounts receivables in foreign currency for VOSA credits in Argentina, and US$ 14 million positive exchange rate differences in credits with CAMMESA.  This was partially offset by US$ 29 million negative exchange rate difference for debt in foreign currency with Mitsubishi in Costanera;

110

·higher financial income of US $ 64 million mainly attributable to a US$67 million increase due to the incorporation of Enel Distribution Sao Paulo, of which US$ 19 million correspond to the recognition of interest income from IFRIC 12, US$ 12 million to accrued interests for cash deposits and legal deposits, and US$ 36 million to commercial account interests.

·an increase in financial costs of US$ 202 million in 2018 mainly due to (i) a US$ 165 million increase due to the incorporation of Enel Distribution Sao Paulo into the consolidation perimeter and (ii) a US$ 151 million increase associated to financial debt for the acquisition of Enel Distribution Sao Paulo.  This was partially offset by (i) a US$ 100 million decrease in Enel Distribution Rio which is explained by a (a) US$ 68 million decrease in interest on bond debt and other debts, including US$ 25 million corresponding to the devaluation of the Brazilian reais against the U.S. dollar, (b) a US$ 16 million decrease due to the financial update of civil contingency allowance, (c) a US$ 9 million decrease of financial effects of regulatory assets and liabilities, and (d) a US$ 7 million reduction of FIDIC financial charges, a program for the sale of the client portfolio.

·decrease in foreign currency exchange gains (losses) of US$ 66 million in 2017 mainly due to a US$ 37 million decrease in positive foreign exchange differences in the foreign currency denominated debt of Enel Brasil and US$ 16 million associated with bank loans of Enel Distribution Rio.

Other Non-Operating Results

Other non-operating results decreased compared to 2017, predominantly due to other gains in Enel Generation Peru from the sale of real state recorded in 2017.

Income Taxes

Total income tax expense decreased in 2018, as compared to 2017. The most significant changes correspond to (i) a US$ 277 million lower tax expense in Enel Distribution Goias mainly due to lower recognition of deferred tax assets of US$ 347 million offset by US$ 70 million as a result of the devaluation of the Brazilian reais against the U.S. dollar, (ii) US$ 37 million in lower taxes in Fortaleza due to lower results in 2018 because of the interruption of the gas supply by Petrobras, (iii) US$ 20 million in lower taxes in Codensa due to lower results with respect to 2017 and (iv) US$ 46 million in lower tax expenses in Enel Brasil mainly for the future recovery of taxes on financial expenses.

This was partially offset by (i) US$ 40 million in higher tax expense in Enel Distribution Rio from better financial results compared to the previous period, (ii) US$ 18 million in higher tax expenses due to the acquisition of EGP Volta Grande in November 2017, (iii) US$ 17 million in higher tax expenses due to the consolidation of Enel Distribution Sao Paulo and (iv) US$ 54 million increased taxes in El Chocón mainly due to the improvement in results as compared to 2017, among them the positive effects of the exchange rate for accounts receivable in U.S. dollars, (v) US$ 24 million in increased taxes in Costanera as a result of improved results compared to 2017 before including the positive effects of the exchange rate for accounts receivable in U.S. dollars and (vi) US$ 138 million increased taxes in Edesur mainly from a tax recorded in relation to the effects of the application of hyperinflation in the company’s balance sheets.

The effective or statutory tax rate was 20.8% in 2018 and 31.6% in 2017. This decrease is mainly due to the recognition of deferred tax assets in Enel Distribution Goais.

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 and tax rates (6.6% for 2018 and 10.9% for 2017) enacted in each foreign jurisdiction:

	Nominal Tax Rates (%)		Tax effect of rates applied in other countries (in millions of US$)
	2018	2017	2018		2017
Argentina	30.0	35.0	(15.9	)	(11.9	)
Brazil	34.0	34.0	(26.3	)	(28.5	)
Colombia	37.0	40.0	(86.3	)	(123.0	)
Peru	29.5	25.5	(11.3	)	(16.3	)
			(139.8	)	(179.7	)

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Net Income

The following table sets forth our consolidated net income from continuing operations before income taxes, income taxes and net income from continuing operations for the years ended December 31, 2018 and 2017.

	Year ended December 31,
	2018		2017		Change	Change
	(in millions of US$)					(in %)
Operating income	2,435		2,219		216	9.7
Other results	(330	)	(574	)	244	(42.5	)
Income before income taxes	2,105		1,646		459	27.9
Income taxes	(438	)	(519	)	81	(15.6	)
Net Income	1,667		1,127		540	48.0
Income	—		—		—	—
Net income attributable to:	1,667		1,127		540	48.0
Net income attributable to the parent company	1,201		709		492	69.4
Net income attributable to non-controlling interests	466		418		48	11.3

3.             Analysis of Results of Operations for the Years Ended December 31, 2017 and 2016.

Revenues and other operating income from Continuing Operations

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, 2017 and 2016:

	Electricity sales during the year ended December 31,
	2017	2016	Change		Change
	(in GWh)				(in %)
Costanera (Argentina)	7,852	5,713	2,140		37.5
El Chocón (Argentina)	2,055	2,574	(520	)	(20.2	)
Dock Sud (Argentina)	4,945	5,025	(80	)	(1.6	)
Cachoeira Dourada (Brazil)	9,526	6,399	3,127		48.9
Fortaleza (Brazil)	2,923	3,049	(125	)	(4.1	)
EGP Volta Grande (Brazil)	137	—	137		100.0
Emgesa (Colombia)	18,156	18,015	141		0.8
Enel Generation Peru (Peru)	9,817	9,091	726		8.0
Enel Generation Piura (Peru)	640	709	(69	)	(9.7	)
Total	56,051	50,575	5,476		10.8

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, 2017 and 2016:

	Electricity sales during the year ended December 31,
	2017	2016	Change		Change
	(in GWh)				(in %)
Edesur (Argentina)	17,736	18,493	(756	)	(4.1	)
Enel Distribution Rio (Brazil)	11,091	11,181	(90	)	(0.8	)
Enel Distribution Ceara (Brazil)	11,522	11,628	(107	)	(0.9	)
Enel Distribution Goias (Brazil)	12,264	—	12,264		n.a
Codensa (Colombia)	13,790	13,632	158		1.2
Enel Distribution Peru (Peru)	7,934	7,782	152		2.0
Total	74,337	62,716	11,621		18.5

112

The following table sets forth the revenues and other operating income from continuing operations, by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2017 and 2016:

	Year ended December 31,
	2017		2016		Change		Change
	(in millions of US$)						(in %)
Generation and Transmission Business in Argentina	300		307		(7	)	(2.4	)
Costanera	152		137		15		11.2
El Chocón	58		42		17		40.0
Dock Sud	88		128		(40	)	(31.0	)
Other	1		1		0		54.8
Generation and Transmission Business in Brazil	829		572		256		44.8
Cachoeira Dourada	503		285		218		76.3
Fortaleza	261		236		26		10.8
Cien	89		77		12		15.0
EGP Volta Grande	9		—		9		n.a.
Other	(33	)	(26	)	(7	)	27.7
Generation and Transmission Business in Colombia	1,160		1,152		8		0.7
Emgesa	1,160		1,152		8		0.7
Generation and Transmission Business in Peru	730		679		52		7.6
Enel Generation Peru	646		587		59		10.1
Enel Generation Piura	87		96		(9	)	(9.3	)
Other	(3	)	(4	)	1		(26.9	)
Total Generation and Transmission Business reportable segment	3,020		2,710		310		11.4
Distribution Business in Argentina	1,223		963		260		27.0
Edesur	1,223		963		260		27.0
Distribution Business in Brazil	4,613		2,472		2,142		86.7
Enel Distribution Rio	1,646		1,285		361		28.1
Enel Distribution Ceara	1,450		1,187		263		22.2
Enel Distribution Goias	1,517		—		1,517		n.a.
Distribution Business in Colombia	1,538		1,361		177		13.0
Codensa	1,538		1,361		177		13.0
Distribution Business in Peru	879		865		14		1.6
Enel Distribution Peru	879		865		14		1.6
Total Distribution Business reportable segment	8,253		5,662		2,592		45.8
Less: consolidation adjustments and non-core activities	(834	)	(729	)	(106	)	14.5
Total Revenues and other operating income	10,438		7,643		2,795		36.6

Generation and Transmission Business:

In Argentina, revenues and other operating income from Costanera increased in 2017, mainly due to (i) US$ 94 million of higher energy revenues attributable to (a) higher physical sales of 2,140 GWh, or 37.5%, compared to 2016 which contributed US$ 31 million and (b) a US$ 69 million increase in tariff remuneration due to the new Resolution No. 19/2017 applied as of February 2017 and (ii) US$ 8 million of revenues recognized due to the recovery of insurance claims for machinery.  This was offset by (i) US$ 78 million lower revenues due to the lower degree of progress in 2017 compared to 2016 of the availability contracts of turbo steam units signed with the Ministry of Electric Energy since the projects are in their final construction stages and (ii) the 12% devaluation of the Argentine peso against the U.S. dollar that resulted in lower revenues of US$ 15 million.

Revenues and other operating income from El Chocón increased in 2017, despite lower generation, mainly due to a US$ 23 million increase in tariff remuneration associated with a new resolution applicable as of February 2017, offset by (i) a decrease in contracted sales of US$ 2 million due to lower energy sales of 520 GWh, or 20%, as a result of lower hydroelectric generation because of lower water availability, and (ii) US$ 5 million as a result of the devaluation of the Argentine peso against the U.S. dollar that resulted in lower revenues of US$ 5 million.

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Revenues and other operating income from Dock Sud decreased in 2017 principally due to a US$ 102 million decrease in other services due to lower fuel recognitions by CAMMESA in relation to 2016 and lower revenues of US$ 14 million as a result of the devaluation of the Argentine peso against the US dollar.  These decreases were offset by a US$ 76 million increase attributable to higher tariffs due to a new resolution.

In Brazil, revenues and other operating income from Cachoeira Dourada increased in 2017 despite lower generation mainly due to a US$ 187 million increase due to higher energy sales of 3,127 GWh predominantly to unregulated customers related to greater market demand, which were principally covered with energy purchases from other generators, and a US$ 26 million increase due to the 8% appreciation of the Brazilian reais against the U.S. dollar.  In addition, Cachoeira Dourada received US$ 5 million in energy contract compensation under the MRE.

Revenues and other operating income from Fortaleza increased in 2017 mostly due to a US$ 21 million increase in energy sales due to a US$ 20 million increase as a result of the appreciation of the Brazilian reais against the U.S. dollar and a US$ 1 million increase due to better average sale prices to distributors as a consequence of tariff updates.  There was also a US$ 5 million increase as a result of the recognition of a fiscal incentive, called Provin, which is an industrial development and incentive program.

Revenues and other operating income from Cien increased in 2017 primarily due to US$ 7 million related to the appreciation of the Brazilian reais against the U.S. dollar and US$ 5 million in higher regulatory revenues.

Revenues and other operating income from EGP Volta Grande contributed US$ 9 million in 2017, arising from 137 GWh in energy sales during December 2017.  There were no EGP Volta Grande contributions to revenues in 2016 because we only started consolidating EGP Volta Grande with its acquisition in November 30, 2017.

In Colombia, revenues and other operating income from Emgesa increased in 2017 and remained relatively stable compared to 2016.  Energy sale revenues increased by US$ 4 million mainly due to a US$ 37 million increase attributable to the 3% appreciation of the Colombian peso against the U.S. dollar and higher energy sales of 141 MW, which contributed US$ 21 million.  This increase was almost completely offset by US$ 42 million lower incomes as a result of lower average sale prices and a US$ 12 million lower incomes for benefits related to lower thermal generation in 2016.  In addition, we received US$ 4 million due to a greater volume of gas sold.

In Peru, revenues and other operating income from Enel Generation Peru increased in 2017 despite lower generation.  This increase in revenues is mostly explained by (i) non-recurrent revenues such as insurance reimbursements of US$ 29 million for weather emergencies and US$ 11 million for the income from the loss of profit mainly related to our Callahuanca (81 MW) and Moyopampa (69 MW) hydroelectric plants, (ii) a US$ 26 million increase in tolls attributable to new unregulated customers, and (iii) US$ 20 million due to the 3% appreciation of the Peruvian sol against the U.S. dollar.  This was offset by US$ 26 million in lower energy sales, despite higher physical sales of 726 GWh, explained by (i) US$ 14 million related to lower average sales prices due to the drop of marginal costs in part related to the oversupply in the system and better hydrology, and (ii) lower energy and capacity sales in the regulated market of US$ 8 million.

Revenues and other operating income from Enel Generation Piura decreased in 2017 mainly due to (i) a US$ 15 million decrease attributable to 69 GWh lower sales due to reduced demand, (ii) a US$ 3 million decrease due to lower average sale prices as a result of the drop in marginal costs, and (iii) lower gas sales of US$ 4 million due to lower production.  These decreases were partially offset by a US$ 11 million increase due to higher toll payments from unregulated customers and a US$ 2 million increase due to the appreciation of the Peruvian sol against the U.S. dollar.

Distribution Business:

In Argentina, revenues and other operating income from Edesur increased in 2017 mainly due to a US$ 439 million increase attributable to higher energy revenues related to Edesur’s new tariffs in effect since February 1, 2017 and US$ 13 million of insurance reimbursements due to weather emergencies in December 2013.  This was partially offset by a US$ 105 million decrease due to the devaluation of the Argentine peso against the U.S. dollar and US$ 63 million lower energy sales of 757 GWh.

In Brazil, revenues and other operating income from Enel Distribution Rio increased in 2017 principally due to (i) a US$ 250 million increase due to tariff recovery, (ii) a US$ 118 million increase due to the appreciation of the Brazilian reais against the U.S. dollar, (iii) a US$ 69 million increase in tolls and transmission, and (iv) US$ 22 million from construction in connection with concession arrangements (IFRIC 12).  This was partially offset by a 90 GWh decrease in physical sales equivalent to US$ 94 million.

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Revenues and other operating income from Enel Distribution Ceara increased in 2017 due to (i) a US$ 143 million increase due to higher income from tariff recoveries, (ii) a US$ 109 million increase due to the appreciation of the Brazilian reais against the U.S. dollar and (iii) a US$ 57 million increase from construction in connection with concession arrangements (IFRIC 12).  This was partially offset by (i) a US$ 41 million decrease from tariff flags recognition (see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Brazilian Electricity Regulatory Framework — Regulation of Distribution Companies — Revenue from Tariff Flags), and (ii) a US$ 16 million decrease due to lower physical sales of 106 GWh.

Revenues and other operating income from Enel Distribution Goias contributed US$ 1,536 million to our consolidated revenues as a result of our acquisition and consolidation of the company as of February 14, 2017.  Enel Distribution Goias’s revenues were mainly comprised of (i) US$ 1,178 million from energy sales equivalent to 12,264 GWh, (ii) other revenue of US$ 256 million mainly corresponding to income from construction in connection with concession arrangements (IFRIC 12) for US$ 239 million and US$ 17 million in regulatory fines and penalties, respectively and (iii) US$ 71 million corresponding to revenues from tolls and transmission.

In Colombia, revenues and other operating income from Codensa increased in 2017 mainly due to a (i) a US$ 81 million increase related to 158 GWh higher physical sales, (ii) a US$ 23 million increase mainly due to higher tariffs due to the inflation effect, (iii) a US$ 10 million increase from other services such as tolls and transmission due to higher rates as a result of inflation, (iv) a US$ 24 million increase for infrastructure rentals, equipment installation and fees from collections orders, and (v) a US$ 45 million increase as a result of the appreciation of the Colombian peso against the U.S. dollar.  The foregoing was offset by a US$ 6 million lower recognition of other operating revenues as a result of the acquisition of Cuindinamarca in 2016.

In Peru, revenues and other operating income from Enel Distribution Peru increased in 2017 mainly due to (i) a US$ 30 million increase due to the appreciation of the Peruvian sol against the U.S. dollar, (ii) a US$ 4 million increase related to network installation and (iii) a US$ 3 million increase in higher tolls by third parties. These increases were partially offset by a US$ 11 million decrease in average sale prices and a US$ 9 million decrease mainly explained by the conversion of medium voltage customers into unregulated customers.

Total Operating Costs from Continuing Operations

Total operating costs from continuing operations consist primarily of energy purchases from third parties, fuel consumption, depreciation, amortization and impairment losses, maintenance costs, tolls paid to transmission companies, employee salaries and administrative and selling expenses.

The following table sets forth consolidated operating costs in U.S. dollars for the years ended December 31, 2017 and 2016:

	Year ended December 31,
	2017		2016
	(in millions of US$)	(in %)	(in millions of US$)	(in %)
Energy purchases	3,940	47.9	2,443	41.5
Fuel consumption	229	2.8	362	6.2
Transportation expense	634	7.7	394	6.7
Other raw materials and combustibles	1,079	13.1	713	12.1
Other expenses(1)	943	11.5	817	13.9
Employee benefit expense and other(1)	665	8.1	527	8.9
Depreciation, amortization and impairment losses(1)	728	8.9	630	10.7
Total Operating Cost from Continuing Operations	8,219	100	5,886	100

(1)Corresponds to selling and administration expenses.

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The following table sets forth our total operating costs (excluding selling and administrative expenses) from continuing operations by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2017 and 2016:

	Year ended December 31,
	2017		2016		Change		Change
	(in millions of US$)						(in %)
Generation and Transmission Business in Argentina	25		88		(63	)	(71.6	)
Costanera	9		8		1		12.9
El Chocón	7		5		2		44.0
Dock Sud	12		78		(66	)	(84.6	)
Other	(3	)	(3	)	0		(5.0	)
Generation and Transmission Business in Brazil	490		269		221		82.4
Cachoeira Dourada	372		149		223		149.6
Fortaleza	147		142		4		2.9
Cien	3		3		(0	)	(9.4	)
EGP Volta Grande	1		—		1		n.a.
Other	(32	)	(26	)	(6	)	24.5
Generation and Transmission Business in Colombia	396		434		(38	)	(8.7	)
Emgesa	396		434		(38	)	(8.7	)
Generation and Transmission Business in Peru	348		347		1		0.3
Enel Generation Peru	314		310		4		1.3
Enel Generation Piura	38		42		(4	)	(9.6	)
Other	(3	)	(4	)	1		(22.3	)
Total Generation and Transmission Business reportable segment	1,259		1,137		122		10.7
Distribution Business in Argentina	687		430		257		59.9
Edesur	687		430		257		59.9
Distribution Business in Brazil	3,323		1,670		1,653		99.0
Enel Distribution Rio	1,190		879		311		35.4
Enel Distribution Ceara	1,019		791		228		28.8
Enel Distribution Goias	1,114		—		1,114		n.a
Distribution Business in Colombia	867		782		85		10.8
Codensa	867		782		85		10.8
Distribution Business in Peru	579		585		(6	)	(1.0	)
Enel Distribution Peru	579		585		(6	)	(1.0	)
Total Distribution Business reportable segment	5,456		3,467		1,989		57.4
Less: consolidation adjustments and non-core activities	(832	)	(736	)	(96	)	13.1
Total operating costs (excluding selling and administrative expenses)	5,883		3,869		2,015		52.1

Generation and Transmission Business:

In Argentina, operating costs of Costanera and El Chocón remained stable in comparison to 2016.  In the case of El Chocón the variation was mainly the result of US$ 1 million higher transportation costs and other variable costs of US$ 1 million.

Operating costs of Dock Sud decreased in 2017 mainly due to a US$ 61 million decrease from lower gas consumption since in 2017 CAMMESA dealt with distributors directly.  The decrease was also the result of the devaluation of the Argentine peso against the U.S. dollar which reduced its costs by US$ 7 million.

In Brazil, operating costs of Cachoeira Dourada increased in 2017 mainly due to a US$ 208 million increase attributable to greater energy purchases as a result of higher sales to unregulated customers and US$ 14 million increase due to the appreciation of the Brazilian reais against the U.S. dollar.

Operating costs of Fortaleza remained relatively stable in comparison to 2016 mainly due to a US$ 14 million increase due to the appreciation of the Brazilian reais against the U.S. dollar partially compensated by a US$ 10 million lower fuel consumption, of which US$ 7 million was attributable to lower prices and US$ 3 million to lower consumption.

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Operating costs of Cien remained stable in comparison to 2016 and operating costs of EGP Volta Grande amounted to US$ 0.8 million as a result of 137 GWh of energy generation during December 2017.

In Colombia, operating costs of Emgesa decreased in 2017 mainly due to (i) reduced energy purchases of US$ 36 million comprised of US$ 62 million related to lower average prices in the spot market (a reductions of CP$54/kWh) as a consequence of better hydrology during 2017 offset by US$ 26 million related to greater physical purchases in the spot market of 344 GWh as a result of slightly lower generation and (ii) a US$ 42 million decrease in fuel consumption composed by US$ 46 million due to the lower thermal generation in the Termozipa and Cartagena plants offset by a US$ 4 million increase due to higher average sale prices.  These decreases were partially offset by (i) a US$18 million increase in transportation costs due to higher generation in the system, (ii) a US$ 15 million increase due to the appreciation of the Colombian peso against the U.S. dollar and (iii) a US$ 8 million increase in other variable procurement and service expenses mainly as a result of a tax effect increase associated with increased hydroelectric generation.

In Peru, operating costs of Enel Generation Peru and Enel Generation Piura remained relatively stable in comparison to 2016.  The increase of costs for Enel Generation Peru was mostly associated with the appreciation of the Peruvian sol against the U.S. dollar.  The decrease of costs for Enel Generation Piura was mostly associated with a lower fuel consumption as a result of its lower generation, which in turn was due to higher hydro generation.

Distribution Business:

In Argentina, operating costs of Edesur increased in 2017 primarily due to a US$ 266 million increase in costs due to higher energy purchases related to inflation adjustments of US$ 291 million, partially offset by a US$ 48 million decrease in costs due to the devaluation of the Argentine peso against the U.S. dollar.

In Brazil, operating costs of Enel Distribution Rio increased in 2017 mainly due to a US$ 236 million increase in energy purchases and higher prices associated with hydrological risk costs coupled with a US$ 82 million increase in costs due to the appreciation of the Brazilian reais against the U.S. dollar

Operating costs of Enel Distribution Ceara increased in 2017 mainly due to a US$ 125 million increase in purchases in the regulated and spot markets to cover the associated increased in demand, a US$ 73 million increase due to the appreciation of the Brazilian reais against the U.S. dollar, a US$ 57 million increase in construction costs in connection with concession arrangements (IFRIC 12) and a US$ 36 million increase in energy transmission costs.  These increases were partially offset by US$ 53 million decrease due to lower prices in regulated industrial tariffs.

Operating costs of Enel Distribution Goias contributed US$ 1,133 million to our consolidated operating costs and were mainly comprised of (i) US$ 796 million in energy purchases to meet demand, (ii) US$ 241 million in constructions costs in connection with concession arrangements (IFRIC 12) and (iii) US$ 75 million in transportation costs.

In Colombia, operating costs of Codensa increased in 2017 predominantly due to a (i) a US$ 52 million increase in energy purchases of 272 GWh compared to the previous year offset by a US$ 27 million decrease in costs due to lower average prices; (ii) a US$ 23 million increase in transportation costs comprised of an increase in energy transportation prices of US$ 82 million offset by a lower use of networks of US$ 59 million, (iii) a US$ 26 million increase due to the appreciation of the Colombian peso against the U.S. dollar, and (iv) a US$ 3 million increase due to higher variable costs associated with new businesses.

In Peru, operating costs of Enel Distribution Peru remained stable compared to 2016 mainly attributable to (i) a US$ 21 million decrease in energy purchases due to lower purchase prices of US$ 17 million and lower physical purchases of US$ 4 million and (ii) US$ 3 million of lower material costs and complementary reconnection services, partially offset by a US$ 22 million increase in costs due to the appreciation of the Peruvian sol against the U.S. dollar.

Selling and Administrative Expenses

Selling and administrative expenses relate to salaries, compensation, administrative expenses, depreciation, amortization and impairment losses, and office materials and supplies.

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The following table sets forth the selling and administrative expenses by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2017 and 2016:

	Year ended December 31,
	2017	2016	Change		Change
	(in millions of US$)				(in %)
Generation and Transmission Business in Argentina	160	128	32		24.6
Costanera	104	81	22		27.4
El Chocón	17	14	2		17.1
Dock Sud	37	30	7		21.9
Other	2	2	0		7.7
Generation and Transmission Business in Brazil	78	64	13		20.8
Cachoeira Dourada	24	19	4		23.1
Fortaleza	26	21	5		24.0
Cien	28	24	4		15.2
EGP Volta Grande	0	—	0		n.a.
Other	0	0	(0	)	(50.5	)
Generation and Transmission Business in Colombia	153	168	(15	)	(9.2	)
Emgesa	153	168	(15	)	(9.1	)
Generation and Transmission Business in Peru	154	161	(7	)	(4.3	)
Enel Generation Peru	131	143	(11	)	(7.9	)
Enel Generation Piura	23	19	4		21.7
Other	0	0	0		n.a.
Other Generation and Transmission Business reportable segment	—	—	—		n.a.
Total Generation and Transmission Business reportable segment	544	521	23		4.3
Distribution Business in Argentina	385	392	(7	)	(1.7	)
Edesur	385	392	(7	)	(1.7	)
Distribution Business in Brazil	947	603	344		57.1
Enel Distribution Rio	346	366	(19	)	(5.3	)
Enel Distribution Ceara	239	237	2		0.9
Enel Distribution Goias	362	—	362		n.a.
Distribution Business in Colombia	259	215	44		20.4
Codensa	259	215	44		20.4
Distribution Business in Peru	126	116	10		8.8
Enel Distribution Peru	126	116	10		8.6
Other Distribution Business reportable segment	—	—	—		n.a.
Total Distribution Business reportable segment	1,718	1,326	392		29.5
Less: consolidation adjustments and non-core activities	74	127	(53	)	(41.5	)
Total selling and administrative expenses	2,336	1,974	361		18.3

Selling and administrative expenses from continuing operations increased in 2017 as compared to 2016, mainly increases from our distribution business.  The main changes are explained below.

Generation and Transmission Business

In Argentina, selling and administrative expenses increased during 2017, mainly Costanera and Dock Sud.  The increase of Costanera is mainly due to a US$ 14 million increase due to a higher depreciation expense in Siemens and Mitsubishi combined cycle power plants and a US$ 9 million increase related to lower workforce capitalizations.  The increase of Dock Sud is mainly due to a US$ 5 million of higher reparations in machinery and maintenance costs.

In Brazil, selling and administrative expenses increased during 2017.  The increase is mainly due to a U$ 5 million increase in depreciation expenses of Fortaleza due to higher capitalizations and a US$ 8 million increase due to the appreciation of the Brazilian reais against the U.S. dollar.

In Colombia, selling and administrative expenses of Emgesa decreased mainly due to a US$ 36 million loss recognized in 2016 for the allowance for Electrocaribe’s uncollectible accounts.  This decrease was partially offset by: (i) US$ 10 million higher in other expenses related to the write-off of non-profitable projects, including Campo Hermoso, Agua Clara and Guaicaramo, (ii) a US$ 6

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million increase in depreciation expense due to higher capitalizations of thermal facilities and (iii) a US$ 4 million increase in payroll expenses associated with higher salary expenses.

In Peru, selling and administrative expenses of Enel Generation Peru decreased in 2017 mainly due to a decrease of US$ 21 million related to the write off of the Curimbamba project in June 2016, partially offset by a US$ 10 million increase in impairment losses due to the deterioration of the Callahuanca power plant as a consequence of a weather emergency in March 2017.  Selling and administrative expenses of Enel Generation Piura increased by US$ 4 million principally due to a US$ 3 million increase in uncollectible provisions.

Distribution Business

In Argentina, due to more favorable regulations, and the effects of the recovery of the economy on our business, we reversed Edesur’s impairment loss that had been recorded in 2011 as a result of the sustained period of uncertainty in the Argentine electricity sector and the lack of distribution tariff adjustments.  The effect of this reversal was a US$ 55 million decrease in our consolidated impairment losses.

In Brazil, selling and administrative expenses increased primarily due to the incorporation of Enel Distribution Goias, which were comprised of US$ 151 million of higher third-party maintenance service costs for lines and networks, US$ 108 million in payroll expenses including US$ 51 million in provisions for the voluntary retirement plan and US$ 84 million in depreciation expense.  Enel Distribution Goias’s impact was offset by a US$ 19 million decrease in Enel Distribution Ceara’s expenses and a US$ 23 million decrease in Enel Distribution Rio’s expenses due to lower provisions for uncollectibility as compared to 2016.

In Colombia, selling and administrative expenses of Codensa increased as compared to 2016, mainly due to: (i) US$ 14 million higher in depreciation expense due to the increase in the substations, lines and networks, (ii) a US$ 14 million increase in third-party maintenance service costs for line and network, (iii) US$ 7 million higher costs related to collection and other services and (iv) US$ 3 million of greater payroll expenses.

In Peru, selling and administrative expenses of Enel Distribution Peru increased mainly due to a US$ 6 million increase related to the appreciation of the Peruvian sol against the U.S. dollar, US$ 3 million of higher depreciation expense due to higher capitalizations, US$ 3 million in uncollectible accounts, partly offset by a US$ 2 million decrease in lower payroll expense due to lower workforce associated with investment projects.

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Operating Income from Continuing Operations

The following table sets forth our operating income from continuing operations by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2017 and 2016:

	Year ended December 31,
	2017		2016		Change		Change
	(in millions of US$)						(in %)
Generation and Transmission Business in Argentina	115		91		24		26.3
Costanera	40		48		(8	)	(16.4	)
El Chocón	55		23		32		140.9
Dock Sud	39		19		20		104.4
Other	(19	)	1		(20	)	n.a.
Generation and Transmission Business in Brazil	262		240		22		9.3
Cachoeira Dourada	107		117		(10	)	(8.2	)
Fortaleza	89		72		16		22.5
Cien	58		50		8		16.3
EGP Volta Grande	7		0		7		n.a.
Other	0		(0	)	0		(100.0	)
Generation and Transmission Business in Colombia	611		550		61		11.0
Emgesa	611		550		61		11.0
Generation and Transmission Business in Peru	229		171		58		34.1
Enel Generation Peru	201		135		67		49.5
Enel Generation Piura	27		36		(9	)	(25.2	)
Other	0		(0	)	0		n.a.
Other Generation and Transmission Business reportable segment	0		0		0		n.a.
Total Generation and Transmission Business reportable segment	1,216		1,051		165		15.7
Distribution Business in Argentina	151		141		10		6.7
Edesur	151		141		10		6.7
Distribution Business in Brazil	342		198		144		72.5
Enel Distribution Rio	109		40		69		172.0
Enel Distribution Ceara	191		158		33		21.0
Enel Distribution Goias	42		0		42		n.a.
Distribution Business in Colombia	412		364		47		13.0
Codensa	412		364		47		13.0
Distribution Business in Peru	174		164		10		6.0
Enel Distribution Peru	174		164		10		6.0
Other Distribution Business reportable segment	0		0		0		n.a.
Total Distribution Business reportable segment	1,079		868		211		24.3
Less: consolidation adjustments and non-core activities	(76	)	(120	)	44		(36.4	)
Total operating income	2,219		1,800		419		23.3

Generation and Transmission Business

Operating income in 2017 was better than in 2016 mainly due to better results of Enel Generation Peru, Emgesa and El Chocón.

In Argentina, a new remuneration scheme was applied as of February 2017 that led to higher operating income for El Chocón, despite its lower generation. Dock Sud faced higher volatility in its revenues and operating costs mainly given that CAMMESA established a pass through of the gas consumption in the case of distributors, which led to higher operating income. Costanera experienced a decrease in operating income due to higher depreciation expenses of its combined cycles and workforce expenses, which were not compensated by the new remuneration scheme.

In Brazil, Cachoeira Dourada sold more energy to non-regulated customers that bought from other generators at a higher price due to the drought, decreasing its operating income.  Fortaleza improved its operating income mainly due to the appreciation of the Brazilian reais against the U.S. dollar coupled with lower fuel costs.  Cien increased its operating income principally as a result of its

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regulatory revenues.  In addition, the acquisition and consolidation of EGP Volta Grande near the end of 2017 also contributed with a positive operating income.

In Colombia, Emgesa’s operating income increased although revenues remained stable, mainly as a consequence of lower energy purchases and fuel consumption due to better hydrological conditions in 2017, in addition to a one-time effect registered in 2016 regarding uncollectible accounts.

Enel Generation Peru increased its operating income mainly due to non-recurrent revenues related to weather emergencies, sales to unregulated customers and the appreciation of the Peruvian sol against the U.S. dollar as well as a project write-off recorded in 2016.  This compensated for lower energy sales, despite higher physical sales, mainly related to a decrease in the marginal costs in the system.

Distribution Business

Operating income increased by 24% in 2017 with respect to 2016, mainly due to better results of our Brazilian subsidiaries.

In Argentina, Edesur’s operating income was positively affected by the new tariff applied since February 2017.

In Brazil, Enel Distribution Rio and Enel Distribution Ceara improved their operating income mainly due to annual tariff adjustments and to a lesser degree to the appreciation of the Brazilian reais against the U.S. dollar.  Operating costs also increased as a result of higher demand, but to a lesser extent.

In Colombia, Codensa improved its operating income mainly due to higher physical sales, higher tariffs due to inflation adjustments and lower average prices for energy purchased as a consequence of the better hydrology during the year.

Enel Distribution Peru improved its operating income mainly as a result of the appreciation of the Peruvian sol against the U.S. dollar which compensated for the negative effect of lower average prices and the migration of medium voltage customers that decided to be unregulated customers.

Other Results from Continuing Operations

The following table sets forth the other results from continuing operations for the years ended December 31, 2017 and 2016:

	Year ended December 31,
	2017		2016		Change		Change
	(in millions of US$)						(in %)
Financial results
Financial income	294		276		17		6.3
Financial costs	(870	)	(773	)	(96	)	12.5
Results from indexed assets and liabilities	0		(1	)	1		(100.0	)
Net foreign currency exchange gains (losses)	(7	)	59		(66	)	(111.4	)
Total	(582	)	(439	)	(144	)	32.7
Other
Other gains (losses)	6		12		(6	)	(47.7	)
Share of the profit of associates and joint ventures accounted for using the equity method	3		3		1		22.3
Total	9		15		(6	)	(41.7	)
Total other results	(574	)	(424	)	(150	)	35.3

Financial Results from Continuing Operations

Our net total financial results in 2017 were a higher net loss when compared to the loss registered in 2016.  The variation is mainly explained by:

·an increase in financial costs of US$ 96 million in 2017 mainly due to (i) US$ 91 million from the consolidation of Enel Distribution Goias, (ii) a US$ 26 million increase in Edesur, of which US$ 23 million is due to the devaluation of

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the Argentine peso against the U.S. dollar, US$ 30 million from litigation and fines provisions updates, offset by a US$ 20 million decrease for capitalized financial expense due to the completion of projects during 2016 and a US$ 7 million decrease in debt balances with CAMMESA and (iii) a US$ 25 million increase in Enel Distribution Rio mainly due to a US$ 30 million settlement of portfolio sale, US$ 10 million increase in expenses of regulated asset and liabilities and US$ 2 million for accrued interest from bank loans, offset by US$ 17 million lower accrued interest from bond.  These increases were partially offset by US$ 42 million of lower financial costs in Emgesa due to lower outstanding amount of bonds related to El Quimbo project.

·a decrease in foreign currency exchange gains (losses) of US$ 66 million in 2017 mainly due to a US$ 37 million decrease in positive foreign exchange differences in the foreign currency denominated debt of Enel Brasil and US$ 16 million associated with bank loans of Enel Distribution Rio.

Other Non-Operating Results from Continuing Operations

Other non-operating results decreased compared to 2016, predominantly due to other gains in Enel Generation Peru from the sale of high-tension transmission lines recorded in 2016.

Income Taxes

Total income tax expense remained relatively stable in 2017, as compared to 2016.  The most significant changes correspond to positive records in Edesur for US $ 68 million corresponding to the recognition in 2017 of deferred taxes for tax losses due to better future regulatory conditions and to the recognition in El Chocón of US $ 27 million for deferred income due to a tax contingency.  This was offset by higher expenses in Enel Américas of US $ 44 million, mainly due to the effects registered in 2016 of the exchange rate of foreign investments and the effects of inflation for US $ 96 million and US$ 55 million, respectively, as a result of the change of our functional currency to the U.S. dollar in 2017, offset by the recognition of US$ 107 million tax credits and higher expenses in Emgesa of US $ 34 million, due to better taxable results compared to 2016.

The effective or statutory tax rate was 31.6% in 2017 and 38.6% in 2016.  This decrease is mainly due to the recognition of deferred taxes in Edesur.

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 and tax rates (10.9% for 2017 and 12% for 2016) enacted in each foreign jurisdiction:

	Tax Rates (%)		Tax effect of rates applied in other countries (in millions of US$)
	2017	2016	2017		2016
Argentina	35.0	35.0	(11.9	)	(8.8	)
Brazil	34.0	34.0	(28.5	)	(30.8	)
Colombia	40.0	40.0	(123.0	)	(113.2	)
Peru	25.5	29.5	(16.3	)	(12.9	)
			(179.7	)	(165.7	)

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Net Income

The following table sets forth our consolidated net income from continuing operations before income taxes, income taxes and net income from continuing operations for the years ended December 31, 2017, and 2016.

	Year ended December 31,
	2017		2016		Change		Change
	(in millions of US$)						(in %)
Operating income	2,219		1,800		419		23.3
Other results	(574	)	(424	)	(150	)	n.a.
Income before income taxes	1,646		1,376		270		19.6
Income taxes	(519	)	(531	)	12		(2.3	)
Net Income	1,127		845		282		33.4
Income after tax from discontinued operations	0		170		(170	)	(100.0	)
Net income attributable to:	1,127		1,015		112		11.0
Net income attributable to the parent company	709		566		143		25.2
Net income attributable to non-controlling interests	418		448		(30	)	(6.7	)

B.Liquidity and Capital Resources.

Our main assets are the stocks of our subsidiaries. The following discussion of cash sources and uses reflects the key drivers of our cash flow.

We, on a stand-alone basis, receive cash inflows from our subsidiaries, as well as from related companies. Our subsidiaries and associates’ cash flows may not be available to satisfy our own liquidity needs, mainly because they are not wholly-owned, and also because there is a time lag before we have effective access to those funds through dividends or capital reductions. However, we believe that cash flow generated from our business operations, as well as cash balances, borrowings from commercial banks, and ample access to the capital markets will be sufficient to satisfy all our needs for working capital, debt service, dividends and routine capital expenditures in the foreseeable future.

Our statement of cash flows for 2016 includes cash flows for two months from the discontinued Chilean businesses as a result of the separation of businesses that occurred on March 1, 2016. In comparison, the statement of cash flow for 2017 and 2018 does not include cash flows from the discontinued Chilean businesses. On March 1, 2016, we transferred all of our ownership in the Chilean businesses to a newly formed affiliate, Enel Chile.

Set forth below is a summary of our consolidated cash flow information (including both continued and discontinued operations) for the years ended December 31, 2018, 2017 and 2016.

	Year ended December 31,
	2018		2017		2016
	(in millions of US$)
Net cash flows provided by operating activities	1,845		1,870		2,532
Net cash flows used in investing activities	(3,069	)	(2,479	)	(735	)
Net cash flows from (used in) financing activities	1,867		(589	)	(1,094	)
Net increase (decrease) in cash and cash equivalents before effect of exchange rates changes	642		(1,198	)	703
Effects of exchange rate changes on cash and cash equivalents	(211	)	(19	)	114
Cash and cash equivalents at beginning of period	1,473		2,689		1,872
Cash and cash equivalents at end of period	1,904		1,473		2,689

Set forth below is a summary of the net cash flow attributable to discontinued operations for the two months ended February 29, 2016. The statement of cash flow for 2018 and 2017 does not include cash flows from the discontinued Chilean businesses.

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	Two months ended February 29,
	2017
	(in millions of US$)
Net cash flows provided by operating activities	225
Net cash flows used in investing activities	(68	)
Net cash flows used in financing activities	(130	)
Net increase (decrease) in cash and cash equivalents before effect of exchange rates changes	26
Effects of exchange rate changes on cash and cash equivalents	3
Cash and cash equivalents at beginning of period	203
Cash and cash equivalents at end of period	232

For the year ended December 31, 2018, net cash flow provided by operating activities was US$ 1,845 million, a US$ 26 million decrease, or 1%, remaining stable compared to 2017. Even when the operating cash flow remained stable, as a consequence of the acquisition of Enel Distribution Sao Paulo, there were some lines within this operating cash flow showing significant variations. The main drivers of the aggregate decrease in 2018 are as follows:

(i)a US$ 2,127 million increase in payments to suppliers for goods and services mainly related to:

(i)US$ 1,919 million from Enel Brasil, on a consolidated basis, explained by

(a)US$ 1,468 million from Enel Distribution Sao Paulo as a result of our acquisition in 2018;

(b)US$ 205 million from Enel Distribution Goias explained by an increase in energy purchases due to higher customers’ demand;

(ii)US$ 105 million from Enel Distribution Ceara explained by an increase in energy purchase costs due to a higher demand and an increase in tolls paid to transmission companies;

(iii)US$ 80 million from Cachoeira Dourada due to a higher energy purchases;

(iv)US$ 63 million from Enel Distribution Rio due to a higher demand and an increase in tolls paid to transmission companies;

(v)US$ 208 million from Codensa due to an increase in the energy purchase due to inflation and an increase in the prices of energy transport; and

(vi)US$ 88 million from Emgesa due to an increase in energy purchases in the spot market and an increase in fuel costs.

All of which were partially offset by a US$ 162 million decrease in Edesur operating cash outflows due to the change in the hyperinflation foreign exchange conversion methodology (for further details associated to the recognition of Argentina as an hyperinflationary economy, 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” — d. Economic Conditions — Hyperinflation in Argentina”.

(ii)a US$ 1,598 million increase in other payments for operating activities mainly attributable to payments of US$ 1,768 million from Enel Distribution Sao Paulo, commencing with our 2018 acquisition, mainly associated with 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 — Regulation of Distribution Companies — Energy Development Account, “Cuenta de Desarrollo Energético - CDE”). This increase in payments was partially offset by:

1.lower other payments of US$ 102 million in Edesur due to the application of IAS 29, which compensated the higher payments of US$ 25 million, and

2.lower payments of US$ 52 million in Codensa Hogar, a program for our residential customers for the acquisition of products and services marketed by various business partners.

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This was offset by an increase in collections from the sale of goods and services of US$ 3,531 million, mainly comprised of:

(i)US$ 3,526 million from Enel Brasil, on a consolidated basis, explained by

1.US$ 3,407 million from Enel Distribution Sao Paulo as a result of its acquisition in 2018; and

2.US$ 281 million from Enel Distribution Goias explained by an increase in energy sales.

This was partially offset by:

1.US$ 155 million lower collections from Enel Distribution Ceara due to the depreciation of the Brazilian reais against the U.S. dollar;

2.US$ 192 million from Emgesa due to a 388 GWh increase of energy sale and higher tariff; and

3.US$ 127 million from Codensa due to higher average price of energy; partially offset by

4.US$ 407 million from Edesur due to the application of IAS 29.

For the year ended December 31, 2017, net cash flow provided by operating activities was US$ 1,870 million, a US$ 662 million decrease, or 26%, compared to US$ 2,532 million for the same period of 2016.  The main drivers of this change are described below.

The decrease in cash flow provided by operating activities was due to:

(i)a US$ 1,315 million increase in other payments for operating activities mainly attributable to:

1.payments of US$ 1,012 million associated with 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 — Regulation of Distribution Companies — Energy Development Account, “Cuenta de Desarrollo Energético - CDE”) by Enel Distribution Goias,

2.higher payments of US$ 114 million in Codensa Hogar, a program for our residential customers for the acquisition of products and services marketed by various business partners,

3.higher payments of US$ 70 million of VAT and municipal and other taxes by Edesur, and

4.higher VAT and other tax payments and payments to the Energy Development Account of US$ 77 million by Enel Distribution Ceara;

(ii)a US$ 208 million increase in payments to and on behalf of employees of mainly attributable to US$ 174 million from Enel Distribution Goias as a result of its acquisition and consolidation; and

(iii)a US$ 2,063 million increase in payments to suppliers for goods and services mainly related to:

1.US$ 1,472 million from Enel Brasil, on a consolidated basis, explained by (a) US$ 961 million from Enel Distribution Goias as a result of its acquisition and consolidation; (b) US$ 209 million from Cachoeira Dourada explained by an increase in energy purchases due to higher unregulated customers’ demand; (c) US$ 155 million from Enel Distribution Rio explained by an increase in energy purchase costs due to an increase in market prices as a consequence of the drought; and (d) US$ 138 million from Enel Distribution Ceara due to higher energy purchase costs also as a consequence of the drought;

2.US$ 438 million from Edesur due to an increase in energy purchase prices related to local inflation; and

3.US$ 115 million from Codensa due to an increase in the energy purchase due to inflation and an increase in the prices of energy transport.

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This was partially offset by an increase in collections from the sale of goods and services of US$ 3,294 million, mainly comprised of:

(i)US$ 2,689 million from Enel Brasil, on a consolidated basis, explained by (a) US$ 2,050 million from Enel Distribution Goias as a result of its acquisition and consolidation since February 14, 2017; (b) US$ 249 million from Cachoeira Dourada due to a 3,127 GWh increase of energy sales due to a greater market demand, mainly from unregulated customers, despite the lower generation; (c) US$ 195 million from Enel Distribution Ceara due to tariff recovery; and (d) US$ 152 million from Enel Distribution Rio mainly as a result of tariff recovery;

(ii)US$ 348 million from Edesur due to higher energy revenues related to new tariffs effective since February 1, 2017; and

(iii)US$ 242 million from Codensa mainly due a 158 GWh increase in physical sales and an increase in tariffs as an effect of inflation.

These operating cash inflows and outflows were offset by a net outflow of US$ 303 million related to collections from the sale of goods and services and payments to suppliers from the discontinued operations of Enel Generación Chile and Enel Distribución Chile, which as a result of the separation of the Chilean and non-Chilean businesses are no longer consolidated by us since March 1, 2016.

For further information regarding our operational results in 2018, 2017 and 2016, please see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2018 and 2017” and “— 3. Analysis of Results of Operations for the Years Ended December 31, 2017 and 2016.”

For the year ended December 31, 2018, net cash used in investing activities was US$ 3,069 million, a 24% increase in comparison to the same period of 2017, mostly explained by:

(i)US$ 1,590 million for the acquisition of Enel Distribution Sao Paulo by Enel Brasil;

(ii)US$ 790 million for the incorporation of intangible assets (under IFRIC 12) of our Brazilian distribution subsidiaries;

(iii)US$ 750 million investments on fixed assets realized by our subsidiaries, mainly explained by US$ 316 million from Codensa, US$ 111 million from Enel Distribution Peru, US$ 90 million from Emgesa, US$ 87 million from Edesur, US$ 56 million from Enel Generation Peru and US$ 42 million from Dock Sud.

For the year ended December 31, 2017, net cash used in investing activities was US$ 2,479 million, mostly explained by:

(i)US$ 720 million for the acquisition of Enel Distribution Goias by Enel Brasil;

(ii)US$ 688 million for the incorporation of intangible assets (under IFRIC 12) of our Brazilian distribution subsidiaries;

(iii)US$ 436 million for the acquisition of Volta Grande by Enel Brasil;

(iv)US$ 682 million investments on fixed assets realized by our subsidiaries mainly: US$ 251 million from Codensa, US$ 122 million from Edesur, US$ 109 million from Emgesa, US$ 78 million from Enel Distribution Peru; and

(v)US$ 81 million for the purchase of a minority stake in Enel Distribution Peru by Enel Perú, a holding company in Peru.

This was partially offset by interest received of US$ 101 million from continuing operations.

For further information regarding the acquisition of fixed assets in 2018 and 2017, 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, 2018, net cash from financing activities amounted to US$ 1,867 million, a US$ 2,456 million increase compared to the US$ 589 million used in 2017. The main drivers of this change are described below.

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The aggregate cash inflows from financing activities were primarily due to:

(i)US$ 2,686 million in loans from our affiliate EFI (US$ 2,501 for Enel Brasil, US$ 108 million for Enel Distribution Sao Paulo and US$ 77 million for Enel Distribution Ceara).

(ii)US$ 1,405 million in bonds issued by Enel Brasil’ subsidiary Enel Sudeste, the vehicle through which we acquire Enel Distribution Sao Paulo, to refinance our acquisition of Enel Distribution Sao Paulo;

(iii)US$ 1,060 million in bonds issued by Enel Brasil to refinance the acquisition of Enel Distribution Sao Paulo;

(iv)US$ 729 million in bonds issued by Enel Distribution Sao Paulo;

(v)US$ 350 million in loans granted to us, on an individual basis;

(vi)US$ 287 million in loans and bonds granted to/issued by Enel Distribution Ceara;

(vii)US$ 287 million in loans and bonds granted to/issued by Enel Distribution Goias;

(viii)US$ 194 million in bonds issued by Codensa; and

(ix)US$ 136 million in loans granted to Enel Distribution Rio.

The aggregate cash outflows were primarily due to:

(i)US$ 4,301 million of payments of loans and bonds (including US$ 1,439 million paid by Enel Sudeste, US$ 1,005 million by Enel Distribution Sao Paulo, US$ 1,064 million by Enel Brasil, US$ 207 million by Enel Distribution Ceara, US$ 135 million by Enel Distribution Goias, US$ 182 million by Emgesa and US$ 103 million by Codensa);

(ii)US$ 592 million in dividend payments to third parties, excluding dividends paid to us (including US$ 354 million from us, on a stand-alone basis, US$ 105 million from Emgesa, US$ 78 million from Codensa, US$ 31 million from Enel Generation Peru, US$ 7 million from Enel Distribution Peru, among others); and

(iii)US$ 440 million of interest expense (including US$ 109 million paid by Emgesa, US$ 54 million by Enel Distribution Sao Paulo, US$ 51 million by Codensa, US$47 million by Enel Distribution Rio, US$ 31 million by us, US$ 29 million by Enel Brasil, US$ 16 million by EGP Volta Grande, US$ 27 million by Enel Distribution Ceara, and US$ 31 million by Enel Distribution Goias).

For the year ended December 31, 2017, net cash used in financing activities decreased to US$ 589 million, a US$ 505 million decrease compared to US$ 1,094 million for 2016. The main drivers of this change are described below.

The aggregate cash outflows were primarily due to:

(i)US$ 1,128 million of payments of loans and bonds (including US$ 342 million by Enel Distribution Rio, US$ 222 million by Enel Distribution Ceara, US$ 182 million by Codensa, US$ 138 million by Enel Distribution Goias, US$ 116 million by Emgesa, US$ 45 million by Enel Distribution Peru, US$ 27 million by Dock Sud, US$ 22 million by Enel Generation Peru and US$ 22 million by Chinango, among others);

(ii)US$ 544 million in dividend payments to third parties, excluding dividends paid to us (including US$ 287 million from us on a stand-alone basis, US$ 106 million from Emgesa, US$ 98 million from Codensa, US$ 13 million from El Chocón, US$ 12 million from Enel Distribution Ceara, US$ 9 million from Enel Generation Peru, US$ 9 million from Enel Distribution Peru, among others); and

(iii)US$ 344 million of interest expense (including US$ 126 million by Emgesa, US$ 52 million by Enel Distribution Rio, US$ 42 million by Codensa, US$ 29 million by Enel Distribution Ceara, US$ 29 million by Enel Distribution Goias , US$ 27 million by Enel Distribution Peru US$ 26 by us, among others).

The aggregate cash inflows from financing activities were primarily due to:

(i)US$ 390 million in loans and bonds granted to/issued by Enel Distribution Rio;

(ii)US$ 287 million in loans and bonds granted to/issued by Enel Distribution Ceara;

(iii)US$ 264 million in loans and bonds granted to/issued by EGP Volta Grande;

(iv)US$ 250 million in bonds issued by Codensa;

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(v)US$ 173 million in loans granted to Enel Distribution Goias;

(vi)US$ 61 million in loans granted to Fortaleza; and

(vii)US$ 34 million in loans granted to Emgesa.

For a description of liquidity risks resulting from the inability of our subsidiaries to transfer funds, please see “Item 3. Key Information — D. Risk Factors — We depend on payments from our subsidiaries and associates to meet our payment obligations.”

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 financially support our subsidiaries. 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 our contractual obligations table set forth below under “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations.  Notwithstanding our corporate policy in connection with the expectation of financial autonomy for our subsidiaries, we have in the past, and to a very limited extent, provided financial support to our foreign subsidiaries.

As of December 31, 2018, our consolidated debt totaled US$ 8,917 million, including US$ 2,652 million in debt that Enel Brasil incurred with EFI.  These funds were used to refinance promissory notes held by Enel Brasil and Enel Sudeste issued for the purchase of Enel Distribution Sao Paulo.

Our consolidated interest-bearing debt had the following maturity profile:

(i)	US$ 4,295 million in 2019 (including debt with EFI);
(ii)	US$ 1,823 million from 2020 to 2021;
(iii)	US$ 1,164 million from 2022 to 2023; and
(iv)	US$ 1,634 million thereafter.

Set forth below is a breakdown by country for debt maturing in 2019:

(i)	US$ 3,397 million for Brazil (including debt with EFI);
(ii)	US$ 390 million for Colombia;
(iii)	US$ 363 million for Chile
(iv)	US$ 131 million for Peru; and
(v)	US$ 14 million for Argentina.

We have accessed the international equity capital markets (including several SEC-registered ADS issuances by our predecessor) in 1993, 1996, 2000, 2003 and 2013. We have also issued bonds for US$ 1,750 million in the United States (“Yankee Bonds”) since 1996.

The following table lists our Yankee Bonds outstanding as of December 31, 2018.

				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				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.

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The following table lists Emgesa’s bond issued in the United States but denominated in Colombian pesos.

				Aggregate Principal Amount
Issuer	Term	Maturity	Coupon (inflation adjusted rate)	Issued	Outstanding
			(%)	(in billions of CP$)	(in billions of CP$)	(in millions of US$)(1)
Emgesa	10 years	January 2021	9.11	737	737	227

(1)Calculated based on the Observed Exchange Rate as of December 31, 2018, which was CP$ 3,250 per US$ 1.00.

We, as well as 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.

The following table lists UF-denominated Chilean bonds issued by us outstanding as of December 31, 2018.

				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	0.6	23

For a full description of local bonds issued by us, see “Secured and unsecured liabilities by company” in Note 21 of the Notes to our consolidated financial statements.

The following table lists local bonds issued by our foreign subsidiaries, outstanding as of December 31, 2018. 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	September 2025	7.50	914
Emgesa	May 2030	7.74	857
Codensa	April 2030	7.04	509
Enel Distribution Peru	November 2038	6.27	393
Enel Distribution Ceara	June 2025	8.63	251
Enel Distribution Rio	December 2020	7.38	155
Enel Distribution Goias	October 2019	6.96	52
Enel Generation Peru	January 2028	6.47	43
Total			3,173

(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, 2018.

We frequently participate in the international commercial bank markets through syndicated senior unsecured loans, including both fixed term and revolving credit facilities. Most recently on February 14, 2018, we entered into a 3-year senior unsecured revolving credit agreement for a total of US$ 500 million. The facility is governed by the laws of the State of New York and is “fully committed,” meaning that a potential Material Adverse Effect (as contractually defined) would not be an impediment to a future drawdown.  We enlarged the principal of the facility twice in 2018 and the outstanding principal is US$ 1 billion, of which US$ 650 million were undrawn as of December 31, 2018, as shown below:

Borrower	Type	Maturity	Facility Amount	Amount Drawn
			(in millions of US$)	(in millions of UF$)
Enel Américas	Syndicated revolving loan	February 2021	1,000	350

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We also borrow from banks in Chile under fully committed facilities. In 2016, we entered into 3-year bilateral revolving loans for an aggregate amount of UF 2.8 million (US$ 113 million as of December 31, 2018), which expired in March 2019.

Our subsidiaries also have access to fully committed credit lines in the local markets, as detailed below.

Borrower	Type	Last Maturity	Facility Amount	Amount Drawn
			(in millions of US$)	(in millions of US$)
Enel Distribution Peru	Bilateral revolving loan	September 2019	67	—
Codensa	Bilateral revolving loan	January 2019	66	—
Enel Brasil	Bilateral revolving loan	May 2019	65	—
Emgesa	Bilateral revolving loan	December 2019	62	—
Enel Distribution Rio	Bilateral revolving loan	June 2019	52	—
Enel Distribution Sao Paulo	Bilateral revolving loan	May 2019	52	—
Enel Distribution Ceara	Bilateral revolving loan	May 2019	49	—
Enel Generation Peru	Bilateral revolving loan	September 2019	30	—
Enel Distribution Goias	Bilateral revolving loan	May 2019	26	—
Cachoeira Dourada	Bilateral revolving loan	May 2019	13	—
Fortaleza	Bilateral revolving loan	May 2019	13	—
Cien	Bilateral revolving loan	May 2019	8	—
Enel X Brasil	Bilateral revolving loan	May 2019	5	—
Total			506	—

As a result of the foregoing, we have access to fully committed undrawn revolving loans, both international and domestic, for up to US$ 1,269 million in the aggregate as of December 31, 2018.

We also may borrow routinely from uncommitted Chilean bank facilities. Unlike the committed lines described above, these facilities are subject to greater risk of not being disbursed in the event of a Material Adverse Effect, and therefore could limit our liquidity under such circumstances. Our subsidiaries also have access to uncommitted local bank facilities, for a total amount of US$ 328 million, which were completely undrawn as of December 31, 2018.

We may also access the Chilean commercial paper market under programs that have been registered with the Chilean CMF for a maximum of US$ 200 million. In addition, we have a Chilean bond program registered with the CMF for UF 12.5 million (US$ 496 million as of December 31, 2018), which has not been drawn upon yet. In addition, on January 22, 2018, we filed a new indenture with the local Chilean CMF that will allow us to issue local bonds for a total amount of UF 15 million (US$ 595 million), for a tenor up to 30 years commencing from the indenture’s registration. Finally, our foreign subsidiaries also have access to other types of financing, including governmental facilities, supplier credit and leasing, among others.

Except for our SEC-registered Yankee Bonds, which are not subject to financial covenants, our outstanding debt facilities include financial covenants. The types of financial covenants, and their respective limits, vary from one type of debt to another. As of December 31, 2018, the most restrictive financial covenant affecting us was the Leverage Ratio, corresponding to the Series B2 local bonds due June 2022. Under such covenant, the maximum additional debt that could be incurred without a breach is US$ 1,219 million. As of December 31, 2018 and as of the date of this Report, we and our subsidiaries are in compliance with the covenants contained in our debt instruments.

As is customary for certain 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, as well as 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 bank credit agreement due February 2021 may be triggered by another debt of ours or of one of our subsidiaries if a matured default on an individual or aggregate basis has an outstanding principal exceeding US$ 150 million.

Cross default provisions of our Yankee Bonds 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. In the case of a matured default above the materiality threshold, Yankee bondholders would have the option to accelerate 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. Our local bonds do not have subsidiary cross default provisions.

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.

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Our subsidiaries have access to existing credit lines sufficient to satisfy all of their present working capital needs. However, during part of 2016, access to the capital markets on the part of our Brazilian subsidiaries was very limited due to the financial situation prevailing in Brazil. Nevertheless, in 2016 and 2017, our Brazilian subsidiaries accessed the financial markets through several financing transactions. In particular, they accessed the debt capital market and entered into bilateral loans at competitive market rates.  More recently during 2018, we supported our Brazilian subsidiaries through guarantees for the acquisition of Enel Distribution Sao Paulo. For further details, please refer to “Item 7. Major Shareholders and Related Party Transactions — B. Related Party Transactions.”

Payment of dividends and distributions by our subsidiaries and affiliates represent an important 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, and capital and retained earnings criteria, and other contractual restrictions. Legal counsel in the countries where our subsidiaries and affiliates operate have informed us of the current legal restrictions regarding the payment of dividends or distributions to us in the jurisdictions where such subsidiaries or affiliates are incorporated. We are currently in compliance with legal restrictions, and therefore, they currently do not affect the payment of dividends or distributions to us. Certain credit facilities and investment agreements of our subsidiaries or affiliates restrict the payment of dividends or distributions in certain special circumstances. For a description of liquidity risks resulting from our company status, please see “Item 3. Key Information — D. Risk Factors —We depend on payments from our subsidiaries and associates to meet our payment obligations.”

Our estimated capital expenditures for 2019 through 2021 amount to US$ 5,329 million.  The amount includes, among others, maintenance capital expenditures, investments in expansion projects under execution and capital expenditures. The latter includes expansion projects that are still under evaluation, in which case we would undertake them only if deemed profitable.

We do not currently anticipate liquidity shortfalls affecting our ability to satisfy the material obligations described in this Report.

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.

C.Research and Development, Patents and Licenses, etc.

None.

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D.Trend Information.

Our businesses are subject to a 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, which aims at controlling relevant variables, reducing risks and providing stability to our results of operations.

Generation

Our operating income is primarily affected by contractual electricity prices and obligations, prevailing hydrological conditions, fuel prices, spot market prices and governmental regulations.

Sales prices and energy costs in each market where we operate are among the main drivers of our results of operations.  For our ongoing businesses, the quantity of electricity sold has been generally stable over time, with increases reflecting economic and demographic growth.  Our profits from contracted sales depend on our ability to generate or buy electricity at a cost lower than contracted sale prices.  However, the applicable price for electricity sales and purchases in the spot market is much harder to predict because the spot generation price is influenced by many factors, including hydrology and fuel prices, which can differ significantly in each of the countries where we operate.  Abundant hydrological conditions generally lower spot prices, while dry conditions increase them, although this effect on prices may be partly mitigated with NCRE generation.

Our operating income might not be impacted adversely even when we are required to buy electricity at high prices in the spot market if our commercial policy is appropriately managed.  We mitigate our exposure to the volatility of the spot market by contracting a significant portion of our expected electricity generation through long term electricity supply contracts.  The optimal level of electricity supply commitments protects us against low marginal cost conditions, such as those existing during a rainy season, while still taking advantage of high marginal cost conditions, such as higher spot market prices during dry years.  In order to determine the optimal mix of long term contracts and sales in the spot market, we project our aggregated generation taking into consideration our generation mix, the incorporation of new projects under construction and various hydrological scenarios.  We then create demand estimates using standard economic theory and forecast the system’s marginal cost using proprietary stochastic models.  This commercial policy is not applicable in Argentina, where contracted sales are immaterial and our margin is strongly dependent on the regulatory framework.

Prices for commodities such as fuel oil, coal and LNG also have an impact on electricity spot prices.  Fuel prices directly affect generation costs of some of our thermal power plants, mainly in upcoming years in Argentina due to the liberalization of the market, although this is mitigated by the fact that in Colombia and Brazil, most of our capacity is hydroelectric, and in Peru, where 60% of our capacity is thermal, the LNG (the main fuel supply) has a regulated price.  Commodity prices, mainly oil, have significantly increased since their lowest level in the first quarter of 2016 and we expect the trend to continue into 2019.  To mitigate the risk of increasing fuel costs we have included indexing polynomials into long-term tender processes with regulated clients and entered into supply contracts to cover part of the fuel needed to operate our thermal generation units.  In Colombia, we expect an increase in the fuel cost of our Termozipa thermal power plant, which uses Colombian coal, mainly due to new production requirements of the mining authority.

In the event that LNG is unavailable at reasonable prices, as has been the case in Peru for specific short periods, we sometimes resort to other fuels.  This is becoming more important as there is an increasing trend to penalize fuel intensive technologies, such as coal and diesel, which have greater environmental impacts.  Due to the material delay in the commissioning schedule of the Peruvian gas pipeline, Gasoducto Sur Peruano, to be built in southern Peru, we expect that thermal power plants may instead use diesel fuel, which would lead to higher energy prices in the system.  The Peruvian government is working on a parallel plan which would use LNG supplied by ships and make use of a floating regasification plant, which could alleviate the problem temporarily.  However, our expectation is that LNG prices in Peru will increase.  In addition, changes to the regulatory framework currently under discussion may affect thermal power plant gas prices, which may also increase spot prices. Given our net purchasing position in the spot market, the cost of our purchases to supply our contracts would increase in such a scenario.

This general framework applies to most countries where we operate, with some country-specific considerations.  In Argentina, the electricity market has been highly regulated and electricity prices are determined by CAMMESA.  Approximately 70% of our Argentine installed capacity is thermal and CAMMESA has been the sole fuel supplier for thermal generation operations.  Other market agents have not been allowed to trade fuel and, as a result, fuel and commodity prices do not have a direct impact on our operations since we have been receiving the needed fuel directly from CAMMESA without any impact in our costs.  However, this scheme is expected to change radically since the Argentine government recently announced that the liberalization of the electricity industry, including the fuel market, will be carried out in 2019.  The new remuneration scheme for generators will be based on average costs for generation companies, establishing payments for fixed and variable costs depending on the technology, the power plant size and the type of fuel, returning to the marginal price and capacity system in place in 2001.  Based on governmental declarations, we

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expect that the marginal price mechanism will increase variable remuneration but decrease fixed remuneration for capacity.  Steam turbines and other older and more inefficient technologies will evidence lower results, while efficient thermal generators should improve their results. In the short-term future, generators will also have the possibility to buy their own fuel; therefore, local fuel prices will have an impact on electricity prices and generation costs.

In Brazil, Fortaleza has a contract with Petrobras, under which the gas supply was supposed to be guaranteed until 2023 at a defined price. However, in February 2018, Petrobras suspended the gas supply, claiming a price imbalance compared to prevailing market conditions, and Fortaleza has been out of service for several months. Fortaleza has a power purchase agreement (PPA) with Enel Distribution Ceara for all of its generation until 2023, when Fortaleza’s concession will end.  To avoid a breach of that contract, Fortaleza bought the required electricity in the spot market.  Since September 2001, the Brazilian government has allowed the power plant to receive all the needed fuel until the end of the PPA period, but there are important unresolved matters. During 2018, Fortaleza’s operating costs considerably increased due to higher energy purchases resulting from the Petrobras gas supply stoppage, which forced the company to purchase energy in the market in order to fulfill its contractual obligations with Enel Distribution Ceara, which had contracted to buy all of Fortaleza’s generation until 2023. See Note 5.a. — Brazil — Enel Generation Fortaleza in the notes to consolidated financial statements for further information about the gas supply stoppage.

In Colombia, 88% of our own installed capacity is hydroelectric and market prices are significantly affected by hydrological conditions, which are very difficult to predict.  Electricity prices are highly volatile and could be affected by a potential El Niño phenomenon.   Hidroituango (2,400 MW of installed hydroelectric capacity) was expected to begin operations in late 2018 and to decrease spot prices.  However, the project has been delayed and the commissioning date is uncertain as of the date of this Report.  We expect energy prices in the Colombian NIS to increase. It is expected by the end of 2021 that the first two units will begin to operate, with two units beginning operations each year thereafter. As a result, by the end of 2024 the hydroelectric plant is expected to be generating energy with all eight units.

In Peru, during 2018, the proportion of unregulated sales continued to increase in relation to contracted sales with distribution companies, a trend which is generally favorable for us.  Many customers have chosen to be unregulated because of the current lower energy prices prevailing in the Peruvian market, which in turn is due to an oversupply of energy.  The Peruvian regulator is promoting a new regulatory framework through measures with generators that seek a more predictable demand from distributors by reducing migration between regulated and unregulated customers, especially when prices are expected to increase from 2021 due to the termination of the oversupply.  We expect these measures to affect our profitability adversely.  For 2019, a slight El Niño effect is forecast, which reduces hydrology, and increases the upward price trend.

NCRE generation has shown a solid growth trend, even faster than expected, mainly because of the technological improvement in wind and solar technologies and the associated declining amount of capital required.  This growth trend is backed by several governmental initiatives.  In the future, we believe NCRE capacity will continue growing and push energy prices down.  However, most of the NCRE projects promoted by Enel, our controlling shareholder, are being developed by Enel Green Power S.p.A. and its subsidiaries, in which we have no equity interest, in the four countries where we operate.  As a result, our strategy is to focus in creating synergies with plants in operation and obtaining economies of scale, by combining existing plants with new NCRE projects to achieve greater competitiveness.

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 have the opportunity to increase their efficiency, and obtain extra profits associated with such efficiencies, during the period subsequent to each new tariff setting.

In Argentina, the government has been gradually implementing reforms to the current regulatory framework, increasing regulated tariff rates that are expected to have a positive effect on our Argentine results.  Until 2017, the Argentine government avoided increasing electricity tariffs for end customers and seasonal prices were maintained substantially fixed in Argentine pesos.  However, since February 2017, ENRE has published several resolutions, which updated the distribution tariff.  Tariff subsidies are expected to be removed during 2019, and that will probably lead to lower demand, delayed payments or an increase in unrecoverable receivables, any of which could affect our profitability adversely.

We expect organic growth expansion in the distribution business from the digitalization of the network.  We expect to invest in technology that will automate our networks to achieve better operational and economic efficiency.  These smart meters allow bi-directional communication, and digitized and interconnected networks.  This technology will allow us to reduce manual reading costs, improve interruption and reconnection processes, and better address extreme weather emergencies by significantly reducing failure recognition time.  These instruments will also lower our maintenance costs and provide a necessary technical tool through which residential customers may inject their future excess energy into the system.

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We expect positive results from Enel Distribution Sao Paulo that increased our customer base by 7 million customers in 2018.

We will keep our marketing focus to boost our current activities developed by our Enel X subsidiaries in the public and private sector.  In the future, we expect to offer turnkey projects for municipalities and other public and governmental entities, industrial and residential appliances such as photovoltaic systems, heating ventilation air conditioning, led lighting, projects related to energy efficiency, and the development of private and public electric mobility and charging infrastructure.  For example, during 2018, ANEEL issued new regulations that allow distributors to install charge stations for vehicles in their concession areas and to negotiate prices directly with customers.  We expect to have almost 12,000 by 2021 and the number of electric buses will increase from none to more than 40 by progressively implementing the model executed by our affiliate Enel Chile in Chile.  We expect these measures to boost investments and demand in the future.

E.Off-balance Sheet Arrangements.

We are not a party to any off-balance sheet arrangements.

F.Tabular Disclosure of Contractual Obligations.

The table below sets forth our cash payment obligations as of December 31, 2018:

	Payments due by Period
US$ Million	Total	2019	2020-2021	2022-2023	After 2024
Purchase obligations(1)	112,120	25,860	20,371	19,281	46,608
Interest expense(2)	1,513	464	502	285	262
Yankee bonds	828	—	227	—	601
Local bonds(3)	3,196	448	752	1,016	980
Financial leases	137	39	79	15	3
Pension and post-retirement obligations(4)	4,235	366	652	570	2,647
Other debt(5)	555	407	65	50	32
Bank debt	4,018	3,234	653	91	41
Total contractual obligations	126,601	30,818	23,301	21,308	51,174

(1)Includes generation and distribution business purchase obligations, which are comprised mainly of energy purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of US$ 107,760 million, 96.1% corresponds to energy purchased for distribution and 1.4% corresponds primarily to fuel supply, maintenance of medium and low voltage lines, supplies of cable and utility poles, and energy purchased for generation. The remaining 2.5% corresponds to miscellaneous services, such as LNG regasification, fuel transport and coal handling.

(2)Interest expenses are the interest payments for all outstanding financial obligations, calculated as principal multiplied by the interest rate, presented according to when the interest payment comes due.

(3)Net value, hedging instruments might substantially modify the outstanding amount of debt.

(4)We have funded and unfunded pension and post-retirement benefit plans. Our funded plans have contractual annual commitments for contributions, which do not change based on funding status. Cash flow estimates in the table are based on such annual contractual commitments including certain estimable variable factors such as interest. Cash flow estimates in the table relating to our unfunded plans are based on future discounted payments necessary to meet all of our pension and post-retirement obligations.

(5)Other debt incudes governmental loan facilities, supplier credits and short-term commercial paper among others.

G.Safe Harbor.

The information contained in the Items 5.E and 5.F contains statements that may constitute forward-looking statements. See “Forward-Looking Statements” in the “Introduction” of this Report, for safe harbor provisions.

Item 6.Directors, Senior Management and Employees

A.Directors and Senior Management.

Directors

Our Board of Directors consists of seven members who are elected for a three-year term at an Ordinary Shareholders’ Meeting (“OSM”). If a vacancy occurs in the interim, the Board of Directors elects a temporary director to fill the vacancy until the next OSM,

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at which time the entire Board of Directors will be elected.  Our Executive Officers are appointed and hold office at the discretion of the Board of Directors.

The members of our Board of Directors as of December 31, 2018 were as follows:

Directors	Position	Age(1)	Current Position Held Since
Borja Acha B.	Chairman	54	2015
Domingo Cruzat A.	Director	63	2016
Livio Gallo	Director	69	2016
Patricio Gómez S.	Director	55	2016
Hernán Somerville S.	Director	78	1999
José Antonio Vargas L.	Director	55	2016
Enrico Viale	Director	62	2016

(1)As of April 30, 2019.

The Board of Directors was elected at the OSM held on April 28, 2016, for a three-year term which ends in April 2019. As required by the Chilean law, the entire Board of Directors will be up for election at the OSM that will be held on April 30, 2019 for a new three-year term ending in April 2022.

Set forth below are brief biographical descriptions of the members of our Board of Directors, of whom four reside outside Chile and three reside in Chile, as of December 31, 2018:

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 the Universidad Complutense de Madrid.

Domingo Cruzat A.

Mr. Cruzat is a director of Conpax, Coprefrut, 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, among others.  He 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 Wharton.

Livio Gallo

Mr. Gallo is also the Head of Enel Infrastructure and Global Networks since 2014. He is the Chairman of Directors of Enel Sole S.r.L. and Director of Endesa, S.A. and CESI S.p.A.  He is Vice Chairman of European Operators of Distribution Networks for Smart Grids Association and member of the Executive Committee of the Italian Electrotechnical Committee since 2006.  Mr. Gallo was Chairman of Enel Rete Gas (2005-2013).  He holds a degree in electronic engineering from the Politecnico di Milano.

Patricio Gómez-Sabaini C.

Mr. Gómez-Sabaini is 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.

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 Association of Banks and Financial Institutions.  In 2000-2010, he was a member of the Asia-Pacific Economic Cooperation Forum (APEC) and the Chairman of the Chile Pacific Foundation, a foundation that strengthens Pacific country integration.  Mr. Somerville holds a law degree from the Universidad de Chile and a masters’ degrees from Yale and New York University.

José Antonio Vargas L.

Mr. Vargas has also been the Chairman of Codensa and Emgesa since 2006. He has over 20 years of experience in the Colombian energy sector, especially in the gas, coal and electricity industries.  In 1999-2006, he was the CEO of Empresa de Energía de Bogotá.

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Mr. Vargas holds a law degree from Colegio Mayor de Nuestra Señora del Rosario, with a special focus on private and public administration.

Enrico Viale

Mr. Viale was Chairman of the Board of Enel Generation Chile until April 2016.  In 2008-2014, he was Enel’s Chief Operating Officer, managed Enel’s interest in OGK-5 and Rusenergosbyt and supported Sever Energia’s upstream gas operations, before becoming Country Manager and CEO of Enel Russia.   Mr. Viale holds a civil engineering degree from the Polytechnic University of Turin and an MBA from the University of Santa Clara.

Executive Officers

Set forth below are our Executive Officers as of December 31, 2018.

The business address of our Executive Officers is c/o Enel Américas S.A., Santa Rosa 76, Santiago, Chile.

Executive Officers	Position	Age(1)	Joined Enelor Affiliate in	Current Position Held Since
Maurizio Bezzeccheri	Chief Executive Officer	61	1999	2018
Aurelio Ricardo Bustilho de Oliveira	Chief Financial Officer	51	1999	2018
Raffaele Cutrignelli (2)	Internal Audit Officer	38	2005	2016
José Miranda M. (2)	Communications Officer	37	2014	2014
Liliana Schnaidt H. (2)	Human Resources Officer	40	2009	2018
Bruno Stella	Planning and Control Officer	46	1995	2018
Domingo Valdés P. (2)	General Counsel	55	1993	1999

(1)As of the date of this Report.

(2)Ms. Schnaidt and Messrs. Cutrignelli, Miranda and Valdés are or have been Executive Officers of Enel Américas but have been paid exclusively by Enel Chile S.A. They provide services to the Company under an intercompany agreement.

Set forth below are brief biographical descriptions of our Executive Officers, all of whom reside in Chile.

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. Mr. Bezzeccheri has held managerial positions in multinational companies located in Europe, Middle East and America. He holds a degree in in chemical engineering from the Università degli Studi di Napoli.

Aurelio Ricardo Bustilho de Oliveira: Mr. Bustilho was CFO of Enel Brasil and had worked 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.

Raffaele Cutrignelli: Mr. Cutrignelli was the Audit Officer for Codensa and Emgesa (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 master’s degree in audit and internal controls from Universitá di Pisa.

José Miranda M.: Before joining Enel, Mr. Miranda worked for eleven years at Televisión Nacional de Chile, a state-owned Chilean TV channel.  He is an audiovisual communicator with a degree from DUOC UC and a graduate degree in management from Universidad de Chile.

Liliana Schnaidt H.: Ms. Schnaidt held positions in EGP business development, with a focus on solar energy (2009-2018). Ms. Schnaidt holds a degree in civil engineering from Pontificia Universidad Católica de Chile.

Bruno Stella: Mr. Stella was Planning and Control Officer of Enel Chile (2016-2018).  He was Director of Planning and Reporting in Global Trading (2015-2016).  Mr. Stella holds a degree in business and economics from the Università degli Studi di Messina in Italy.

Domingo Valdés P.:  Mr. Valdés is the Secretary of the Boards of Directors of both Enel Chile and Enel Américas and is a Professor of Economic and Antitrust Law at Universidad de Chile.  Mr. Valdés holds a law degree from Universidad de Chile and a master’ in law degree from the University of Chicago.

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B.Compensation.

At the OSM held on April 26, 2018, our shareholders approved the current compensation policy for our Board of Directors.  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 meetings 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.

The members of our Directors’ Committee 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 meetings 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 and/or associate companies or serves as director of other companies or corporations in which the economic group holds an interest directly or indirectly the director can only receive compensation in one of these Boards of Directors.

Executive Officers of our Company and/or of our subsidiaries or associate companies will not receive compensation in the case that they serve as director of any subsidiary, associate company or are affiliated in any way to our Company. However, compensation may be received by the Executive Officer 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, with which the Executive Officer signed a work contract.

In 2018, the total compensation paid to each of our directors, including fees for attending Directors’ Committee meetings was as follows:

	Year ended December 31, 2018
Director	Fixed Compensation	Ordinary and Extraordinary Session	Directors’ Committee (Fixed Compensation)	Ordinary and Extraordinary Session (Directors’ Committee)	Total
	(in Th US$)
Borja Acha B. (1)	—	—	—	—	—
José Antonio Vargas L. (1)	—	—	—	—	—
Livio Gallo (1)	—	—	—	—	—
Enrico Viale (1)	—	—	—	—	—
Hernán Somerville S.	96	57	32	14	199
Domingo Cruzat A.	96	57	32	14	199
Patricio Gómez S.	96	55	32	14	196
Total	287	169	96	41	593

(1)Messrs. Acha, Vargas, Gallo and Viale waived their compensation for their current position as Director of the Company due to their positions as employees of other companies in the Enel Group.

We do not disclose, to our shareholders or otherwise, 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 individual contribution to our results and objectives.  The annual bonus plan provides for 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, 2018, the aggregate gross compensation, paid or accrued, for all our Executive Officers, attributable to fiscal year 2018, was US$ 3,5 million in fixed compensation and US$ 205,902 in benefits. No variable compensation was paid by the Company in 2018. For expatriate Executive Officers, no variable compensation was paid by us since they received their variable bonus from their home country in 2018. For the other Executive Officers, they have been paid exclusively by Enel Chile and they provide services to the Company under an intercompany agreement. Therefore, their variable bonus was paid by Enel Chile in 2018.

We entered into severance indemnity agreements with all of our Executive Officers, pursuant to which we will pay a severance indemnity in the event of voluntary resignation or termination by mutual agreement 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 legal severance pay if terminated due to our needs, as defined in Article 161 of the Chilean Labor Code. No severance indemnity was paid in 2018 to our Executive Officers.

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C.Board Practices.

Our Board of Directors in office as of December 31, 2018 was elected at the OSM held on April 28, 2016, for a three-year term which ends in April 2019. At the OSM to be held on April 30, 2019, the entire Board of Directors will be up for election for a three-year term ending in April 2022. For information about each of the directors and the year that they began their service on the Board of Directors, see “Item 6. Directors, Senior Management and Employees — A. Directors and Senior Management” above. Members of the Board of Directors do not have service contracts with us or with any of our subsidiaries that provide them benefits upon termination of their service.

Corporate Governance

We are managed by a Board of Directors, in accordance with our bylaws, consisting of seven directors who are elected by our shareholders at an OSM, each of whom serves for a three-year term. Following the end of their term, they may be re-elected indefinitely or replaced.  Staggered terms are not permitted under Chilean law. If a vacancy occurs on the Board of Directors during the three-year term, the Board of Directors may appoint a temporary director to fill the vacancy. A vacancy triggers an election for every seat on the Board of Directors at the next OSM.

Chilean corporate law provides that a company’s Board of Directors is responsible for the management and representation of a company in all matters concerning its corporate purpose, subject to the provisions of the company’s bylaws and the shareholders’ resolutions. In addition to the bylaws, our Board of Directors has adopted regulations and policies that guide our corporate governance principles.

Our corporate governance policies are included in the following policies or procedures: the Charter Governing Executives, the Employee Code of Conduct, the Manual for the Management of Information of Interest to the Market (the “Manual”), the Human Rights Policy, the Code of Ethics and a Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Penal Risk Prevention Model, the “Guidelines 231: Guidelines applicable to non-Italian subsidiaries in accordance with Legislative Decree 231 of June 8, 2001” (the “Guidelines 231”)  and procedures issued in compliance with General Regulation 385 issued by the CMF. The Charter Governing Executives, approved by our Board in 2003, and the Employee Code of Conduct, explain our principles and ethical values, establish the rules governing our contact with customers and suppliers, and establish the principles that should be followed by employees, including ethical conduct, professionalism and confidentiality. They also impose limitations on the activities that our executives and other employees may undertake outside the scope of their employment with us.

In order to ensure compliance with Securities Market Law 18,045 and CMF regulations, our Board of Directors approved the Manual at its meeting held in 2008.  This document addresses applicable standards regarding the information in connection with transactions of our securities and those of our affiliates, entered into by directors, management, principal executives, employees and other related parties, the existence of blackout periods for such transactions undertaken by directors, principal executives and other related parties, the existence of mechanisms for the continuous disclosure of information that is of interest to the market and mechanisms that provide protection for confidential information.  The Manual was released to the public in 2008, and is posted on our website at www.enelamericas.com. In 2010, the Manual was modified in order to comply with the provisions of Law 20,382 (Corporate Governance Improvement Law).

The provisions of this Manual apply to the members of our Board, as well as our executives and employees who have access to confidential information, and especially those who work in areas related to the securities markets.

Our Board of Directors approved a procedure for relationships between Politically Exposed Persons and our Company, which established a specific regulation for their commercial and contractual relationships. The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into the corporate reality.

In order to supplement the aforementioned corporate governance regulations, our Board of Directors approved a Code of Ethics and the ZTAC Plan at its meeting held in 2010. The Code of Ethics is based on general principles such as impartiality, honesty, integrity and other ethical standards of similar importance, all of which are expected from our employees. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with special emphasis on avoiding corruption in the form of bribes, preferential treatment, and other similar matters.  At its meeting held on January 19, 2017, our Board of Directors approved an amendment to the Code of Ethics and ZTAC Plan to eliminate the reference to Law 19,885 in connection with political donations and to forbid political donations altogether.

In 2011, our Board approved the Penal Risk Prevention Model in order to comply with Law 20,393 of December 2, 2009, which imposes criminal responsibility on legal entities for the crimes of asset laundering, financing of terrorism and bribing of public officials.  The law encourages companies to adopt this model, whose implementation involves compliance with managerial and

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supervision duties.  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.

At its meeting held on October 28, 2016, our Board approved “The Global Compliance Program for Corporate Penal Liability”, which was incorporated into the Penal Risk Prevention Model to reflect current standards, and appointed Mr. Rafael Cutrignelli as our Penal Risk Prevention and Global Compliance Program for Corporate Penal Liability Officer as required by the Penal Risk Prevention Model.  Mr. Cutrignelli also serves as Internal Audit Officer for both Enel Chile and Enel Américas.

In 2010, our Board of Directors approved the Guidelines 231.  The Guidelines 231 is defined by Italian Legislative Decree 231, which was enacted on June 8, 2001.  It establishes a compliance program that identifies the behaviors expected of related parties for the non-Italian subsidiaries of Enel.  Given that our ultimate controlling shareholder, Enel, complies with Italian Legislative Decree 231, which establishes management responsibility for Italian companies as a consequence of certain crimes committed in Italy or abroad, in the name of or for the benefit of such entities, including those crimes described in Chilean Law 20,393, these guidelines set a group of measures, with standards of behavior expected from all employees, advisers, auditors, officials, directors as well as consultants, contractors, commercial partners, agents and suppliers.  Legislative Decree 231 includes various activities of a preventive nature that are coherent with and integral to the requirements and compliance with Chilean Law 20,393, which deals with the criminal responsibility of legal entities.  These guidelines are supplementary to the standards included in the Code of Ethics and the ZTAC Plan.

On November 29, 2012, the CMF issued General Regulation 341 which established regulations for the disclosure of information with respect to the standards of corporate governance compliance adopted by publicly held limited liability corporations and set the procedures, mechanisms and policies that are indicated in the Appendix to the regulation.  The objective of this regulation is to provide credible information to investors with respect to good corporate governance policies and practices adopted by publicly held limited liability corporations, which include us, and permit entities like stock exchanges to produce their own analyses to help the various market participants to understand and evaluate the commitment of companies.  General Regulation 341 was substituted by General Regulation 385, issued by the CMF on June 8, 2015.  This regulation has similar objectives than the former General Regulation 341, but includes additional issues; by the way of separating each policy in several more detailed policies.  Subjects such as non-discrimination, inclusion and sustainability are particularly important in this new regulation.  The Appendix of General Regulation 385 is divided into the following four sections with respect to which companies must report the corporate practices that have been adopted: (i) the functioning and composition of the board, (ii) relations between the company, shareholders and the general public, (iii) risk management and control, and (iv) assessment by a third party.  Publicly held limited liability corporations should send the information with respect to corporate governance practices to the CMF no later than March 31 of each year, using the contents of the Appendix to this regulation as criteria.  If none of them is adopted, the company must explain its reasons to the CMF.  The information should refer to December 31 of the calendar year prior to its dispatch.  At the same time, such information should also be at the public’s disposal on the company’s website, and must be sent to the stock exchanges.

Compliance with the New York Stock Exchange Listing Standards on Corporate Governance

The following is a summary of the significant differences between our corporate governance practices and those applicable to U.S. domestic issuers under the corporate governance rules of the NYSE.

Independence and Functions of the Directors’ Committee (Audit Committee)

Chilean law requires that at least two thirds of the Directors’ Committee be independent directors. According to Article 50 bis of Law No.18,046, a member would not be considered independent if, at any time, within the last 18 months he (i) maintained 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; (ii) maintained 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 that 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 that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of the principal competitors, suppliers or customers. In case there are not sufficient independent directors on the Board to serve on the Directors’ Committee, Chilean law determines that the independent director nominates the rest of the members of the Directors’ Committee among the remaining Board members that 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$ 595 million as of December 31, 2018) and at least 12.5% of its voting

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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, at an Extraordinary Shareholders’ Meeting (“ESM”), our bylaws were amended and the Audit Committee was merged with the Directors’ Committee.

Pursuant to our bylaws, all members of the Directors’ Committee must satisfy the requirements of independence, as stipulated by the NYSE. The Directors’ Committee is composed of three members of the Board and complies with Article 50 bis of Law No.18,046, as well as with 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 conditions of the Audit Committee 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 among its functions the duties performed by an Audit Committee.

Our Directors’ Committee performs the following functions:

·review of financial statements and the reports of the external auditors prior to their submission for shareholders’ approval;

·present proposals to the Board of Directors, which will make its own proposals to shareholders’ meetings, for the selection of external auditors and private rating agencies;

·review of information related to our transactions with related parties and reports the opinion of the Directors’ Committee to the Board of Directors;

·the examination of the compensation framework and plans for managers, executive officers and employees;

·the preparation of an Annual Management Report, including its main recommendations to shareholders;

·provide 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;

·oversee the work of external auditors;

·review and approve the annual auditing plan by the external auditors;

·evaluate the qualifications, independence and quality of the auditing services;

·elaborate on policies regarding employment of former members of the external auditing firm;

·review and discuss problems or disagreements between management and external auditors regarding the auditing process;

·establish procedures for receiving and dealing with complaints regarding accounting, internal control and auditing matters;

·any other function mandated to the Committee by the bylaws, our Board of Directors or our shareholders.

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 disclosure of the procedures related to the General Resolution 385 and the Manual.  We have also adopted the Code of Ethics, and our bylaws include provisions that govern the creation, composition, attributions, functions and compensation of the Directors’ Committee described above, which includes among its functions the duties performed by an Audit Committee.

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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, 2018, 2017 and 2016:

Company	2018	2017	2016
Argentina
Costanera	418	439	470
El Chocón	49	52	58
Edesur	3,760	4,251	4,297
Enel Trading Argentina	29	27	17
Dock Sud	88	87	88
CTM and TESA	4	5	5
Total personnel in Argentina	4,348	4,861	4,935
Brazil
Cachoeira Dourada	94	85	82
EGP Volta Grande	—	—	—
Fortaleza	64	61	66
Cien	34	35	37
Enel Distribution Sao Paulo	7,278	—	—
Enel Distribution Rio(1)	1,118	1,075	1,103
Enel Distribution Ceara	1,135	1,163	1,140
Enel Brasil	76	72	71
Enel Distribution Goias	1,101	1,098	—
Enel X Brasil	—	—	—
Total personnel in Brazil	10,900	3,589	2,499
Chile
Enel Américas	57	55	62
Total personnel in Chile	57	55	62
Colombia
Emgesa	615	604	558
Codensa	1,529	1,376	1,340
Total personnel in Colombia	2,144	1,980	1,898
Peru
Enel Generation Peru	285	276	256
Enel Distribution Peru	590	588	620
Enel Generation Piura	40	44	52
Generalima	—	—	2
Total personnel in Peru	915	908	930
Total personnel (2)	18,364	11,393	10,324

(1)Includes Enel Soluções S.A.

(2)The total number of temporary employees is not significant.

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Chile

We have the following collective bargaining agreements:

Company	Signed in	In Force until
Enel Américas - Collective Bargaining Agreement 1	July 2015	July 2019
Enel Américas - Collective Bargaining Agreement 2	January 2016	December 2019

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 14,250 (Art. 12).

Brazil

We have the following collective bargaining agreements:

Company (1)	Signed in	In Force until
Enel Distribution Sao Paulo - Collective Bargaining Agreement	June 2018	May 2020
Enel Distribution Rio - Collective Bargaining Agreement	October 2017	September 2019
Enel Distribution Ceara - Collective Bargaining Agreement	November 2018	October 2020
Cien - Collective Bargaining Agreement	May 2017	April 2019
Cachoeira Dourada - Collective Bargaining Agreement	May 2018	April 2020
Fortaleza - Collective Bargaining Agreement	May 2017	April 2019
Enel Distribution Goias - Collective Bargaining Agreement	May 2018	April 2020
Enel Brasil - Collective Bargaining Agreement	October 2017	September 2019

(1)Under Brazilian law, collective bargaining agreements cannot last for more than two years.

Colombia

We have the following collective bargaining agreements:

Company (1)	Signed in	In Force until
Codensa - Collective Bargaining Agreement 1 (2)	August 5, 2015	June 30, 2018
Codensa - Collective Bargaining Agreement 2	April 29, 2016	December 31, 2019
Emgesa - Collective Bargaining Agreement 1	August 13, 2015	June 30, 2018
Emgesa - Collective Bargaining Agreement 2	June 1, 2016	December 31, 2019

(1)Under Colombian labor law, pre-existing collective bargaining agreements are automatically renewed until a new agreement is in force.

(2)The direct negotiation process ended without agreement between the parties and we are waiting the decision of the Arbitration Court, which will result in a new effective date of the Arbitral Agreement and will have the same effects as a Collective Bargaining Agreement.

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Peru

We have the following collective bargaining agreements:

Company	Signed in	In Force until
Enel Distribution Peru - Collective Bargaining Agreement 1	January 1, 2018	December 31, 2019
Enel Distribution Peru - Collective Bargaining Agreement 2 (1)	January 1, 2017	December 31, 2017
Enel Distribution Peru - Collective Bargaining Agreement 3	January 1, 2018	December 31, 2019
Enel Generation Peru - Collective Bargaining Agreement 1	January 1, 2018	December 31, 2018
Enel Generation Piura - Collective Bargaining Agreement 1	January 1, 2018	December 31, 2021

(1)To date, the collective bargaining agreements with respect to 2018 and 2019 are still in negotiation.

E.Share Ownership.

To the best of our knowledge, none of our directors or officers owns more than 0.1% of our shares or owns 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. To the best of our knowledge, any share ownership by all of our directors and officers, in the aggregate, amounts to significantly less than 10% of our outstanding shares. However, Mr. Hernán Somerville, a director, is a controlling shareholder of Inversiones Santa Verónica Limitada, which owns 5,044,782 shares of the company as of March 27, 2019.

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 since June 2009, has no different voting rights than our other shareholders. As of April 15, 2019, our 23,173 shareholders of record held our 57,452,641,516 shares of common stock outstanding.  Enel owned 32,416,546,356 shares of our common stock, representing a 56.4% direct ownership interest in us. There were five record holders of our ADSs, 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, as the depositary for our ADSs only has knowledge of the record holders, including the Depositary Trust Company and its nominees. As such, we are not able to ascertain the domicile of the final beneficial holders represented by the six ADS record holders in the United States. Likewise, we cannot readily determine the domicile of any of our foreign stockholders who hold our common stock, either directly or indirectly.

As of April 15, 2019, Chilean private pension funds (“AFPs”), owned 12.5% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 21.3% of our shares. ADS holders owned 7,2% of our shares and the remaining 2.6 % of our shares were held by 22,983 minority shareholders.

The following table sets forth certain information concerning ownership of the common stock as of April 15, 2019, with respect to each stockholder known by us to own more than 5% of the outstanding shares of common stock:

	Number of SharesOwned	Percentage of SharesOutstanding
Enel S.p.A.	32,416,546,356	56.4	%

Enel is an energy company with multinational operations in the power and gas markets, with a focus on Europe and Latin America. Enel operates in 34 countries across five continents, produces energy through a managed installed capacity of almost 90 GW, which includes 43 GW of renewable sources, and distributes electricity and gas through a network covering 2.2 million kilometers. With over 73 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enel shares trade on the Milan Stock Exchange.

B.Related Party Transactions.

Article 146 of Law 18,046 (the “Chilean Corporations Act”) 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

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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 control 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. The law establishes that in the event that these persons fulfill the requirements established by Article 146, such persons must immediately inform the Board of Directors of their related-party nature or such other group as the Board of Directors may appoint for that purpose. As required by law, “related-party transactions” must comply with corporate interests, as well as prices, terms and conditions prevailing in the market at the time of their approval. They must also meet all legal requirements, including acknowledgement by the Directors’ Committee and approval of the transaction by the Board of Directors (excluding the affected directors), by the ESM (in some cases, with requisite majority approval) and by any applicable regulatory procedures.

The aforementioned law, which also applies to our affiliates, also provides for some exceptions, stating that in certain cases, Board approval would suffice for “related-party transactions,” pursuant to certain related-party transaction thresholds and 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 does not comply with Article 146 of the Chilean Corporations Act, this would not affect the transaction’s validity, but we or our shareholders may demand compensation from the individual associated with the infringement as provided under law, and compensation for damages.

As a result of the 2016 Reorganization, we entered into certain intercompany arrangements. Under Chilean law, we remain jointly and severally liable for former obligations that were assumed by Enel Chile pursuant to the separation of the businesses completed on March 1, 2016. Such liability, however, will not extend to any obligation to a person or entity that has given its express consent relieving us of such liability.  For additional information on the corporate reorganization, see “Item 4. Information on the Company — A. History and Development of the Company — The 2016 Reorganization.”

In the countries in which we operate, we do not manage the cash flows of our subsidiaries even when intercompany transactions are permitted; however, these may have adverse tax consequences.

In the context of the tender offer process aiming to the acquisition of Enel Distribuição São Paulo, in April 2018, the Board of Directors examined and approved an intercompany loan to Enel Brasil and/or its vehicle Enel Sudeste. In addition, the Board of Directors approved to grant a guarantee to Enel Brasil and Enel Sudeste in favor of BTG Pactual Brasil and/or any other entities, to support the tender offer. The guarantees were due after the execution of the payment of all the shares tendered.

In May 2018, the Board of Directors examined and approved the granting of guarantees by Enel Américas for the financing of the acquisition of Enel Distribution Sao Paulo. Later, in June 2018, the company granted corporate guarantees to its subsidiaries Enel Brasil and Enel Sudeste for the funding through the issuance of Notas Promissorias issued in the Brazilian capital market for a total amount of 9,300 million Brazilian Reais. The mentioned guarantees were due after the repayment of the Notas Promissorias with an intercompany loan granted to Enel Brasil by EFI in September 2018, for a total amount of 9,400 million Brazilian Reais.

In December 2018, due to the need for working capital, two intercompany loans were made by EFI to Enel Distribution Ceara for an amount of 300 million Brazilian Reais and to Enel Distribution Sao Paulo for an amount of 420 million Brazilian Reais.

In addition, during 2017, we granted intercompany loans to Enel Brasil for an amount of US$ 375 million, to support its business plan. All of these intercompany loans are denominated in U.S. dollars and are due between 2019 and 2022. As of March 31, 2019, the outstanding balance of the loans amounted US$ 375 million.

Starting from January 1, 2019, all intercompany operating lease contracts are considered as financial debt between related parties to comply with the new IFRS 16 standards. As of March 31, 2019, there were no intercompany operating lease agreements.

There are various contractual relationships between Enel Chile and us to provide for intercompany services. Enel Chile entered into intercompany agreements under which it provides services directly and indirectly to us. The services to be rendered by Enel Chile include certain legal, finance, treasury, insurance services, capital markets, financial compliance, accounting, human resources, communications, security, relations with contractors, IT services, tax services and other corporate support and administrative services. These services are provided and charged at market prices if there is a comparable service. If there are no comparable services in the market, they will be provided at cost plus a specified percentage. The intercompany services contracts are valid for five years with renewable terms since January 1, 2017.

As of the date of this Report, the abovementioned transactions have not experienced material changes.  Finally, as of December 31, 2018, there were also some commercial transactions with related parties.  For more information regarding transactions with related parties, refer to Note 13 of the Notes to our consolidated financial statements.

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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

We and our subsidiaries 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, 2018 on the status of the material pending lawsuits that have been filed against us and our subsidiaries, please refer to Note 36.3 of the Notes to our consolidated financial statements. Please note that since March 1, 2016, Enel Chile appears as the defendant instead of us for current legal proceedings or those that may arise from our former Chilean businesses.

In relation to the legal proceedings reported in the Notes to our consolidated financial statements, we use the criteria of disclosing lawsuits above a minimum threshold of US$ 20 million of potential impact to us, and, in some cases, qualitative criteria according to the materiality of the plausible impact in 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 proposes annually to the OSM for approval a definitive dividend payable each year, which is accrued in the prior year and cannot be less than the legal minimum of 30% of annual net income, and informs a dividend policy for the current fiscal year. Additionally, our Board of Directors generally establishes an interim dividend for the current fiscal year, to be paid in January of the following year and which is deducted from the definitive dividend to be paid in May of the following year. The interim dividend is established by the Board of Directors and it is not subject to any restrictions under the Chilean law.

For dividends corresponding to fiscal year 2017, the interim and definitive dividend were paid on January 26, 2018 and May 25, 2018, respectively. The interim dividend of US$ 0.00100 per share of common stock was paid as part of the definitive dividend and amounted to 15% of consolidated net income as of September 30, 2017. At the OSM held on April 26, 2018, our shareholders approved the definitive dividend equivalent to US$ 0.00617 per share of common stock, but only US$ 0.00517 was effectively distributed since the interim dividend paid in January 2018 was deducted from it. These dividends were paid in Chilean pesos, considering the U.S. dollar Observed Exchange Rate as of January 19, 2018 in the case of the interim dividend, and as of May 18, 2018 in the case of the definitive dividend. The definitive dividend amounted to a payout ratio of 50% based on annual net income for fiscal year 2017.

For dividends corresponding to fiscal year 2018, on November 26, 2018, the Board of Directors agreed to distribute an interim dividend of US$ 0.001338 per share of common stock on January 25, 2019 accrued in fiscal year 2018, amounting to 15% of consolidated net income as of September 30, 2018. The interim dividend was paid in Chilean pesos, considering the U.S. dollar Observed Exchange Rate as of January 18, 2019. At the OSM to be held on April 30, 2019, our shareholders will vote to approve a definitive dividend for fiscal year 2018. If the proposed definitive dividend is approved at the OSM, the definitive dividend will correspond to a payout ratio of 40% based on annual net income for fiscal year 2018.

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For dividends corresponding to fiscal year 2019, our Board of Directors will inform to the OSM to be held on April 30, 2019 the following Dividend Policy:

·An interim dividend, accrued in fiscal year 2019 and amounting to 15% of consolidated net income as of September 30, 2019, to be paid in January 2020.

·A definitive dividend payout equal to 50% of the annual net income for fiscal year 2019, to be paid in May 2020.

This dividend policy is conditional to net profits obtained in each period, as well as to 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 Director’s right to change the amount and timing of the dividends under the circumstances at the time of the payment. The payment of dividends is 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 at each subsidiary and affiliate agree on the definitive 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 prior to the payment date. Holders of ADS on the applicable record dates will be entitled to participate in dividends.

Dividends

The table below sets forth, for each of the years indicated, the per share dividend amounts distributed by us in Chilean pesos and the amount of dividends distributed per ADS (one ADS = 50 shares of common stock) in U.S. dollars.  For additional information, see “Item 10. Additional Information — D. Exchange Controls”.

	Dividends distributed(1)
Year	Nominal		Per ADS(2)
2018(3)	US$	0.00617	US$	0.31
2017	Ch$	3.33	US$	0.27
2016(4)	Ch$	4.64	US$	0.38
2015	Ch$	6.21	US$	0.44
2014	Ch$	6.71	US$	0.55
2013	Ch$	4.25	US$	0.41

(1)This chart details dividends paid and not the dividends accrued. These amounts do not reflect reduction for any applicable Chilean withholding tax.

(2)The U.S. dollar per ADS amount has been calculated by applying the exchange rate as of December 31 of each year. One ADS = 50 shares of common stock.

(3)From 2018 onwards, dividends are presented in dollars per share.

(4)The current company is not necessarily comparable to its predecessor before the 2016 Reorganization.

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.

Item 9.The Offer and Listing

A.Offer and Listing Details.

The shares of our common stock and our ADSs currently trade on Chilean Stock Exchanges and the NYSE, respectively, under the trading symbols “ENELAM” and “ENIA”, respectively.

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B.Plan of Distribution.

Not applicable.

C.Markets.

In Chile, our common stock is traded on the following stock exchanges: the Santiago Stock Exchange, the Electronic Stock Exchange and, until October 8, 2018, the Valparaíso Stock Exchange. The Santiago Stock Exchange, the largest exchange in the country, was established in 1893 as a private company. As of December 31, 2018, more than 200 companies had shares listed on the Santiago Stock Exchange. For 2018, the Santiago Stock Exchange accounted for 93.9 % of our total equity traded in Chile, which amounted to 14,328,965,300 shares. In addition, 6.1 % of our equity trading was conducted on the Electronic Stock Exchange, an electronic trading market that was created by banks and non-member brokerage houses, and less than 0.01% was traded on the Valparaíso Stock Exchange.

On October 5, 2018, the Board of the Financial Market Commission (“CMF”) made public its resolution to revoke the existence authorization of the Valparaíso Stock Exchange, after 126 years of operations. The CMF explained that this was the result of the breach of the requirement of having a minimum number of 10 brokers as established in No. 4 of Article 40 of the Securities Market Law No. 18,045. Therefore, since October 8, 2018, the Valparaiso Stock Exchange stopped its operations.

Equities, closed-end funds, fixed-income securities, short-term and money market securities, gold and U.S. dollars are traded on the Santiago Stock Exchange. The Santiago Stock Exchange also trades U.S. dollar futures and stock index futures. The Santiago Stock Exchange also trades U.S. dollar futures and stock index futures. The Santiago Stock Exchange operates on business day from 9:30 a.m. to 4:00 p.m., during winter period from March to October, and from 9:30 a.m. to 5:00 p.m. during the summer period, from November to February, which may differ from New York City time by up to two hours, depending on the season.

Until early August 2018, there were two main stock price indexes on the Santiago Stock Exchange, the General Shares Price Index, or IGPA, and the Selective Shares Price Index, or IPSA. The IGPA was calculated using the prices of the shares traded during at least 5% of the days of the year, with a total of annual transactions exceeding UF 10,000 (approximately Ch$ 276 million as of December 31, 2018, equivalent to US$ 396,761) and a free float representing at least 5%. The IPSA was calculated using the prices of the 40 shares with the highest volume of quarterly transactions and with a market capitalization above US$ 200 million. The shares included in the IPSA and IGPA were weighted according to the weighted value of the shares traded. Either we or Enersis, from whom we spun off in 2016, have been included in the IPSA since 1988.

In August 2016, the Santiago Stock Exchange and the S&P Dow Jones Indices (“S&P DJI”) signed an Operating Agreement and Index Licensing. The alliance between the Santiago Stock Exchange and S&P DJI, the main global provider of concepts, data and research on indexes, includes the implementation of international methodological standards, as well as the integration of operational processes and business strategies, enhancing the visibility, governance and transparency of the existing indexes. The agreement also enables the development, granting of licenses, distribution and administration of current and future indexes, which will be developed as innovative and practical tools at the service of local and international investors. The indexes of the Santiago Stock Exchange, both new and existing, will use the shared brand “S&P/CLX” and may be used as underlying liquid financial products, thereby contributing to the expansion and depth of the Chilean capital markets. Under this agreement, S&P DJI assumed the tasks of calculation, production, maintenance, licensing and distribution of the indexes on Monday, August 6, 2018. Since that date the IGPA and the IPSA are referred to as the SPCLXIGPA and the SPCLXIPSA, respectively.

The SPCLXIGPA is calculated considering, among others things, the prices of the shares traded during at least 25% of the days of the year, with a total of annual transactions exceeding UF 10,000 (approximately US$ 396,761 as of December 31, 2018) and a free float representing at least 5%. The SPCLXIGPA index is rebalanced annually, after the close of the third Friday in March, and also, the number of shares per component of the index is updated quarterly after the close of the third Friday of the months of June, September and December. The SPCLXIGPA index at the close of December 2018 was 25,949.84 points.

The SPCLXIPSA is calculated considering, among other things, the prices of the 30 shares with the highest volume of quarterly transactions, with market presence of at least 90% and with a market capitalization above Ch$ 200,000 million (US$ 288 million). The SPCLXIPSA index is rebalanced every six months, after the closing of the third Friday of March and September, and also, the index is re-weighted quarterly after the close of the third Friday of the months of June and December. The SPCLXIPSA index at the close of December 2018 was 5,105.43 points.

Shares of our common stock traded in the United States, our primary market, in the form of ADSs on the NYSE and over-the-counter from October 1993 until the completion of the spin-off under our predecessor’s ticker symbol “ENI.” Since the completion of the spin-off of Enel Chile in April 2016, our ADSs trade under the ticker symbol “ENIA.” Each ADS represents 50 shares of common stock, with the ADSs 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

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and beneficial owners from time to time of ADRs issued thereunder (the “Deposit Agreement”). Only persons in whose names ADRs are registered on the books of the Depositary are treated by the Depositary as owners of ADRs.

As of April 15, 2019, ADRs evidencing 82,983,449 ADSs (equivalent to 4,149,172,428 shares of common stock) were outstanding, representing 7.2% of the total number of outstanding shares. It is not practicable for us to determine the proportion of ADSs beneficially owned by U.S. final beneficial holders. Trading volume of our shares on the NYSE and other U.S. exchanges during 2018 amounted to 272 million ADSs, equivalent to approximately US$ 2,516 million.

The NYSE is open for trading Monday through Friday from 9:30 am to 4:00 pm, with the exception of holidays declared by the NYSE in advance. On the trading floor, the NYSE trades in a continuous auction format, where traders can execute stock transactions on behalf of investors. Specialist brokers act as auctioneers in an open outcry auction market to bring buyers and sellers together and to manage the actual auction. Customers can also send orders for immediate electronic execution or route orders to the floor for trade in the auction market. The NYSE works with U.S. regulators like the SEC and the Commodity Futures Trading Commission to coordinate risk management measures in the electronic trading environment through the implementation of mechanisms like circuit breakers and liquidity replenishment points.

The following table contains information regarding the amount of total traded shares of common stock and the corresponding percentage traded per market during 2018:

	Number of shares ofcommon stock traded	Percentage
Market
United States (One ADS = 50 shares of common stock)(1)	13,577,931,850	47.1	%
Chile(2)	15,251,948,387	52.9	%
Total	28,829,880,237	100.0	%

(1)Includes the New York Stock Exchange and over-the-counter trading.

(2)Includes Santiago Stock Exchange, Electronic Stock Exchange and, until October 8, 2018, Valparaíso Stock Exchange.

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.

B.Memorandum and Articles of Association.

Description of Share Capital

Set forth below is certain information concerning our share capital and a brief summary of certain significant provisions of Chilean law 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 by the Chilean

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Corporations Act (Law No. 18,046). In addition, D.L. 3500, or the Pension Funds’ System Law, which permits the investment by Chilean pension funds in stock of qualified companies, indirectly affects corporate governance and prescribes certain rights of shareholders. In accordance with the Chilean Corporations Act, legal actions by shareholders to enforce their rights as shareholders of the company must be brought in Chile in arbitration proceedings or, at the option of the plaintiff, 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 that UF 5,000 (US$ 198,381 as of December 31, 2018) do not have the option to bring the procedure to the courts.

The Chilean securities markets are principally regulated by the CMF under Securities Market Law (Law No. 18,045) and the Chilean Corporations Act. These two laws state the disclosure requirements, restrictions on insider trading and price manipulation, and provide protection to 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 Act 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 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 the 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 269 of the CMF, certain information regarding transactions in shares of a publicly held stock corporation or in contracts or securities whose price or financial results depend on, or are conditioned in whole or in 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 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 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 part on the price of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held stock corporation’s subscribed capital;

·any direct or indirect acquisition or sale of shares made by a holder who, due to an acquisition 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; and

·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 stock corporation.

In addition, majority shareholders of a publicly held stock corporation must inform the CMF and the Chilean stock exchanges if such transactions are entered into with the intention of acquiring control of the company or if they are making a passive financial investment instead.

Under Article 54 of the Securities Market Law and General Rule 104 enacted by the CMF, any person who directly or indirectly intends to take control of a publicly held 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 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

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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 who are appointed by shareholders at an OSM and are elected 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. Each shareholder may vote his shares in favor of one nominee or may apportion his 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 is able to elect a member of the Board although 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 Act.

Certain Powers of the Board of Directors

Our bylaws provide that 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 two-thirds of the Board of Directors and be included in the Board meetings, and must comply with the provisions of the Chilean Corporations Act.

Our bylaws do not contain provisions relating 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

·number of shares, if any, required for directors’ qualification.

Certain Provisions Regarding Shareholder Rights

As of the date of the filing of this Report, our capital is comprised of 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 his name, and the subscriber is treated as a shareholder for

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all purposes, except receipt of dividends and for return of capital in the event that the shares have been subscribed but not paid for. The subscriber becomes eligible to receive dividends only for the shares that he has actually 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 prior to the date agreed upon for payment, notwithstanding the actions intended by the company to collect payment, the company is entitled to auction the shares 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 rights of a shareholder, except the right to receive dividends and return of capital. The Chief Executive Officer, or the person replacing him, 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 corresponding 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 in no case may exceed three years from the date of such meeting), these shall be reduced in the non-subscribed amount until that date. With respect to the shares subscribed and not paid following the term mentioned above, the Board must proceed to collect payment, unless the shareholders’ meeting authorizes (by two thirds of the voting shares) a reduction of the company’s capital to the amount effectively collected, 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 simple majority of the write-off of the outstanding balance and the reduction of capital to the amount effectively recovered.

As of December 31, 2018, our subscribed and fully paid capital totaled US$ 6,763 million consisting of 57,452,641,316 shares.

Preemptive Rights and Increases of Share Capital

The Chilean Corporations Act requires Chilean companies to grant shareholders preemptive rights to purchase a sufficient number of shares to maintain their existing ownership percentage of such company whenever such company issues new shares.

Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders during a 30-day period. 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 prior to the date of the start of the preemptive rights period. The preemptive rights offering and the start of the 30-day period 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-day period, and for an additional period of up to 30-days immediately following the initial 30-day period, publicly held stock corporations are not permitted to offer any unsubscribed shares to third parties on terms which are more favorable than those offered to their shareholders. At the end of the second 30-day period, a Chilean publicly held 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 OSM will be held on April 30, 2019. An ESM may be called by the Board of Directors when deemed appropriate, or when requested by shareholders representing at least 10% of the issued shares with voting rights, or by the CMF. To convene an OSM or an ESM, notice must be given three times in a newspaper located in our corporate domicile. The newspaper designated by our shareholders is El Mercurio. The first notice must be published not less than 15-days and no more than 20-days in advance of the scheduled meeting. Notice must also be mailed to each shareholder, to the CMF and to the Chilean stock exchanges.

The OSM shall be held on the day stated in the notice and should remain in session until having exhausted all the matters stated in the notice. 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 take place 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.

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Shareholders’ meetings adopt resolutions by the affirmative vote of a majority of those shares present or represented at the meeting. An ESM must be called to take the following actions:

·a transformation of the company into a form other than a publicly held stock corporation under the Chilean Corporations Act, 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;

·the disposition of 50% or more of the assets of the company, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater that 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 reaches 95% of the company’s shares by means of 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.

Regardless of the quorum present, the vote required for any of the actions above is at least two-thirds of the outstanding shares with voting rights.

Bylaw amendments for the creation of 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 stock corporation to provide its shareholders the same level and type of information required by the U.S. securities laws regarding the solicitation of proxies. However, shareholders are entitled to examine the financial statements and corporate books of a publicly held stock corporation within the 15-day period before its scheduled shareholders meeting. Under Chilean law, a notice of a shareholders meeting listing matters to be addressed at the meeting must be mailed at least 15 days prior to the date of such meeting, and, an indication of the way complete copies of the documents that support the matters submitted for voting can be obtained, which must also be made available to shareholders on our 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 Act 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 in relation to the company’s affairs. In accordance with Article 136 of the Chilean Companies 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 being able to make individually or jointly more than one presentation. These observations should be presented in writing to

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the company concisely, responsibly and respectfully, and the respective shareholder(s) should state their willingness for these 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

·make comments and proposals on matters that the Board submits for the knowledge or voting of the shareholders. 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 10-days prior to the date of dispatch of the information by the company. The shareholders should present their comments and proposals to the company, expressing their willingness for these 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 Act provides that whenever the Board of Directors of a publicly held stock corporation convenes an OSM 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 prior to the date of a meeting, 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 with respect to any of the matters submitted for voting at the meeting and which were 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 of the Depositary, currently Banco Santander-Chile, or any successor thereto. Accordingly, holders of ADSs are not entitled to receive notice of meetings of shareholders directly or to vote the underlying shares of common stock represented by ADS directly. The Deposit Agreement contains provisions pursuant to which the Depositary has agreed to request instructions from registered holders of ADSs as to the exercise of the voting rights pertaining to 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 of Directors or to a person designated by the Chairman of the Board of Directors to vote) the shares of common stock represented by the ADSs in accordance with any such instruction. The Depositary shall not itself exercise any voting discretion over any shares of common stock underlying ADSs. If no voting instructions are received by the Depositary from a holder of ADSs with respect to 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 ADS, may 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 limitations set forth in the Deposit Agreement.

Dividends and Liquidation Rights

According to the Chilean Corporations Act, unless otherwise decided by unanimous vote of its issued shares eligible to vote, all companies 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.

Any dividend in excess of 30% of net income may be paid, at the election of the shareholders, in cash, or in our shares, or in shares of publicly held corporations owned by us. Shareholders who do not expressly elect to receive a dividend other than in cash are legally presumed to have decided to receive the dividend in cash.

Dividends which are declared but not paid within the appropriate time period set forth in the Chilean Corporations Act (as to minimum dividends, 30-days after declaration; as to additional dividends, the date set for payment at the time of declaration) are adjusted to reflect the change in the value of UF, from the date set for payment to the date such dividends are actually paid. Such dividends also accrue interest at the then-prevailing rate for UF-denominated deposits during such 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 period are transferred to the volunteer fire department.

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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 which publicly offer their shares or securities convertibles into shares and which offer is made to shareholders to purchase their shares under conditions which allow the bidder to reach a certain percentage of ownership of the company within a fixed period of time. 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 as a result of such shareholder owning a substantial number of shares. However, no person may directly or indirectly own more than 65% of the outstanding shares of our stock. The foregoing restriction does not apply to the depositary as record owner of shares represented by ADRs, but it does apply to each beneficial ADS holder. Additionally, our bylaws prohibit any shareholder from exercising voting power with respect to more than 65% of the common stock owned by such shareholder or on behalf of others representing more than 65% of the outstanding issued shares with voting rights.

Right of Dissenting Shareholders to Tender Their Shares

The Chilean Corporations Act provides that upon the adoption of any of the resolutions enumerated below at a meeting of shareholders, dissenting shareholders acquire the right to withdraw from the company and to compel the company to repurchase their shares, subject to the fulfillment of certain terms and conditions. In order to exercise such withdrawal rights, holders of ADRs must first withdraw the shares represented by their ADRs pursuant to the terms of the Deposit Agreement.

“Dissenting” shareholders are defined as those who at a shareholders’ meeting 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 present or represented at the meeting and who abstain in exercising their voting rights shall not be considered as 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 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 two-month period between the ninetieth and the thirtieth day before the shareholders’ meeting giving rise to the withdrawal right. If, because of the volume, frequency, number and diversity of the buyers and sellers, 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 shall equal paid capital plus reserves and profits, less losses, divided by the total number of subscribed shares, whether entirely or partially paid. For the purpose of making this calculation, the last consolidated statements of financial position is used, as adjusted to reflect inflation up to the date of the shareholders’ meeting which gave rise to the withdrawal right.

Article 126 of the Chilean Corporations Act Regulations establishes that in cases where the right to withdraw arises, the company shall be obliged to inform the shareholders of this situation, the value per 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, prior to 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 are born. 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, plus a written communication addressed to the shareholders with rights at the address they have registered with the

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company. The notice of the shareholders meeting that should pronounce on a matter that could originate 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 which is not a publicly held stock corporation governed by Chilean Corporations Act;

·the merger of the company with another company;

·disposition of 50% or more of the assets of the company, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which 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 which exceed 50% of the assets (if the third party is a subsidiary of the company, the approval of the Board of Directors is sufficient);

·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 Funds’ System Law permits AFPs to invest their funds in companies that are subject to Title XII 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 have been a Title XII company since 1985 and we are approved by the Risk Classification Committee.

Title XII companies are required to have bylaws that limit the ownership of any shareholder to a specified maximum percentage, currently at 65%, require that certain actions be taken only at a meeting of the shareholders, and give the shareholders the right to approve certain investment and financing policies.

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 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.

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 set forth in the Compendium of Foreign Exchange Regulations (the “Compendium”) approved by the Central Bank of Chile in 2002. Appropriate registration of a foreign investment in Chile permits the investor access to the Formal Exchange Market. Foreign investments can be registered with the Foreign Investment Committee under D.L. 600 of 1974 or can be registered with the Central Bank of Chile under the Central Bank Act, Law No. 18,840 of October 1989.

a)Chapter XIV

The following is a summary of certain provisions of Chapter XIV that are applicable 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

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regulates the following type of investments: credits, deposits, investments and equity contributions. A Chapter XIV investor may at any time repatriate an investment made in us upon sale of our shares, and the profits derived therefrom, with no monetary ceiling, subject to the then effective regulations, which 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 issued by the Central Bank of Chile internationally under Chapter XIV of the Compendium.

E. Taxation.

Chilean Tax Considerations

The following discussion summarizes material Chilean 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 contained in statutes such as tax rates applicable to foreign investors, the computation of taxable income for Chilean purposes and the manner in which Chilean taxes are imposed and collected may be amended only by another law.  In addition, the Chilean tax authorities enact rulings and regulations of either general or specific application and interpret the provisions of the Chilean Income Tax Law.  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 in accordance with 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 the treaty will be ratified by either country.  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) an individual is a Chilean resident if he has resided in Chile for more than six months in one calendar year, or a total of more than six months in two consecutive fiscal years; 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

·in the case of a legal entity holder, an entity that is not organized under the laws of Chile, 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 with respect to 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 prior to January 1, 2017) the Foreign Holder can apply 100% of the CIT as a credit.  For 2017, 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.

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There are two alternative mechanisms of shareholder-level income taxation in effect since January 1, 2017: a) accrued income basis (known as attributed-income system in Chile) shareholder taxation and b) cash basis (known as partially-integrated system in Chile) shareholder taxation.

Under the current Chilean Income Tax Law, publicly held limited liability stock companies, such as we, are subject to the latter regime.

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 and 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 (as opposed to 100% under the accrued income basis regime).  However, in those cases where tax treaties between Chile and the jurisdiction of the shareholder’s residence are signed prior to January 1, 2019 (even if not yet in effect), the CIT is fully creditable against the 35% withholding tax.  This is the case with the tax treaty signed between Chile and the United States, which was signed prior to this date, but which is not in effect as of the time of this Report.  In the case of treaties signed prior to January 1, 2019 but not enacted as of December 31, 2021, the shareholder may apply 100% of the CIT as a credit if a dividend distribution is made before December 31, 2021, on a transitional basis.  Under the Chilean Tax Law in force at the time 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, 2021 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, 2022, 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 enacted by December 31, 2021, 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 2018 for companies that elected the 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	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 resident. 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%).

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 depository’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 be subject to Chilean taxation.

Taxation on sale or exchange of Shares

The Chilean Income Tax Law includes a tax exemption on capital gains arising 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 stock corporation with a “sufficient stock market liquidity” status in the Chilean Stock Exchanges; (ii) the sale must be carried out in a Chilean Stock Exchange authorized by the CMF, or in a tender

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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 ADS’s 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, in accordance with Chilean law and regulations. As of this date, our shares are considered to have a high presence in the Chilean Stock Exchanges and no market maker has been retained by us. 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 in relation to 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 2018, and a 35% Chilean withholding tax, the former being creditable against the latter.

The date of acquisition of the ADSs is considered to be the date of acquisition 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 pursuant to a rights offering is a nontaxable event.  In addition, 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 the ownership, transfer or disposition of ADSs by foreign holders, but such taxes will generally apply to the transfer at death or by 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.

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 so as 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, but 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 and 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;

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·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 in connection 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 tax advisors as to 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 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 is able to 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.

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 the claiming of 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 tax advisors with respect to 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

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foreign currency gain or loss in respect of 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 noncorporate 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 prior to 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 with respect to our 2018 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 2019 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.

Based on existing guidance, it is not entirely clear whether dividends received with respect to shares will be treated as qualified dividends, because the shares are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to 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 be able to comply with them. A U.S. Holder should consult its tax advisors to determine whether the favorable rate will apply to dividends it receives and whether it is subject to any special rules that limit 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 for purposes of calculating 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 pursuant to 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)

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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 tax advisors regarding the availability of foreign tax credits in their particular circumstances.

Passive Foreign Investment Company Rules

We were not a “passive foreign investment company” or PFIC for U.S. federal income tax purposes for our 2018 taxable year and we do not anticipate being a PFIC for our 2019 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 tax advisors regarding the consequences to them if we were to become a PFIC, as well as 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 to 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

Legislation enacted in 2010 generally imposes a tax of 3.8% on the “net investment income” of certain individuals, trusts and estates.  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 possible application of this legislation in the beneficial owner’s particular circumstances.

U.S. Holders should consult their tax advisors with respect to the particular consequences to them of owning or disposing of shares or ADSs.

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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 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. In accordance with these statutory requirements, we file or furnish reports and other information with the SEC. 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 changes in commodity prices, interest rates and foreign exchange rates that affect the generation, transmission and distribution businesses in the countries where we operate. Our Board of Directors approves risk management policies at all levels.

Commodity Price Risk

In our electricity generation and transmission business segment, 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 that are expected to match the lifetime of our generation assets. 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 prevailing at the time the purchase occurs.

In order to reduce risk under extreme drought conditions, Enel has designed a commercial policy that defines sale commitment levels in line with the capacity of its generating facilities during a dry year, by including risk mitigation clauses with unregulated clients in some contracts. In the case of regulated clients subject to long-term tender processes, indexing polynomials are determined in order to reduce commodity exposure.

Considering the operating conditions faced by the electricity generation market, drought and volatility of commodity prices in international markets, the Company is constantly evaluating the convenience of contracting hedges to mitigate the impact of price changes on profits.

As of December 31, 2018, there were operations of energy futures purchase agreements in place for the amount of 5.28 GWh. Said purchases support energy sale contracts on the wholesale market. As of December 31, 2018, 10.9 GWh in sale contracts and 7.2 GWh energy futures purchases have been settled.

As of December 31, 2017, there were contracts for the purchase of energy futures in place for 5.4 GWh for the January-March 2018 period. Said purchases support an energy sale contract in the Colombian wholesale market. As of December 31, 2017, 24.2 GWh in sale contracts and 77.5 GWh energy futures purchases have been settled.

We are continually analyzing strategies to hedge commodity price risk, including transferring commodity price variations to customers’ contract prices, adjusting commodity indexed price formulas for new Power Purchase Agreements according to our exposure, or analyzing ways to mitigate risk through hydrological insurance in dry years. In the future, we may consider using price-sensitive instruments.

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Interest Rate and Foreign Currency Risk

As of December 31, 2018, the carrying values according to maturity and the corresponding fair value of our interest bearing debt are detailed below.  Values do not include derivatives.

	Expected maturity date
															Fair
For the year ended December 31.	2019		2020		2021		2022		2023		Thereafter		Total		Value(1)
	(in millions of US$)(1)
Fixed Rate
Ch$/UF	0		0		0		0		0		0		0		0
Weighted average interest rate	—		—		—		—		—		—		—		—
US$	309		256		128		6		4		632		1,334		1,333
Weighted average interest rate	3.2	%	4.2	%	3.8	%	2.0	%	0.8	%	4.1	%	3.9	%	—
Other currencies(2)	2,875		118		296		223		56		331		3,899		3,998
Weighted average interest rate	6.7	%	7.4	%	8.3	%	7.1	%	6.1	%	6.3	%	6.8	%	—
Total fixed rate	3,184		374		423		230		60		963		5,233		5,331
Weighted average interest rate	6.3	%	5.2	%	7.0	%	6.9	%	5.8	%	4.9	%	6.0	%	—
Variable Rate
Ch$/UF	6		6		7		4		—		—		23		25
Weighted average interest rate	9.9	%	9.9	%	9.9	%	9.9	%	—		—		9.9	%	—
US$	462		60		97		—		—		1		621		617
Weighted average interest rate	3.6	%	3.9	%	3.0	%	—		—		3.2	%	3.6	%
Other currencies(2)	519		399		475		399		477		691		2,960		2,970
Weighted average interest rate	7.7	%	7.8	%	7.3	%	7.0	%	6.8	%	7.5	%	7.4	%	—
Total variable rate	987		466		579		403		477		693		3,605		3,612
Weighted average interest rate	5.8	%	7.3	%	6.6	%	7.1	%	6.8	%	7.5	%	6.7	%	—
Total	4,171		839		1,002		632		537		1,655		8,837		8,943

(1)Calculated based on the foreign exchange rate of the applicable foreign currency to the U.S. dollar as of December 31, 2018.

(2)As of December 31, 2018, fair value was 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 Brazilian real, Colombian peso, Argentine peso and Peruvian Nuevo Sol.

As of December 31, 2017, the carrying values according to maturity and the corresponding fair value of our interest bearing debt are detailed below.  Values do not include derivatives.

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	Expected maturity date
For the year ended December 31,	2018		2019		2020		2021		2022		Thereafter		Total		FairValue(2)
	(in millions of US$) (1)
Fixed Rate
Ch$/UF	—		—		—		—		—		—		—		—
Weighted average interest rate	—		—		—		—		—		—		—		—
US$	71		295		214		100		6		636		1,323		1,317
Weighted average interest rate	3.4	%	3.3	%	4.1	%	3.7	%	2.1	%	4.1	%	3.8	%	—
Other currencies(3)	82		236		121		292		238		308		1,277		1,442
Weighted average interest rate	6.1	%	7.3	%	7.4	%	7.7	%	7.1	%	6.4	%	7.1	%	—
Total fixed rate	153		531		336		392		244		944		2,600		2,759
Weighted average interest rate	4.9	%	5.1	%	5.3	%	6.7	%	7.0	%	4.8	%	5.4	%	—
Variable Rate
Ch$/UF	6		7		7		8		4		—		32		36
Weighted average interest rate	8.3	%	8.3	%	8.3	%	8.3	%	8.3	%	8.3	%	8.3	%	—
US$	46		76		60		—		—		1		184		179
Weighted average interest rate	4.0	%	3.5	%	3.3	%	—		—		2.5	%	3.5	%
Other currencies(3)	395		368		376		244		219		560		2,161		2,358
Weighted average interest rate	10.4	%	9.6	%	7.9	%	9.0	%	8.1	%	8.7	%	9.0	%	—
Total variable rate	448		450		443		251		223		561		2,376		2,573
Weighted average interest rate	9.7	%	8.5	%	7.2	%	9.0	%	8.2	%	8.7	%	8.5	%	—
Total	600		982		779		643		467		1,506		4,977		5,331

(1)Calculated based on the foreign exchange rate of the applicable foreign currency to the U.S. dollar as of December 31, 2017.

(2)As of December 31, 2017, fair value was 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 Brazilian real, Colombian peso, Argentine peso and Peruvian Nuevo 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 the debt structure, we sometimes manage interest rate risk through the use of interest rate derivatives.

As of December 31, 2018 and 2017, 59% and 46%, respectively, of our total outstanding debt was denominated in fixed terms and 41% and 54% respectively was subject to variable interest rates. Because of the exposure to variable interest rate risk, we engage in derivative hedging instruments.

As of December 31, 2018, 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:

	Expected Maturity Date
For the year ended December 31,	2019	2020	2021	2022	2023	Thereafter	Total	FairValue(1)
	(in millions of US$)
Variable to fixed rates	698	—	—	—	—	—	698	(1.156	)
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	698	—	—	—	—	—	698	(1.156	)

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(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.

As of December 31, 2017, 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:

	Expected Maturity Date
For the year ended December 31,	2018	2019	2020	2021	2022	Thereafter	Total	FairValue(1)
	(in millions of US$)
Variable to fixed rates	46	162	—	—	—	—	208	1.609
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	46	162	—	—	—	—	208	1.609

(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.

Foreign Currency Risk

Our policy seeks to maintain a balance between the currency in which cash flows are indexed and the currency of the principal debt of each company. Most of our subsidiaries have access to funding in the same currency as their revenues, therefore reducing the exchange rate volatility impact. In some cases, we cannot fully benefit from this, and therefore, we try to manage the exposure with financial derivatives such as cross currency swaps or currency forwards, among others. However, this may not always be possible under reasonable terms due to market conditions. This is the case of Costanera in Argentina which has its revenues linked to the Argentine peso, and a substantial part of its debt denominated in U.S. dollars, with no possibility of hedging this debt under reasonable market conditions. Costanera’s debt denominated in U.S. dollars amounted to US$ 54 million as of December 31, 2018.

As of December 31, 2018, 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,	2019	2020	2021	2022	2023	Thereafter	Total	FairValue(1)
	(in millions of US$)
UF to US$	—	—	—	—	—	—	—	—
US$ to Ch$/UF	—	—	—	—	—	—	—	—
US$ to R$	717	230	173	—	—	—	1,120	124.5
US$ to other currencies(2)	—	—	—	—	—	—	—	—
Other currencies to US$	—	—	—	—	—	—	—	—
Total	717	230	173	—	—	—	1,120	124.5

(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)“Other currencies” include the Euro, Colombian peso, Argentine peso and Peruvian Nuevo Sol.

As of December 31, 2017, 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:

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	Expected Maturity Date
For the year ended December 31,	2018	2019	2020	2021	2022	Thereafter	Total	FairValue(1)
	(in millions of US$)
UF to US$	—	—	—	—	—	—	—	—
US$ to Ch$/UF	—	—	—	—	—	—	—	—
US$ to R$	67	778	224	76	—	—	1,144	(8.38	)
US$ to other currencies(2)	34	—	—	—	—	—	34	(0.44	)
Other currencies to US$	—	—	—	—	—	—	—	—
Total	101	778	224	76	—	—	1,178	(8.83	)

(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 Euro, Colombian peso, Argentine peso and Peruvian Nuevo Sol.

For further detail please refer to Note 21 of the Notes to our consolidated financial statements.

(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 ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. In the case of distributions other than cash, the Depositary will invoice the applicable ADS record date holders. The Depositary may generally refuse to provide the requested services

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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 ADS 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 ADS	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 ADS pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADS	Up to US$5 per 100 ADSs (or fraction thereof) held
(5) Distribution of securities other than ADS or rights to purchase additional ADS (i.e., 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

The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. In the case of distributions other than cash, the Depositary will invoice the applicable ADS record date holders.

Depositary Payments for Fiscal Year 2018

The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2018, the Depositary reimbursed expenses related primarily to investor relations’ activities for a total amount of US$ 1.4 million (after the deduction of applicable U.S. taxes).

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) for the year ended December 31, 2018.

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.

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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 Rule 13 a-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.

Enel Distribution Sao Paulo became part of our consolidated subsidiaries as of June 7, 2018 because of its acquisition. Enel Distribution Sao Paulo represents 21.8% of our total consolidated assets and 18.7% of our total consolidated revenues as reported in our consolidated financial statements as of and for the year ended December 31, 2018.

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, 2018. 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 excluded from the scope of its assessment of internal control over financial reporting the operations and related assets of Enel Distribution Sao Paulo, in accordance with applicable guidance provided by the SEC, since the company constituted 21.8% of our total consolidated assets and 18.7% of our total consolidated revenues as reported in our consolidated financial statements as of and for the year ended December 31, 2018. Based on the assessment, our management has concluded that as of December 31, 2018, 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, 2018. Their attestation report appears on page F-2.

(d)Changes in Internal Control Over Financial Reporting

During the first half of 2018, Enel Distribution Sao Paulo became part of our consolidated subsidiaries as of June 7, 2018 because of its acquisition. Enel Distribution Sao Paulo represents 21.8% of our total consolidated assets and 18.7% of our total consolidated revenues as reported in our consolidated financial statements as of and for the year ended December 31, 2018.

Enel Distribution Sao Paulo will be included in the scope of the internal control model for financial reporting in 2019 and its processes and controls will be included and certified in 2019.

There were no additional changes in our internal control over financial reporting identified in connection with the evaluation required by Rules 13a-15(d) or 15d-15(d) under the Exchange Act that occurred during 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting model.

Item 16. Reserved

Item 16A.              Audit Committee Financial Expert

As of December 31, 2018, the Directors’ Committee (which performs the functions of the Audit Committee) financial expert was Mr. Hernán Somerville, as determined by the Board of Directors. Mr. Somerville is an independent member of the Directors’ Committee pursuant to the requirement of both Chilean law and NYSE corporate governance rules.

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Item 16B.              Code of Ethics

Our standards of ethical conduct are governed by means of the following seven corporate rulings or policies: the Charter Governing Executives (“Estatuto del Directivo”), the Employee Code of Conduct, the Code of Ethics, the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Human Rights Policy, the Manual for the Management of Information of Interest to the Market (the “Manual”) and the Diversity Policy.

The Charter Governing Executives was adopted by the Board of Directors in May 2003 and is applicable to all executives contractually related to us or our subsidiaries in which we are the majority shareholder, including the Chief Executive Officer, the Chief Financial Officer and other senior officers of the Company. The objective of this set of rules is to establish standards for the governance of our management’s actions, the behavior of management with respect to the principles governing their actions and the limitations and incompatibilities involved, all within the context of our vision, mission and values. Likewise, the Employee Code of Conduct explains our principles and ethical values, establishes the rules governing our contact with customers and suppliers, and establishes the principles that should be followed by employees, including ethical conduct, professionalism and confidentiality. Both documents also impose limitations on the activities that our executives and other employees may undertake outside the scope of their employment with us.

The Manual, adopted by our Board of Directors in May 2008 and amended in February 2010, 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 mechanisms that provide protection for confidential information.

In addition to the corporate governance rules described above, our Board approved the Code of Ethics and the ZTAC Plan in its meeting held on June 24, 2010. The Code of Ethics is based on general principles such as impartiality, honesty, integrity and other values of similar importance, which are translated into detailed behavioral criteria. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with a special emphasis in avoiding corruption in the form of bribes, preferential treatment, and other similar matters.

On October 30, 2013, the Board approved the Human Rights Policy, which incorporates and adapts the general human rights principles championed by the United Nations into a corporate reality.

The Diversity Policy was approved by the Board of Directors on March 23, 2016. This policy defines the key principles required to spread a culture that focuses on diversity and is based on the respect and promotion of the principles of preventing arbitrary discrimination and encouraging equal opportunities and inclusion, which are fundamental values in the development of our activities. By means of this policy, we seek to improve the work environment and the quality of life at work. We are 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) 2353-4682

During fiscal year 2017, at its meeting held on January 19, 2017, our Board of Directors approved an amendment to the Code of Ethics and ZTAC Plan to eliminate the reference to Law 19,885 in connection with political donations and to forbid them under all circumstances. Other than this, there have been no amendments to any provisions of the documents described above during fiscal year 2018. No waivers from any provisions of the Charter Governing Executives, the Employee Code of Conduct, the Code of Ethics, 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 fiscal year 2018.

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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, as well as the other member firms and their respective affiliates, by type of services for the periods indicated.

Services Rendered	2018	2017
	(in thousands of US$)
Audit fees(1)	3,859	3,097
Audit-related fees(2)	575	830
Tax fees	—	—
All other fees	63	54
Total	4,497	3,981

(1)The amounts for 2018 includes auditing services in connection with Enel Distribution Sao Paulo for ThUS$ 577.

(2)The amounts for 2017 include non-recurrent services in connection with bond issuances in Brazil for ThUS$ 166 and auditing procedures at Enel Distribution Goias for ThUS$ 172.

All of 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 the related footnotes have been classified in accordance with SEC guidance.

Directors’ Committee Pre-Approval Policies and Procedures

Our external auditors are appointed by our shareholders at the OSM. Similarly, the shareholders of our subsidiaries appoint their own external auditors according to applicable law and regulation in each respective country.

The Directors’ Committee (which performs the functions of the Audit Committee), reviews engagement letters with external auditors, ensures quality control in respect of the services provided, reviews and controls independence issues, and other related matters.

The Directors’ 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 they have been analyzed by the CFO, are submitted to the Directors’ Committee for approval or rejection.

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 CFO review the nature of the service to be provided.

·The CFO 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 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 new requirements described in SEC release number 34-53677, File No. PCAOB-2006-01 (Audit Committee Pre-Approval of Certain Tax Services).

Item 16D.Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item 16E.Purchases of Equity Securities by the Issuer and Affiliated Purchasers

There were no purchases of the Company’s common stock or ADSs by the Company or any of its affiliated purchasers during 2018.  However, on March 21, 2019 Enel reported that on March 18, 2019, it had acquired beneficial ownership of 18,931,352 ADSs representing 946,567,600 shares of common stock, or 1.65% of the outstanding shares of common stock, under a share swap transaction with respect to ADSs entered into by Enel in October 2018, which was terminated on March 18, 2019.  In addition, on April 10, 2019 Enel reported that on April 9, 2019, it had acquired beneficial ownership of an additional 1,707,765,225 shares of

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common stock, or 2.97% of the outstanding common stock, under a separate share swap transaction with respect to shares of common stock entered into by Enel in October 2018.  The share swap transaction with respect to shares of common stock remains in effect with respect to 218,298,845 shares of common stock of the Company.  As a result of the two equity swap transactions described here, Enel increased its beneficial ownership in the Company from 51.8% as of the end of December 31, 2018 to 56.4% as of the date of this Report.

Item 16F.Change in Registrant’s Certifying Accountant

None.

Item 16G.Corporate Governance

For a summary of the significant differences between our corporate governance practices and those applicable to domestic issuers under the corporate governance rules of the NYSE, see “Item 6. Directors, Senior Management and Employees — C. Board Practices.”

Item 16H.Mine Safety Disclosure

Not applicable.

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PART III

Item 17.Financial Statements

Not Applicable.

Item 18.Financial Statements

ENEL AMÉRICAS S.A. and Subsidiaries

Index to the Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firms:

Report of EY Audit SpA— Enel Américas S.A. 2018, 2017 and 2016	F-1
Report of EY Audit SpA — Enel Américas S.A. — Internal Control Over Financial Reporting 2018	F-2
Consolidated Financial Statements:
Consolidated Statements of Financial Position as of December 31, 2018 and 2017	F-4
Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016	F-6
Consolidated Statements of Changes in Equity for the years ended December 31, 2018, 2017, and 2016	F-8
Consolidated Statements of Direct Cash Flows for the years ended December 31, 2018, 2017, and 2016	F-10
Notes to the Consolidated Financial Statements	F-11

Ch$	Chilean pesos
US$	U.S. dollars
UF	The UF is a Chilean inflation-indexed, 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
AR$	Argentine pesos
CP$	Colombian pesos
R$	Brazilian Reals
Ps$	Peruvian Soles

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Item 19.Exhibits

Exhibit	Description
1.1	By-laws (Estatutos) of Enel Américas S.A., as amended.
8.1	List of Principal Subsidiaries as of December 31, 2018
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 EY Audit SpA., an independent registered public accounting firm

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase 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 26, 2019

174

Enel Américas S.A. and Subsidiaries

Consolidated financial statements as of December 31, 2018 and 2017

Index to the Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm
Report of EY Audit SpA — Enel Américas S.A. 2018, 2017 and 2016	F-1
Report of EY Audit SpA — Enel Américas S.A. — Internal Control Over Financial Reporting 2018	F-2
Consolidated Financial Statements:
Consolidated Statements of Financial Position as of December 31, 2018 and 2017	F-4
Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016	F-6
Consolidated Statements of Changes in Equity for the years ended December 31, 2018, 2017 and 2016	F-8
Consolidated Statements of Direct Cash Flows for the years ended December 31, 2018, 2017 and 2016	F-10
Notes to the Consolidated Financial Statements	F-11

Ch$	Chilean pesos
US$	U.S. dollars
UF	The UF is a Chilean inflation-indexed, 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
AR$	Argentine pesos
CP$	Colombian pesos
R$	Brazilian Reals
PS$	Peruvian Soles

EY Audit SpA Avda. Presidente Riesco 5435, piso 4, 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 the accompanying consolidated balance sheets of Enel Américas S.A. and subsidiaries (the Company) as of December 31, 2018 and 2017, the related consolidated statements of comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

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, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated April 25, 2019 expressed an unqualified opinion thereon.

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 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.

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 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 audits 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 audits provide a reasonable basis for our opinion.

/s/ EY Audit SpA.

EY Audit SpA.

We have served as the Company’s auditor since 2011.

Santiago, Chile
April 25, 2019

F-1

EY Audit SpA Avda. Presidente Riesco 5435, piso 4, 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 Internal Control over Financial Reporting

We have audited Enel Américas S.A. and subsidiaries’ internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Enel Américas S.A. and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Enel Distribution Sao Paulo S.A., which are consolidated from June 2018 and constituted 21.8% and 18.7% of total and net assets, respectively, as of December 31, 2018 and 18.7% and 1.3% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Enel Distribution Sao Paulo S.A.

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, 2018 and 2017, the related consolidated statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and our report dated April 25, 2019 expressed an unqualified opinion thereon.

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.

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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

F-2

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/ EY Audit SpA.

EY Audit SpA.

Santiago, Chile

April 25, 2019

F-3

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Financial Position

As of December 31, 2018 and December 31, 2017

(In thousands of US Dollars — ThUS$)

		12-31-2018	12-31-2017
ASSETS	Note	ThUS$	ThUS$
CURRENT ASSETS
Cash and cash equivalents	9	1,904,285	1,472,763
Other current financial assets	10	210,393	110,352
Other current non-financial assets	11	307,732	283,632
Trade and other current receivables	12	3,551,022	2,377,789
Current accounts receivable from related parties	13	14,337	7,403
Inventories	14	339,398	246,089
Current tax assets	15	50,994	47,393
Total current assets other than assets or groups of assets for disposal classified as held for sale or as held for distribution to owners		6,378,161	4,545,421
Non-current assets or disposal groups held for sale or for distribution to owners	6.2	5,825	—
TOTAL CURRENT ASSETS		6,383,986	4,545,421
NON-CURRENT ASSETS
Other non-current financial assets	10	2,796,475	1,752,267
Other non-current non-financial assets	11	1,140,708	560,426
Trade and other non-current receivables	12	906,508	616,793
Non-current accounts receivable from related parties	13	1,652	2,845
Investments accounted for using the equity method	16	2,596	2,747
Intangible assets other than goodwill	17	5,827,289	3,682,479
Goodwill	18	1,205,570	713,175
Property, plant and equipment	19	8,686,827	8,092,467
Investment property		11,708	—
Deferred tax assets	20	433,037	200,371
TOTAL NON-CURRENT ASSETS		21,012,370	15,623,570
TOTAL ASSETS		27,396,356	20,168,991

The accompanying notes are an integral part of these consolidated financial statements.

F-4

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Financial Position

As of December 31, 2018 and December 31, 2017

(In thousands of US Dollars — ThUS$)

		12-31-2018		12-31-2017
LIABILITIES AND EQUITY	Note	ThUS$		ThUS$
CURRENT LIABILITIES
Other current financial liabilities	21	1,648,099		689,768
Trade and other current payables	24	4,116,247		3,323,853
Current accounts payable to related parties	13	2,996,668		225,027
Other current provisions	25	422,863		269,966
Current tax liabilities	15	192,924		172,638
Other current non-financial liabilities	11	270,120		253,084
Total current liabilities other than those associated with groups of assets for disposal classified as held for sale		9,646,921		4,934,336
Liabilities associated with disposal groups held for sale or for distribution to owners	6.2	3,835		—
TOTAL CURRENT LIABILITIES		9,650,756		4,934,336
NON-CURRENT LIABILITIES
Other non-current financial liabilities	21	4,621,868		4,349,515
Trade and other non-current payables	24	933,056		978,569
Other long-term provisions	25	1,363,976		660,305
Deferred tax liabilities	20	546,070		455,311
Non-current provisions for employee benefits	26	1,343,507		388,931
Other non-current non-financial liabilities	11	105,223		123,517
TOTAL NON-CURRENT LIABILITIES		8,913,700		6,956,148
TOTAL LIABILITIES		18,564,456		11,890,484
EQUITY
Issued capital	27.1.1	6,763,204		6,763,204
Treasury shares		—		—
Retained earnings		4,841,687		3,583,831
Other reserves	27.6	(4,880,883	)	(3,866,564	)
Equity attributable to shareholders of Enel Américas		6,724,008		6,480,471
Non-controlling interests	27.7	2,107,892		1,798,036
TOTAL EQUITY		8,831,900		8,278,507
TOTAL LIABILITIES AND EQUITY		27,396,356		20,168,991

The accompanying notes are an integral part of these consolidated financial statements.

F-5

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Nature

For the years ended December 31, 2018, 2017 and 2016

(In thousands of US Dollars — ThUS$)

		For the years ended December 31,
		2018		2017		2016
STATEMENTS OF PROFIT (LOSS)	Note	ThUS$		ThUS$		ThUS$
Revenues	28	12,119,134		9,489,266		7,007,908
Other operating income	28	1,064,928		948,737		634,674
Revenues and Other Operating Income		13,184,062		10,438,003		7,642,582
Raw materials and consumables used	29	(8,142,773	)	(5,882,788	)	(3,868,218	)
Contribution Margin		5,041,289		4,555,215		3,774,364
Other work performed by the entity and capitalized		177,997		173,186		99,449
Employee benefits expenses	30	(840,493	)	(837,984	)	(626,102	)
Depreciation and amortization expense	31	(862,440	)	(648,114	)	(473,238	)
Impairment loss recognized in the period’s profit or loss	31	(60,748	)	(79,748	)	(157,078	)
Other expenses	32	(1,021,085	)	(943,156	)	(817,375	)
Operating income		2,434,520		2,219,399		1,800,020
Other gains (losses)	33	681		5,345		12,141
Financial income	34	358,081		293,843		276,457
Financial costs	34	(1,071,759	)	(869,535	)	(773,157	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	16	2,452		3,310		2,706
Foreign currency exchange differences	34	110,635		(6,714	)	58,934
Gains (losses) from indexed assets and liabilities (*)	34	270,380		—		(1,032	)
Income from continuing operations, before taxes		2,104,990		1,645,648		1,376,069
Income tax expenses, continuing operations	20	(437,932	)	(519,134	)	(531,461	)
INCOME AFTER TAX FROM CONTINUING OPERATIONS		1,667,058		1,126,514		844,608
Income after tax from discontinued operations		—		—		170,263
NET INCOME		1,667,058		1,126,514		1,014,871
Net income attributable to:
Shareholders of Enel Américas		1,201,381		709,043		566,497
Non-controlling interests	27.6	465,677		417,471		448,374
NET INCOME		1,667,058		1,126,514		1,014,871
Basic and diluted earnings per share
Basic and diluted earnings per share from continuing operations	US$/Share	0.02091		0.01234		0.00907
Basic and diluted earnings per share from discontinued operations	US$/Share	—		—		0.00232
Basic and diluted earnings per share	US$/Share	0.02091		0.01234		0.01139
Weighted average number of shares of common stock		57,452,641,516		57,452,641,516		49,768,783,340
Diluted earnings per share
Diluted earnings per share from continuing operations	US$/Share	0.02091		0.01234		0.01275
Diluted earnings per share from discontinued operations	US$/Share	—		—		0.00232
Diluted earnings per share	US$/Share	0.02091		0.01234		0.01139
Weighted average number of shares of common stock		57,452,641,516		57,452,641,516		49,768,783,340

(*)In 2018, this corresponds to the effect from the hyperinflation in Argentina (see note 8).

The accompanying notes are an integral part of these consolidated financial statements.

F-6

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Nature (continued)

For the years ended December 31, 2018, 2017 and 2016

(In thousands of US Dollars — ThUS$)

		For the years ended December 31,
		2018		2017		2016
STATEMENTS OF COMPREHENSIVE INCOME	Note	ThUS$		ThUS$		ThUS$
Net Income		1,667,058		1,126,514		1,014,871
Components of other comprehensive income that will not be reclassified subsequently to profit or loss, before taxes
Remeasurement (loss) from defined benefit plans		(177,527	)	(4,941	)	(29,399	)
Other comprehensive loss that will not be reclassified subsequently to profit or loss		(177,527	)	(4,941	)	(29,399	)
Components of other comprehensive income that will be reclassified subsequently to profit or loss, before taxes
Foreign currency translation gains (losses)		(1,575,134	)	(95,501	)	214,887
Gains (losses) from available-for-sale financial assets		(458	)	(829	)	976
Share of other comprehensive income (loss) from associates and joint ventures accounted for using the equity method		—		—		(20,832	)
Gains (losses) from cash flow hedge		(5,763	)	12,723		22,030
Adjustments from reclassification of cash flow hedges, transferred to profit or loss		3,036		12		6,701
Other comprehensive income (loss) that will be reclassified subsequently to profit or loss		(1,578,319	)	(83,595	)	223,762
Total components of other comprehensive income (loss), before taxes		(1,755,846	)	(88,536	)	194,363
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		59,684		3,694		9,592
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss		59,684		3,694		9,592
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss
Income tax related to cash flow hedge		1,354		(5,088	)	(6,816	)
Income tax related to available-for-sale financial assets		—		—		—
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss		1,354		(5,088	)	(6,816	)
Total Other Comprehensive Income (Loss)		(1,694,808	)	(89,930	)	197,139
TOTAL COMPREHENSIVE INCOME		(27,750	)	1,036,584		1,212,010
Comprehensive income attributable to:
Shareholders of Enel Américas		(121,326	)	650,731		788,647
Non-controlling interests		93,576		385,853		423,363
TOTAL COMPREHENSIVE INCOME		(27,750	)	1,036,584		1,212,010

The accompanying notes are an integral part of these consolidated financial statements.

F-7

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Changes in Equity

For years ended December 31, 2018, 2017 and 2016

(In thousands of US Dollars — ThUS$)

			Changes in Other Reserves
Statement of Changes in Equity	Issued Capital	Treasury Shares	Reserve for Exchange Differences in Translation		Reserves for Cash Flow Hedges		Reserve for Gains and Losses for Defined Benefit Plans		Reserve for Gains and Losses on Remeasuring Available-for-Sale Financial Assets		Other Miscellaneous Reserves		Amounts recognized in other comprehensive income and accumulated in equity related to non-current assets or groups of assets for disposal classified as held for sale	Total Other Reserves		Retained Earnings		Equity Attributable to Shareholders of Enel Américas		Non-Controlling Interests		Total Equity
Equity at beginning of period 1/1/2018	6,763,204	—	(453,995	)	(3,472	)	—		(175	)	(3,408,922	)	—	(3,866,564	)	3,583,831		6,480,471		1,798,036		8,278,507
Increase (decrease) through changes in accounting policies (1)	—	—	—		—		—		—		—		—	—		667,447		667,447		286,583		954,030
Equity at beginning of period 1/1/2018 (As Restated)	6,763,204	—	(453,995	)	(3,472	)	—		(175	)	(3,408,922	)	—	(3,866,564	)	4,251,278		7,147,918		2,084,619		9,232,537
Changes in equity
Comprehensive income:	—	—	—		—		—		—		—		—	—		—		—		—		—
Profit (loss)	—	—	—		—		—		—		—		—	—		1,201,381		1,201,381		465,677		1,667,058
Other comprehensive income (loss)	—	—	(1,212,114	)	(1,622	)	(108,749	)	(222	)	—		—	(1,322,707	)	—		(1,322,707	)	(372,101	)	(1,694,808	)
Comprehensive income											—		—	—		—		(121,326	)	93,576		(27,750	)
Dividends	—	—	—		—		—		—		—		—	—		(502,223	)	(502,223	)	(255,242	)	(757,465	)
Increase (decrease) from other changes	—	—	—		—		108,749		—		199,639		—	308,388		(108,749	)	199,639		184,939		384,578
Total changes in equity	—	—	(1,212,114	)	(1,622	)	—		(222	)	199,639		—	(1,014,319	)	590,409		(423,910	)	23,273		(400,637	)
Equity at end of period 12/31/2018	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 Other Reserves
Statement of Changes in Equity	Issued Capital		Share Premium		Reserve for Exchange Differences in Translation		Reserves for Cash Flow Hedges		Reserve for Gains and Losses for Defined Benefit Plans		Reserve for Gains and Losses on Remeasuring Available-for-Sale Financial Assets		Other Miscellaneous Reserves		Amounts recognized in other comprehensive income and accumulated in equity related to non-current assets or groups of assets for disposal classified as held for sale (2)	Total Other Reserves		Retained Earnings		Equity Attributable to Shareholders of Enel Américas		Non-Controlling Interests		Total Equity
Equity at beginning of period 1/1/2017	9,023,164		(139,630	)	(2,610,348	)	(4,426	)	—		217		(4,093,262	)	—	(6,707,819	)	4,023,919		6,199,634		1,680,105		7,879,739
Increase (decrease) through changes in accounting policies (1)	(2,119,480	)	(849	)	2,221,406		(6,997	)	—		10		728,703		—	2,943,122		(822,793	)	—		—		—
Equity at beginning of period 1/1/2017 (As Restated)	6,903,684		(140,479	)	(388,942	)	(11,423	)	—		227		(3,364,559	)	—	(3,764,697	)	3,201,126		6,199,634		1,680,105		7,879,739
Changes in equity
Comprehensive income	—		—		—		—		—		—		—		—	—		—		—		—		—
Profit (loss)	—		—		—		—		—		—		—		—	—		709,043		709,043		417,471		1,126,514
Other comprehensive income (loss)	—		—		(65,053	)	7,951		(808	)	(402	)	—		—	(58,312	)	—		(58,312	)	(31,618	)	(89,930	)
Comprehensive income	—		—		—		—		—		—		—		—	—		—		650,731		385,853		1,036,584
Dividends	—		—		—		—		—		—		—		—	—		(325,530	)	(325,530	)	(230,272	)	(555,802	)
Increase (decrease) from other changes	(140,480	)	140,479		—		—		808		—		(44,363	)	—	(43,555	)	(808	)	(44,364	)	(37,650	)	(82,014	)
Total changes in equity	(140,480	)	140,479		(65,053	)	7,951		—		(402	)	(44,363	)	—	(101,867	)	382,705		280,837		117,931		398,768
Equity at end of period 12/31/2017	6,763,204		—		(453,995	)	(3,472	)	—		(175	)	(3,408,922	)	—	(3,866,564	)	3,583,831		6,480,471		1,798,036		8,278,507

The accompanying notes are an integral part of these consolidated financial statements.

F-8

					Changes in Other Reserves
Statement of Changes in Equity	Issued Capital		Share Premium		Reserve for Exchange Differences in Translation		Reserves for Cash Flow Hedges		Reserve for Gains and Losses for Defined Benefit Plans		Reserve for Gains and Losses on Remeasuring Available-for-Sale Financial Assets		Other Miscellaneous Reserves		Amounts recognized in other comprehensive income and accumulated in equity related to non-current assets or groups of assets for disposal classified as held for sale (2)		Total Other Reserves		Retained Earnings		Equity Attributable to Shareholders of Enel Américas		Non-Controlling Interests		Total Equity
Equity at beginning of period 1/1/2016 (As Restated)	10,680,663		—		(3,165,288	)	(7,649	)	—		(256	)	(4,659,748	)	(171,638	)	(8,004,579	)	5,809,538		8,485,622		3,046,721		11,532,343
Changes in equity
Comprehensive income	—		—		—		—		—		—		—		—		—		—		—		—		—
Profit (loss)	—		—		—		—		—		—		—		—		—		566,497		566,497		448,374		1,014,871
Other comprehensive income (loss)	—		—		554,940		3,223		(13,224	)	473		(189	)	(2,693	)	542,530		—		542,530		129,483		672,013
Comprehensive income	—		—		—		—		—		—		—		—		—		—		1,109,027		577,857		1,686,884
Dividends	—		—		—		—		—		—		—		—				(300,696	)	(300,696	)	(291,001	)	(591,697	)
Decrease (increase) thorough other distributions to owner	(3,211,186	)	—		—		—		—		—		1,366,382		174,331		1,540,713		(2,038,196	)	(3,708,669	)	(921,670	)	(4,630,339	)
Increase (decrease) from other changes	1,553,687		—		—		—		13,224		—		(799,707	)	—		(786,483	)	(13,224	)	753,980		(731,802	)	22,178
Increase (decrease) through treasury share transactions			(139,630	)																	(139,630	)			(139,630	)
Total changes in equity	(1,657,499	)	(139,630	)	554,940		3,223		—		473		566,486		171,638		1,296,760		(1,785,619	)	(2,285,988	)	(1,366,616	)	(3,652,604	)
Equity at end of period 12/31/2016	9,023,164		(139,630	)	(2,610,348	)	(4,426	)	—		217		(4,093,262	)	—		(6,707,819	)	4,023,919		6,199,634		1,680,105		7,879,739

(1)Considers a charge to retains earnings of ThUS$5,804 due to the application of IFRS 9, a charge to retain earning of ThUS$1,272 due to the application of IFRS 15 and a credit to retains earnings of ThUS$961,107 due to the application of IAS 29. See Note 2.2, impairments, revenue from contracts with customers and Note 8, respectively.

(2)Correspond to adjustment due to charge in functional currency, See Note 3.

The accompanying notes are an integral part of these consolidated financial statements.

F-9

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

Consolidated Statements of Cash Flows, Direct

For the years ended December 31, 2018, 2017 and 2016

(In thousands of US Dollars — ThUS$)

		For the years ended December 31,
		2018		2017		2016
Statements of Direct Cash Flows	Note	ThUS$		ThUS$		ThUS$
Cash flows from (used in) operating activities
Types of collection from operating activities
Collections from the sale of goods and services		16,445,981		12,914,844		10,523,146
Collections from royalties, payments, commissions, and other income from ordinary activities		48,659		44,388		50,068
Collections from premiums and services, annual payments, and other benefits from policies held		48,028		26,155		17,088
Other collections from operating activities		752,842		629,627		600,521
Types of payment in cash from operating activities
Payments to suppliers for goods and services		(8,597,388	)	(6,470,110	)	(5,006,113	)
Payments to and on behalf of employees		(786,892	)	(886,921	)	(678,825	)
Payments on premiums and services, annual payments, and other obligations from policies held		(11,345	)	(10,050	)	(13,287	)
Other payments for operating activities, net	9.c	(5,227,832	)	(3,629,559	)	(2,314,081	)
Cash flows from (used in) operating activities
Income taxes paid		(593,948	)	(492,495	)	(557,683	)
Other outflows of cash		(233,540	)	(255,830	)	(88,648	)
Net cash flows from operating activities		1,844,565		1,870,049		2,532,186
Cash flows from (used in) investing activities
Cash flows from the loss of control of subsidiaries or other businesses		—		—		—
Cash flows used to obtain control of subsidiaries or other businesses		(1,590,435	)	(720,401	)	(4	)
Cash flows used in the purchase of non-controlling interests		—		(80,768	)	—
Other collections from the sale of equity or debt instruments belonging to other entities		294,562		209,535		751,097
Other payments to acquire equity or debt instruments belonging to other entities		(335,668	)	(234,346	)	(737,236	)
Other payments to acquire stakes in joint ventures		—		—		—
Loans to related parties		—		(224,075	)	(34,221	)
Proceeds from the sale of property, plant and equipment		1,000		—		103,020
Purchases of property, plant and equipment		(750,435	)	(682,466	)	(824,093	)
Purchases of intangible assets		(790,184	)	(688,160	)	(405,894	)
Proceeds from the sale of other long-term assets		—		—		—
Purchases of other long-term assets		—		(435,597	)	—
Payments from future, forward, option and swap contracts		(3,079	)	(13,860	)	(8,692	)
Collections from future, forward, option and swap contracts		14,003		52,564		11,013
Collections from related parties		—		224,075		252,890
Dividends received		1,524		1,823		1,750
Interest received		99,648		100,542		126,435
Other inflows (outflows) of cash, net		(10,125	)	11,993		28,977
Net cash flows used in investing activities		(3,069,189	)	(2,479,141	)	(734,958	)
Cash flows from (used in) financing activities
Payments from changes in ownership interests in subsidiaries that do not result in loss of control		—		—		—
Payments to acquire or redeem own shares		—		—		(139,083	)
Total proceeds from loans	9.d	4,538,165		1,503,047		1,577,694
Proceeds from long-term loans		2,836,717		1,434,395		1,350,962
Proceeds from short-term loans		1,701,448		68,652		226,732
Loans from related parties		2,686,387		257,453		107,004
Payment on borrowings	9.d	(4,301,358	)	(1,127,892	)	(1,034,434	)
Payment on financial lease liabilities	9.d	(31,619	)	(46,975	)	(30,837	)
Payments on loans to related parties	9.d	—		(257,955	)	(106,237	)
Dividends paid	9.d	(591,958	)	(543,774	)	(637,864	)
Interest paid	9.d	(439,552	)	(343,991	)	(360,189	)
Other inflows (outflows) of cash, net	9.d	7,001		(28,433	)	(469,905	)
Net cash flows from (used in) financing activities		1,867,066		(588,520	)	(1,093,851	)
Net increase (decrease) in cash and cash equivalents before effect of exchange rate changes		642,442		(1,197,612	)	703,377
Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents		(210,920	)	(19,081	)	114,071
Net increase (decrease) in cash and cash equivalents		431,522		(1,216,693	)	817,448
Cash and cash equivalents at beginning of period	9	1,472,763		2,689,456		1,872,008
Cash and cash equivalents at end of period	9	1,904,285		1,472,763		2,689,456

The accompanying notes are an integral part of these consolidated financial statements.

F-10

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contents		Page
1.	THE GROUP’S ACTIVITIES AND FINANCIAL STATEMENTS	F-14
2.	BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS	F-15
2.1	Accounting principles	F-15
2.2	New accounting pronouncements	F-15
2.3	Responsibility for the information, judgments and estimates provided	F-24
2.4	Subsidiaries	F-25
	2.4.1 Changes in the scope of consolidation	F-26
	2.4.2 Consolidated companies with an economic equity interest of less than 50%	F-26
2.5	Investments in associates	F-27
2.6	Joint arrangements	F-27
2.7	Basis of consolidation and business combinations	F-28
3.	CHANGE OF FUNCTIONAL CURRENCY AND PRESENTATION CURRENCY	F-29
4.	ACCOUNTING POLICIES APPLIED	F-31
a)	Property, plant and equipment	F-31
b)	Investment Properties	F-34
c)	Goodwill	F-34
d)	Intangible assets other than goodwill	F-34
	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-36
f)	Leases	F-37
g)	Financial instruments	F-38
	g.1) Financial assets other than derivatives	F-38
	g.2) Cash and cash equivalents	F-39
	g.3) Impairment of financial assets	F-39
	g.4) Financial liabilities other than derivatives	F-39
	g.5) Derivative financial instruments and hedging transactions	F-40
	g.6) Derecognition of financial assets and liabilities	F-41
	g.7) Offsetting financial assets and liabilities	F-42
	g.8) Financial guarantee contracts	F-42
h)	Measurement of fair value	F-42
i)	Investments accounted for using the equity method	F-43
j)	Inventories	F-43
k)	Non-current assets (or disposal groups) classified as held for sale or as held for distribution to owners and discontinued operations	F-44
l)	Treasury shares	F-45
m)	Provisions	F-45
	m.1) Provisions for post-employment benefits and similar obligations	F-45
n)	Translation of balances in foreign currency	F-46
o)	Current/non-current classification	F-46
p)	Income taxes	F-46
q)	Revenues and expense recognition	F-47
r)	Earnings per share	F-48
s)	Dividends	F-49
t)	Share issuance costs	F-49
u)	Statement of cash flows	F-49
v)	Functional currency	F-49
5.	SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS	F-50

F-11

a)	Regulatory framework	F-50
b)	Tariff Revisions	F-78
6.	NON-CURRENT ASSETS OR DISPOSAL GROUPS HELD FOR SALE OR HELD FOR DISTRIBUTION TO OWNERS AND DISCONTINUED OPERATIONS	F-86
6.1	Corporate Reorganization	F-86
6.2	Operation Central Rio Negro (CODENSA)	F-91
7.	BUSINESS COMBINATION	F-92
7.1	ACQUISITION OF ENEL DISTRIBUCION GOÍAS (FORMERLY CELG DISTRIBUIÇÃO S.A.)	F-92
7.2	ACQUISITION OF ENEL DISTRIBUCIÓN SAO PAULO S.A. (“FORMERLY ELETROPAULO METROPOLITANA DE ELETRICIDADE DE SAO PAULO S.A.”)	F-94
8.	ARGENTINA’S HYPERINFLATIONARY ECONOMY	F-96
9.	CASH AND CASH EQUIVALENTS	F-98
10.	OTHER FINANCIAL ASSETS	F-100
11.	OTHER NON-FINANCIAL ASSETS AND LIABILITIES	F-102
12.	TRADE AND OTHER RECEIVABLES	F-103
13.	BALANCES AND TRANSACTIONS WITH RELATED PARTIES	F-104
13.1	Balances and transactions with related parties	F-105
	a) Receivables from related companies	F-105
	b) Accounts payable to related companies	F-106
	c) Significant transactions and effects on income/expenses:	F-107
	d) Significant transactions Enel Américas	F-107
13.2	Board of directors and key management personnel	F-108
	a) Accounts receivable and payable and other transactions	F-108
	b) Compensation for directors	F-108
	c) Guarantees given by the Company in favor of the directors	F-110
13.3	Compensation for key management personnel	F-110
	a) Remunerations received by key management personnel	F-110
	b) Guarantees established by the Company in favor of key management personnel	F-111
13.4	Compensation plans linked to share price	F-111
14.	INVENTORIES	F-111
15.	CURRENT TAX ASSETS AND LIABILITIES	F-112
16.	INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD	F-113
16.1.	Investments accounted for using the equity method	F-113
17.	INTANGIBLE ASSETS OTHER THAN GOODWILL	F-114
18.	GOODWILL	F-116
19.	PROPERTY, PLANT AND EQUIPMENT	F-118
20.	INCOME TAX AND DEFERRED TAXES	F-122
	a) Income taxes	F-122
	b) Deferred taxes	F-123
21.	OTHER FINANCIAL LIABILITIES	F-126
21.1	Interest-bearing borrowings	F-126
21.2	Unsecured liabilities	F-130
21.3	Secured liabilities	F-130
21.4	Hedged debt	F-137
21.5	Other information	F-137
21.6	Future undiscounted debt flows	F-138
22.	RISK MANAGEMENT POLICY	F-142
22.1	Interest rate risk	F-142
22.2	Exchange rate risk	F-142
22.3	Commodities risk	F-143
22.4	Liquidity risk	F-143
22.5	Credit risk	F-144
22.6	Risk measurement	F-144
23.	FINANCIAL INSTRUMENTS	F-145
23.1	Financial instruments, classified by type and category	F-145
23.2	Derivative instruments	F-146
23.3	Fair value hierarchies	F-148

F-12

24.	TRADE AND OTHER CURRENT AND NON-CURRENT PAYABLES	F-150
25.	PROVISIONS	F-151
26.	EMPLOYEE BENEFIT OBLIGATIONS	F-152
26.1	General information	F-152
26.2	Details, changes and presentation in financial statements	F-153
26.3	Other revelations	F-157
27.	EQUITY	F-159
27.1	Equity attributable to the shareholders of Enel Américas	F-159
27.2	Foreign currency translation reserves	F-163
27.3	Capital Management	F-163
27.4	Restrictions on subsidiaries transferring funds to the parent	F-163
27.5	Other reserves	F-164
27.6	Non-controlling Interests	F-166
28.	REVENUE AND OTHER OPERATING INCOME	F-167
29.	RAW MATERIALS AND CONSUMABLES USED	F-168
30.	EMPLOYEE BENEFITS EXPENSE	F-168
31.	DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES	F-168
32.	OTHER EXPENSES	F-169
33.	OTHER GAINS (LOSSES)	F-169
34.	FINANCIAL RESULTS	F-170
35.	INFORMATION BY SEGMENT	F-171
35.1	Basis of segmentation	F-171
35.2	Generation and transmission, distribution and others	F-174
35.3	Segment information by country	F-176
35.4	Generation and Transmission, and Distribution by Country	F-179
36.	THIRD PARTY GUARANTEES, CONTINGENT ASSETS, LIABILITIES, AND OTHER COMMITMENTS	F-184
36.1	Direct guarantees	F-184
36.2	Indirect guarantees	F-185
36.3	Lawsuits and Arbitrations Proceedings	F-186
36.4	Financial restrictions	F-199
36.5	Other Information	F-203
37.	PERSONNEL FIGURES	F-212
38.	SANCTIONS	F-212
39.	ENVIRONMENT	F-219
40.	FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED	F-221
41.	SUBSEQUENT EVENTS	F-223
APPENDIX 1 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY:		F-228
APPENDIX 2 ADDITIONAL INFORMATION OFFICIAL BULLETIN No. 715 OF FEBRUARY 3, 2012:		F-232
APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:		F-234
APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY:		F-236
APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS:		F-237

F-13

ENEL AMÉRICAS S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2018 and 2017 AND FOR THE YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016

(In thousands of US Dollars — ThUS$)

1.THE GROUP’S ACTIVITIES AND FINANCIAL STATEMENTS

Enel Américas S.A. (hereinafter “Enel Américas”, the “Company” or the “Paret 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 in the securities register of the Financial Market Commission of Chile, hereinafter “CMF”, (formerly known as the Superintendency of Securities and Insurance of Chile, hereinafter “SVS”) under number 175. In addition, the Company is registered with the Securities and Exchange Commission of the United States of America (hereinafter “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 51.8% interest.

The Company was initially created in 1981 under the corporate name of 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. In the context of the restructuring process carried out by the Group (see Note 6.1), on March 1, 2016, as part of the “Spin-Off” stage, the then Enersis S.A. became Enersis Américas S.A. On December 1, 2016, upon completion of the “Merger” stage, the corporate name was changed again and the then Enersis Américas S.A. became Enel Américas S.A. For tax purposes, the Company operates under Chilean tax identification number 94.271.000-3.

As of December 31, 2018, the Group had 18,364 employees. During the year 2018, the Group averaged a total of 15,577 employees. See Note 37 for additional information regarding employee distribution by category and geographic location.

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 consultation 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-14

2.BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1Accounting principles

The consolidated financial statements as of December 31, 2018 of Enel Américas, which were approved for issuance by the Company’s Board of Directors at its meeting held on April 26, 2019 and have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

These consolidated financial statements reflect faithfully the financial position of Enel Américas and its subsidiaries as of December 31, 2018 and 2017 and the results of their operations, changes in their equity and their cash flows for each of the years in the three-year period ended December 31, 2018 and corresponding notes.

These consolidated financial statements present voluntarily the figures for 2016 of the consolidated statement of comprehensive income, the consolidated statement of cash flows, the consolidated statement of changes in equity 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 that are measured at a fair value.

2.2New accounting pronouncements

a)The following accounting pronouncements have been adopted by the Group effective as of January 1, 2018:

i.New Standards and Interpretations

New Standards and Interpretations	Mandatory Effective date:
IFRS 9: Financial Instruments	January 1, 2018
IFRS 15: Revenue from Contracts with Customers	January 1, 2018
IFRIC 22: Foreign Currency Transactions and Advance Consideration	January 1, 2018

·IFRS 9 — Financial Instruments

IFRS 9 entered into force effective as of January 1, 2018, replacing IAS 39 Financial Instruments: Recognition and Measurement. This standard contains requirements in regards to the recognition, classification and measurement of financial assets, financial liabilities and certain purchase or sale contracts of non-financial items.

The Group adopted retrospectively for transition in the first time adoption of this standard. The accumulated effect of this application was accounted for as an adjustment to the opening balance of retained earnings as of the initial application date. The Group has applied prospectively the hedge accounting requirements of IFRS 9.

Management conducted a detailed evaluatiobigfoon of the three aspects of the standard and its impact on the consolidated financial statements of the Group, which is summarized as follows:

F-15

(i)Classification and measurement

IFRS 9 introduces a new classification approach for financial assets, based on two concepts: the characteristics of the contractual cash flows of the financial assets and the business model of the entity. Under this new approach, the four classification categories of IAS 39 are replaced by the following three categories:

·Amortized cost, if the financial assets are held within a business model whose objective is to collect contractual cash flows;

·Fair value through other comprehensive income, if the financial assets are held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets; or

·Or fair value through profit or loss, a residual category which consists of financial instruments that are not held within any of the two business models previously discussed, including those held for trading and those designated at fair value on initial recognition.

For financial liabilities, IFRS 9 retains largely the existing requirements in IAS 39, with certain specific modifications under which most of the financial liabilities are measured at amortized cost, and allowing the designation of a financial liability to be measured at fair value through profit or loss, if certain criteria are met.

However, IFRS 9 introduces new requirements for financial liabilities designated at fair value through profit or loss, which states that under certain circumstances, changes in fair value originated by the variation of and entity’s own credit risk will be recognized in other comprehensive income.

Based on the business model and the characteristics of the contractual cash flows, the Group determined that the new classification requirements for financial assets did not have an impact on the consolidated financial statements of the Group. Most of the Group’s financial instruments, i.e. loans and trade receivables, will continue to be measured at amortized cost under IFRS 9, and derivative instruments will continue to be measured at fair value through profit or loss (general treatment) or through other comprehensive income (hedge accounting), as appropriate. The Group has elected to measure certain investments in equity instruments at fair value through other comprehensive income under IFRS 9.

(ii)Impairment

The new impairment model in IFRS 9 is based on expected credit losses, as opposed to the incurred loss model in IAS 39. Consequently, under IFRS 9 impairment losses will be recognized, as a general rule, earlier than previus practice.

The new impairment model will be applied to financial assets measured at amortized cost and those measured at fair value through other comprehensive income, except for investments in equity instruments. Under IFRS 9, the allowance for impairment losses will be measured based on:

·12-months expected credit losses; or

·Lifetime expected credit losses, if the credit risk of a financial asset at the reporting date has increased significantly since initial recognition.

The standard allows the application of a simplified approach for trade receivables, contract assets and lease receivables so that the impairment is always recognized in reference to the lifetime expected credit losses for the asset. The Group has chosen to apply this policy for the designated financial assets.

The analysis of the impairment of the Group’s financial assets was made with a focus on trade accounts receivable, which represent most of the Group’s credit exposure. In particular, for the application of the simplified approach

F-16

contemplated in the standard, these accounts receivable were grouped into specific pools, taking into account the nature and credit risk, and the impairment model based on expected losses developed by the Group was applied on a collectively evaluated basis. For trade accounts receivable that management considered significant on an individual basis and for which more detailed information on credit risk was available, an analytical approach was adopted within the simplified model. As of January 1, 2018, as a result of the application of the new impairment model, the Group recognized a charge, net of taxes, of ThUS$5,804 to retained earnings.

(iii)Hedge accounting

IFRS 9 introduces a new model for hedge accounting in order to more closely align the accounting treatment with risk management activities of the entities and to establish a new principle-based approach. The new model will enable entities to better reflect risk management activities in the financial statements, and allow more items to be eligible as hedged items, such as non-financial risk components, net positions, and aggregated exposures (i.e., a combination of derivative and non-derivative exposure).

The most significant changes in relation to hedging instruments compared to hedge accounting methodology in IAS 39, is the possibility to defer in other comprehensive income the time value of options, forward points in forward contracts, and foreign currency basis spread, until the hedged item impacts profit or loss.

IFRS 9 eliminated the quantitative requirement of the evidence of effectiveness included in IAS 39, under which the profit or loss should be within the range of 80% -125%, allowing the evaluation of effectiveness to be aligned with risk management through of the demonstration of the existence of an economic relationship between the hedging instrument and the hedged item, and offers the possibility of rebalancing the hedging relationship if the risk management objective remains unchanged. However, retrospective ineffectiveness should continue to be valued and recognized in profit or loss.

When initially applying IFRS 9, the Group may choose as its accounting policy to continue to apply the hedge accounting requirements of IAS 39 instead of the requirements in IFRS 9, until the time the new requirements on macro-hedging are published and adopted. The Group has chosen to apply the new requirements of IFRS 9 on the date of its adoption.

The application of the new hedge accounting model has not had an impact on the Group’s consolidated financial statements.

The Group implemented changes in the systems, internal control, policies and procedures in order to comply with the new disclosures and accounting requirements of IFRS 9.

·IFRS 15 — Revenue from Contracts with Customers

In May 2014, the IASB published IFRS 15, which is applicable to all revenue arising from contracts with customers, with certain exemptions (lease and insurance contracts, financial instruments and non-monetary exchanges) and to recognition and measurement of gains and losses on disposal of non-financial assets. The new revenue standard supersedes, effective as of January 1, 2018, all current revenue recognition standards:

·IAS 11 Construction Contracts;

·IAS 18 Revenue;

·IFRIC 13 Customer Loyalty Programs;

F-17

·IFRIC 15 Agreements for the Construction of Real Estate;

·IFRIC 18 Transfers of Assets from Customers; and

·SIC-31 Revenue Barter Transactions Involving Advertising Services.

This new standard introduces a general framework for recognition and measurement of revenue, based on the core principle that revenues are recognized for an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring promised goods or services to customers. This core principle shall be applied using a five-step approach to revenue recognition: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contracts; and (5) recognize revenue when (or as) the entity satisfies a performance obligation.

The Group carried out an implementation project, to identify and measure the possible impacts of applying IFRS 15 on its consolidated financial statements. This project involved identifying all of the revenue flows of Enel Américas and its subsidiaries, knowledge of the traditional practices of the business, a comprehensive evaluation of each kind of contract with customers and determining the methodology for recording this revenue under the standards. The evaluation was performed paying special attention to those contracts presenting key aspects of IFRS 15 and particular characteristics of interest to the Group, such as identifying contractual obligations; contracts with multiple obligations and recognition timing; contracts with variable compensation; significant financing components; analysis of principal versus agent; existence of service guarantees; and recognition of costs to obtain and fulfill a contract.

The Group participates in the electrical energy Generation, Transmission and Distribution businesses, and related activities. Based on the nature of the goods and services offered and the characteristics of its revenue flows, the Group did not identify any impact on the consolidated financial statements of the Group on the date of initial application of IFRS 15. For further details about the goods and services provided by the Group and the revenue recognition criteria, see Note 4.q.

The Group implemented changes in the systems, internal control, policies and procedures in order to comply with the new disclosures and accounting requirements of IFRS 15.

The Group adopted the new standard on the required effective date using the retrospectively modified method. As of January 1, 2018, as a result of the application of the new standard, the Group recognized a charge, net of taxes, of ThUS$1,272 to retained earnings.

·IFRIC 22 — Foreign Currency Transactions and Advance Consideration

This Interpretation clarifies the date of the transaction for the purpose of determining the exchange rate to use in foreign currency transactions when the consideration is paid or received before recognizing related revenues, expenses or assets. For this purposes, the date of the transaction is the date on which an entity initially recognizes the non-monetary asset or non-monetary liability arising from the payment or receipt of advance consideration.

IFRIC 22 has been implemented by the Group as of January 1, 2018 and it has not generated an impact on the consolidated financial statements of the Group.

F-18

ii.Amendments and Improvements

Amendments and Improvements	Mandatory Effective Date:
Amendment to IFRS 12: Classification and Measurement of Share-based Payment Transactions	January 1, 2018
Amendment to IAS 40: Transfers of Investment Property	January 1, 2018
Annual Improvements to IFRS: Cycles 2014-2016 IFRS 1 and IAS 28	January 1, 2018

·Classification and Measurement of Share-based Payment Transactions (Amendments to IFRS 2)

The amendments to IFRS 2 Share-based Payment Transactions, developed through the IFRS Interpretations Committee, address the following issues:

a)the effects of vesting and non-vesting conditions on the measurement of cash-settled share-based payments;

b)the classification of withholding tax obligations for share-based payment transactions with net settlement features; and

c)the accounting for modifications of share-based payment transactions from cash-settled to equity-settled.

The amendments to IFRS 2, applied by the Group as of January 1, 2018, have not had any impact on the consolidated financial statements of the Group.

·Transfers of Investment Property (Amendments to IAS 40)

The amendments to IAS 40 Investment Property clarify that an entity shall transfer a property to, or from, investment property when, and only when, there is evidence of a change in use. A change of use occurs if property meets, or ceases to meet, the definition of investment property. A change in management’s intentions for the use of a property by itself does not constitute evidence of a change in use. The amendments shall be applied prospectively.

The amendments to IAS 40, applied by the Group as of January 1, 2018, have not had any impact on the consolidated financial statements of the Group.

·Annual Improvements to IFRS: Cycles 2014-2016 IAS 28

IAS 28 Investments in Associates and Joint Ventures clarifies that if an entity that is not itself an investment entity has an interest in an associate or joint venture that is an investment entity, it may choose to maintain the fair value measurement applied by its investment entity associate or joint venture. Application of these improvements is on a retrospective basis.

The 2014-2016 annual improvements, applied as of January 1, 2018, have not had any material impacts on the consolidated financial statements of the Group.

b)Accounting pronouncements with application effective as of January 1, 2019 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 is not mandatorily effective:

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i.New Standards and Interpretations

Standards and Interpretations	Mandatory Effective Date:
IFRS 16: Leases	January 1, 2019
IFRIC 23 Uncertainty over Income Tax Treatments	January 1, 2019
Conceptual Framework (Revised)	January 1, 2020

·IFRS 16 Leases

In January 2016, the IASB issued IFRS 16 which establishes recognition, measurement, presentation and disclosure principles for lease agreements. IFRS 16 supersedes IAS 17 Leases and its interpretations: IFRIC 4 Determining whether an Arrangement contains a Lease, SIC-15 Operating Leases—Incentives and SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a Lease. The standard is effective for annual periods beginning on or after January 1, 2019.

Although IFRS 16 substantially retains the definition of a lease in IAS 17, the main change is the incorporation of the “control” concept within the new definition. In relation to the accounting treatment for a lessee and a lessor, the new standard states the following:

i)Lessee accounting: IFRS 16 requires lessees to account for all leases under a single model, similar to accounting for finance leases under IAS 17. As a result, at the date of commencement of a lease, the lessee will recognize on the statement of financial position a right to use asset and a lease liability for the future payments. Subsequent to initial recognition it will recognize in the statement of profit or loss the depreciation expense of the asset separately from the interest related to the liability. The standard provides two voluntary recognition exceptions for low-value leases and short-term leases.

ii)Lessor accounting: does not change substantially from the current model of IAS 17. The lessor will continue to classify leases under the same principles of the current standard as operating or financial leases.

The Group carried out an assessment of the potential impact of IFRS 16 on its consolidated financial statements. Conducting this assessment required the use of professional judgment and assumptions, which are summarized below:

·Analysis of the lease contracts executed by the Group’s companies in order to identify if they are within the scope of the standard. This analysis included not only the contracts in which the Group’s companies act  as a lessee, but also the contracts for the rendering of services and the contracts in which the Group companies act as a lessor.

·Analysis of lease contracts that could benefit from the exemption from application of this standard, because they are contracts with a maturity of less than 12 months or that have underlying assets of low individual value, such as: lease of certain office equipment (personal computers, printers and photocopiers) that are considered low value assets.

·Estimate of the lease terms, based on the non-cancellable period and the periods covered by the renewal options, the exercise of which is in the power of Enel Américas and is considered reasonably certain.

·Estimate of the discount rate to calculate the present value of the lease payments. This is equal to the incremental rate of the lessee’s loans when the interest rate implicit in the lease cannot be easily determined. For the transition, the Group has used the incremental borrowing rate from January 2019, defined as the interest rate that the Group would have to pay to borrow over a similar term, and with a similar security, the

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funds necessary to obtain an asset of a value similar to the right-of-use asset in a similar economic environment.

The implementation work also required a review of the processes and systems, including the internal control, in order to determine the most appropriate tool for the management of the information required for the application of the new standard, as well as the required disclosures in the consolidated financial statements.

For the transition of the new standard, the Group has decided to apply the following practical expedients:

·The Group decided not to re-evaluate if a contract is, or contains, a lease. Instead, it will apply the standard to contracts that were previously identified as leases by applying IAS 17 and IFRIC 4. Therefore, the Group will not apply the standard to contracts that were not previously identified as containing a lease.

·The Group has determined that it will apply the modified retrospective transition method, whereby the restatement of comparative periods is not required and the cumulative effect of the initial application of the standard is presented as an adjustment to the opening balance of retained earnings (or another component of equity as applicable) on the date of initial application, recording the asset for the same value as the liability.

·Trust in its assessment of whether leases are onerous by applying IAS 37 Provisions, Contingent Liabilities and Contingent Assets immediately before the date of initial application and adjust the right-of-use asset at the date of initial application for the amount of any provision for onerous leases recognized in the financial statements immediately before the date of initial application

The new standard will have an impact on all Group entities that have lease contracts. The main issues that arise are those related to the lease of land, buildings and automobiles. As a result of the change of the accounting model for lessees, the Group expects an increase in non-current and current liabilities of approximately US$75 million as of January 1, 2019, for the recognition of future payment obligations of lease contracts. In accordance with the chosen transition model, an increase in non-current assets for an equal amount is also expected, resulting from the recognition of the rights of use arising from those contracts.

·IFRIC 23 Uncertainty over Income Tax Treatments

In June 2017, the IASB issued IFRIC 23 to clarify the application of recognition and measurement requirements in IAS 12, Income Taxes, when there is uncertainty over income tax treatments. The Interpretation specifically addresses the following: whether an entity considers uncertain tax treatments separately; the assumptions an entity makes about the examination of tax treatments by taxation authorities; how an entity determines taxable profit (loss), tax bases, unused tax losses, unused tax credits and tax rates; and how an entity considers changes in facts and circumstances.

Uncertainty over income tax treatments can affect both current and deferred taxes. Recognizing the effects of uncertainty depends on whether the tax authority is likely or not to accept an uncertain tax treatment, assuming that the tax authority will examine the amounts that it is entitled to examine and has full knowledge of all the related information.

This interpretation is effective for annual periods beginning on or after January 1, 2019. Retrospective application is allowed, if it is possible without the use of hindsight. Management has assessed the effects of the application of IFRIC 23 and has determined that its adoption will not have any material impacts on the consolidated financial statements of the Group as of its effective date.

·Conceptual Framework (Revised)

The IASB issued the Conceptual Framework (revised) in March 2018. It incorporates some new concepts, provides updated definitions and recognition criteria for assets and liabilities and clarifies some important matters.

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Revisions to the Conceptual Framework may affect the application of IFRSs when no standard applies to a particular transaction or event.

The IASB has also issued a separate accompanying document, “Amendments to References to the Conceptual Framework in IFRS Standards,” which establishes amendments to affected IFRSs in order to update references to the new Conceptual Framework.

The Conceptual Framework (Revised) is effective as of January 1, 2020. Management is assessing the potential impact of the application of the new Conceptual Framework on the consolidated financial statements of the Group.

ii.Amendments and Improvements

Amendments and Improvements	Mandatory Effective Date:
Amendment to IAS 9: Prepayment Features with Negative Compensation	January 1, 2019
Amendment to IAS 28: Long-term interests in Associates and Joint Ventures	January 1, 2019
Annual Improvements to IFRS: 2015 - 2017 Cycle (IFRS 3, IFRS 11, IAS 12 and IAS 23).	January 1, 2019
IAS 19: Plan Amendment, Curtailment or Settlement	January 1, 2019
Amendment to IAS 3: Definition of a Business	January 1, 2020
Amendments to IAS 1 and IAS 8 Definition of Material	January 1, 2020
Amendments to IFRS 10 and IAS 28; Sale or contribution of assets between an investor and its associate or joint venture	Postponed indefinitely. Available for optional adoption

·Amendments to IFRS 9 Prepayment Features with Negative Compensation

This amendment was issued on October 12, 2017. This amendment amends the existing requirements in IFRS 9 regarding termination rights in order to allow measurement of financial assets at amortized cost (or, depending on the business model, at fair value through other comprehensive income) even in the case of negative compensation prepayments.

Under IFRS 9, a debt instrument can be measured at amortized cost or at fair value through profit or loss in other comprehensive income, provided that the contractual cash flows are only principal and interest payments on the outstanding principal and the instrument is carried out within the business model for that classification. The amendments to IFRS 9 are intended to clarify that a financial asset meets the criterion of “only principal payments plus interest”, regardless of the event or circumstance that causes the early termination of the contract or of which party pays or receives reasonable compensation for the early termination of the contract.

The amendments to IFRS 9 should be applied when the prepayment is close to the unpaid amounts of principal and interest in such a way that it reflects the change in the benchmark interest rate. This implies that prepayments at fair value or for an amount that includes the fair value of the cost to terminate an associated hedging instrument will normally meet the criterion of only principal payments plus interest, only if other elements of the change in fair value, such as the effects of credit risk or liquidity, are not minimal.

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The amendments are applicable from January 1, 2019, retrospectively. Management considers that the application of these amendments will not have an impact on the consolidated financial statements of the Group.

·Amendments to IAS 28 Long-term interests in Associates and Joint Ventures

These amendments clarify that IFRS 9 Financial Instruments is applicable to an entity’s long-term interests in an associate or joint venture to which the equity method is not applied. This clarification is relevant because it implies that the expected credit loss model, described in IFRS 9, applies to these long-term interests. Entities should apply the amendments retrospectively, with certain exceptions.

The effective application date is January 1, 2019. Management considers that the application of these amendments will not have an impact on the consolidated financial statements of the Group.

·Annual improvements to IFRS 2015 - 2017 Cycle (IFRS 3, IFRS 11, IAS 12 and IAS 23).

IFRS 3 Business Combinations and IFRS 11 Joint Arrangements clarifies the accounting for increases in ownership interest in a joint operation that meets the definition of a business. If a party maintains (or obtains) joint control, the previously held ownership interest is not remeasured. If a party obtains control, the transaction is a business combination in stages and the acquiring party remeasures the previously held ownership interest in the assets and liabilities of a joint operation, at fair value.

The IAS 12 Income Taxes amendments clarify that the income tax on dividends is linked more directly to past transactions or events that generated distributable profits than to distributions to shareholders. Therefore, an entity recognizes income tax on dividends in profit or loss, other comprehensive income or equity according to where the entity originally recognized those past transactions or events.

IAS 23 Borrowing Costs clarifies that loans that were specifically intended to finance qualifying assets part of the entity’s general loan pool for the purpose of calculating the capitalization rate, , when substantially all of the activities necessary to prepare the asset for its intended use or sale are complete.

The improvements are effective for annual reporting periods beginning on or after January 1, 2019. Management considers that the application of these improvements will not have an impact on the consolidated financial statements of the Group.

·Amendment to IAS 19 Plan Amendment, Curtailment or Settlement

The amendments to IAS 19 Employee Benefits, issued in February 2018, address the accounting when a plan amendment, curtailment or settlement occurs during a reporting period. The amendment specifies that an entity is required to determine the current service cost and net interest for the remainder of the annual period using the actuarial assumptions used to remeasure the defined benefit liability (asset) and plan assets after the plan amendment, curtailment or settlement.

The amendments to IAS 19 also clarify that an entity first determines any past service cost, or a gain or loss on settlement, without considering the effect of the asset ceiling. This amount is recognized in profit or loss. An entity then determines the effect of the asset ceiling after the plan amendment, curtailment or settlement. Any change in that effect, excluding amounts included in net interest, is recognized in other comprehensive income.

This clarification provides that entities might have to recognize a past service cost, or a gain or loss on settlement, that reduces a surplus that was not recognized before. Changes in the effect of the asset ceiling are not netted against such amounts.

The amendments to IAS 19 apply to a plan amendment, curtailment or settlement that occur from January 1, 2019.

F-23

·Amendments to IFRS 3 Definition of a Business

IFRS 3 Business Combinations was amended by the IASB in October 2018, to clarify the definition of business, in order to help entities to determine whether a transaction should be accounted for as a business combination or as the acquisition of an asset. To be considered as a business, an acquired integrated set of activities and assets must include, at least, an input and a substantive process that together contribute significantly to the ability to create output. The amendment also adds guidance and illustrative examples to assess whether a substantial process has been acquired.

The amendment is applicable prospectively to business combinations and acquisitions of assets, the acquisition date of which is from January 1, 2020. Earlier application is permitted.

·Amendments to IAS 1 and IAS 8 Definition of Material or Materiality

In October 2018, the IASB amended IAS 1 Presentation of Financial Statements and IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors, to improve the definition of material and the explanations accompanying the definition. The amendments ensure that the definition of material is consistent in all IFRS.

Information is material if omitting, misstating or obscuring it could reasonably be expected to influence the decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.

The amendments will be applicable prospectively for annual periods beginning on or after January 1, 2020. Earlier application is permitted. Management is evaluating the potential impact of the application of these amendments on the consolidated financial statements of the Group.

2.3Responsibility 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.

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 important 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 4.d.1).

·The identification of cash generating units (CGU) for impairment testing (see Note 4.e).

·The hierarchy of information used to measure assets and liabilities at fair value (see Note 4.h).

·The determination of the Group’s functional currency (see Note 3 and 4.v).

·Application of the revenue recognition model in accordance with IFRS 15 (see Note 4.q).

The estimates refer basically to:

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·The valuations performed to determine the existence of impairment losses in assets and goodwill (see Note 4.e).

·The assumptions used to calculate the actuarial liabilities and obligations with employees, such as discount rates, mortality tables, salary increases, etc. (see Notes 4.m.1 and 26).

·The useful lives of property, plant and equipment and intangible assets (see Notes 4.a and 4.d).

·The assumptions used to calculate the fair value of financial instruments (see Notes 4.h and 23).

·The energy supplied to customer whose meters have not yet been read (see Note 4.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 2.2).

·The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 4.m).

·Future disbursements for closure of facilities and restoration of land, as well as associated discount rates to be used (see Note 4.a).

·The tax results of the various subsidiaries of the Group that will be reported to the respective tax authorities in the future, and other estimates have been used as a basis for recording the various income tax-related balances in these consolidated financial statements (see Note 4.p).

·The fair value of assets acquired and liabilities assumed, and any pre-existing interest in an entity acquired in a business combination.

Although these judgments and estimates have been based on the best available information as of the issuance date 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 and estimation in the corresponding future consolidated financial statements.

2.4Subsidiaries

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, that is, the activities that significantly affect the subsidiary’s results.

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 elements of control listed above.

Subsidiaries are consolidated as described in Note 2.7.

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The following are the entities in which the Group has the ability to exercise control and are therefore included in these consolidated financial statements:

			Functional	% Ownership as of 12-31-2018						% Ownership as of 12-31-2017
Taxpayer ID No.	Company	Country	Currency	Direct		Indirect		Total		Direct		Indirect		Total
Foreign	Enel Distribución Río S.A. (formerly Ampla Energía E Serviços S.A.)	Brazil	Real	0.00	%	99.73	%	99.73	%	0.00	%	99.64	%	99.64	%
Foreign	EGP Cachoeira Dourada S.A.	Brazil	Real	0.00	%	99.75	%	99.75	%	0.00	%	99.75	%	99.75	%
Foreign	Enel Generación Fortaleza S.A.	Brazil	Real	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%
Foreign	Enel Cien S.A. (formerly named Cien S.A.)	Brazil	Real	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%
Foreign	Enel Distribución Ceará S.A.	Brazil	Real	0.00	%	74.05	%	74.05	%	0.00	%	74.05	%	74.05	%
Foreign	Enel Brasil S.A.	Brazil	Real	100.00	%	0.00	%	100.00	%	97.67	%	2.33	%	100.00	%
Foreign	Enel X Brasil S.A	Brazil	Real	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%
Foreign	Enel Distribución Goias S.A	Brazil	Real	0.00	%	99.93	%	99.93	%	0.00	%	99.93	%	99.93	%
Foreign	Enel Distribución Sao Paulo S.A	Brazil	Real	0.00	%	95.88	%	95.88	%	0.00	%	0.00	%	0.00	%
Foreign	Enel Green Power Volta Grande	Brazil	Real	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%
Foreign	Ingendesa do Brasil Ltda.	Brazil	Real	1.00	%	0.00	%	1.00	%	1.00	%	0.00	%	1.00	%
Foreign	Enel Brasil Investimento Sudeste S.A	Brazil	Real	0.00	%	100.00	%	100.00	%	0.00	%	0.00	%	0.00	%
Foreign	Central Generadora Fotovoltaica Sao Francisco Ltda.	Brazil	Real	0.00	%	100.00	%	100.00	%	0.00	%	0.00	%	0.00	%
Foreign	Nuxer Trading S.A	Uruguay	US Dollar	0.00	%	100.00	%	100.00	%	0.00	%	0.00	%	0.00	%
Foreign	Central Dock Sud, S.A.	Argentina	Argentine peso	0.00	%	70.24	%	70.24	%	0.00	%	70.24	%	70.24	%
Foreign	Compañía de Transmisión del Mercosur S.A.	Argentina	Argentine peso	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%
Foreign	Distrilec Inversora S.A.	Argentina	Argentine peso	51.50	%	0.00	%	51.50	%	51.50	%	0.00	%	51.50	%
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Argentine peso	0.00	%	99.45	%	99.45	%	0.00	%	99.45	%	99.45	%
Foreign	Enel Argentina S.A. (formerly named Endesa Argentina S.A.)	Argentina	Argentine peso	99.92	%	0.00	%	99.92	%	99.88	%	0.00	%	100.00	%
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	0.00	%	75.68	%	75.68	%	0.00	%	75.68	%	75.68	%
Foreign	Enel Generación El Chocón S.A. (formerly named Hidroeléctrica El Chocón S.A.)	Argentina	Argentine peso	0.00	%	67.67	%	67.67	%	0.00	%	67.67	%	67.67	%
Foreign	Hidroinvest S.A.	Argentina	Argentine peso	41.94	%	54.76	%	96.70	%	41.94	%	54.76	%	96.09	%
Foreign	Inversora Dock Sud, S.A.	Argentina	Argentine peso	57.14	%	0.00	%	57.14	%	57.14	%	0.00	%	57.14	%
Foreign	Transportadora de Energía S.A.	Argentina	Argentine peso	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%
Foreign	Compañía Distribuidora y Comercializadora de Energía S.A. (3)	Colombia	Colombian peso	48.30	%	0.00	%	48.30	%	48.30	%	0.00	%	48.41	%
Foreign	Emgesa S.A. E.S.P.	Colombia	Colombian peso	48.48	%	0.00	%	48.48	%	48.48	%	0.00	%	48.48	%
Foreign	Inversora Codensa S.A.S.	Colombia	Colombian peso	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%
Foreign	Sociedad Portuaria Central Cartagena S.A.	Colombia	Colombian peso	0.00	%	99.85	%	99.85	%	0.00	%	99.85	%	99.85	%
Foreign	Enel X Colombia S.A.S	Colombia	Colombian peso	0.00	%	100.00	%	100.00	%	0.00	%	0.00	%	0.00	%
Foreign	Enel Peru S.A.C.	Peru	Peruvian Soles	100.00	%	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%
Foreign	Chinango S.A.C.	Peru	Peruvian Soles	0.00	%	80.00	%	80.00	%	0.00	%	80.00	%	80.00	%
Foreign	Enel Generación Perú	Peru	Peruvian Soles	0.00	%	83.60	%	83.60	%	0.00	%	83.60	%	83.60	%
Foreign	Enel Distribución Perú S.A.	Peru	Peruvian Soles	0.00	%	83.15	%	83.15	%	0.00	%	83.18	%	83.18	%
Foreign	Enel Generación Piura.	Peru	Peruvian Soles	0.00	%	96.50	%	96.50	%	0.00	%	96.50	%	96.50	%
Foreign	Compañía Energetica Veracruz S.A.C	Peru	Peruvian Soles	0.00	%	100.00	%	100.00	%	0.00	%	100.00	%	100.00	%

2.4.1Changes in the scope of consolidation

·On February 14, 2017, our subsidiary Enel Brasil S.A. completed the purchase of a total of 99.88% of the capital stock of Enel Distribución Goias S.A. (formerly Celg Distribución S.A.). The effects of this transaction in the consolidated financial statements of the Group, and other information regarding this acquisition, are described in Note 7.1.

·On October 4, 2017, Enel Brasil S.A. created Sociedad EGP Project I. On November 30, 2017, the company won the 30 year concession for the Volta Grande power plant. (See Note 4.d.1 and Note 10).

·On June 7, 2018, our subsidiary Enel Brasil S.A. through its own subsidiary (100%) Enel Brasil Investimentos Sudeste S.A. (Enel Sudeste) successfully completed the acquisition, by means of a voluntary tender offer (“OPA” or “Tender Offer”), for the Brazilian energy distributor Enel Distribución Sao Paulo (formerly known as Eletropaulo Metropolitana de Eletricidade de Sao Paulo S.A.). For further information related to this acquisition, see Note 7.2.

·During the last quarter of 2018, Enel Brasil S.A. acquired the Uruguayan company Nuxer Trading S.A. and Central Geradora Fotovoltaica Sao Francisco Ltda. Both companies were acquired in order to develop the business lines of Enel X Brasil in Uruguay and Brazil, respectively.

2.4.2Consolidated companies with an economic equity interest of less than 50%

Although the Group holds a 48.3% equity interest in Codensa S.A. E.S.P. and a 48.48% equity interest in Emgesa S.A. E.S.P., they are considered as subsidiaries since the Company exercises control over these entities through contracts or agreements with shareholders, or as a consequence of their structure,

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composition and shareholder classes. The Group holds 57.15% and 56.43% of the voting shares of Codensa and Emgesa, respectively.

2.5Investments 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 financial and operational policy decisions of the associate but is not 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 those cases in which the Group has more than 20% of the voting power of the investee.

Associates are accounted for under equity method as described in Note 4.i.

The detail of the companies that qualify as associates is the following:

		Functional	% Ownership as of 12-31-2018						% Ownership as of 12-31-2017
Taxpayer ID No.	Company	Currency	Direct		Indirect		Total		Direct		Indirect		Total
Foreign	Sacme S.A.	U.S. dollar	0.00	%	50.00	%	50.00	%	0.00	%	50.00	%	50.00	%
Foreign	Yacylec S.A.	Argentine peso	22.22	%	0.00	%	22.22	%	22.22	%	0.00	%	22.22	%
Foreign	Central Termica Manuel Belgrano	Argentine peso	0.00	%	25.60	%	25.60	%	0.00	%	25.60	%	25.60	%
Foreign	Central Térmica San Martin	Argentine peso	0.00	%	25.60	%	25.60	%	0.00	%	25.60	%	25.60	%
Foreign	Central Vuelta Obligado S.A.	Argentine peso	0.00	%	40.90	%	40.90	%	0.00	%	40.90	%	40.90	%

2.6Joint arrangements

Joint arrangements are defined as those entities in which the Group exercises control under an agreement with other shareholders and jointly with them, in other words, 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 incorporated to the consolidated financial statements using the equity method, as described in Note 4.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 incorporated to the consolidated financial statements recognizing the interest in the contractually named assets and liabilities in the joint operation.

In determining the type of joint arrangement in which it is involved, the management of the Group 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.

Currently, the Company is not involved in any joint arrangement that qualifies as a joint operation.

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2.7Basis 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 from intra-group transactions have been made.

The comprehensive income of subsidiaries is included in the consolidated statement of comprehensive income from the date when the parent company obtains control of the subsidiary and until the date on which it loses control of the subsidiary.

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, the Group chooses whether to measure the non-controlling interests in the acquire at fair value or at the proportional share of the net identifiable assets acquired.

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 the 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.

For business combinations achieved in stages, the Company’s previously held equity interest in the acquire is remeasured to its acquisition date fair value and the resulting gain or loss, if any, is recognized in profit or loss.

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 “Net income attributable to non-controlling interests” and “Comprehensive income attributable to non-controlling interests” in the consolidated statement of comprehensive income.

3.The financial statements of the Group companies operating in non-hyper-inflationary economies, with functional currencies other than the US dollar are translated as follows:

a.For assets and liabilities, the prevailing exchange rate on the closing date of the financial statements is used.

b.For items of the comprehensive income, the average exchange rate for the period is used (unless this average is not a reasonable approximation of the cumulative effect of the exchange rates in effect on the

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dates of the transactions, in which case the exchange rate in effect on the date of each transaction is used).

c.For equity accounts, the historical exchange rate from the date of acquisition or contribution is used, and retained earnings are translated at the average exchange rate at the date of origination.

d.Exchange differences arising in translation of financial statements are recognized in the item “Foreign currency translation gains (losses”) within the consolidated statement of comprehensive income in other comprehensive income (see Note 27.2).

4.The financial statements of the subsidiaries whose functional currency comes from hyper-inflationary economies, as is the case of the Argentine economy (see Note 8), are first adjusted for the inflation effect, and any gain or loss in the net monetary position is recognized in profit or loss; then all the items (assets, liabilities, equity items, expenses and revenue) are translated using the closing exchange rate corresponding to the closing date of the most recent statement of financial position.

5.Balances and transactions between consolidated companies have been fully eliminated in the consolidation process.

6.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.

7.Business combinations between entities under common control are accounted for using, as a reference, 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 recognized in the ultimate controlling company, although subsequent accounting adjustments may need to be made to align the accounting policies of the companies involved.

Any difference between assets and liabilities contributed to the consolidation and the consideration paid is recorded directly in Net equity, as a charge or credit to “Other reserves”. The Group does not restate comparative periods in its financial statements for business combinations under common control.

3.CHANGE OF FUNCTIONAL CURRENCY AND PRESENTATION CURRENCY

As a result of the corporate reorganization process completed in 2016, the primary economic environment and generation and use of cash flows of Enel Américas became mainly denominated in U.S. dollars. Consequently, effective on January 1, 2017, Enel Américas changed both its functional currency and the presentation currency of its consolidated financial statements from the Chilean peso (“Ch$”) to the U.S. dollar (“US$”).

Enel Américas is a holding company that does not undertake any material operating activities of its own. Therefore, the indicators in IAS 21.9 are not the most relevant factors in determining the functional currency of the Company.

In consideration of the indicators in IAS 21.10, the Company determined that the new financing activities, the future currency change of issued capital and equity accounts and the change in the currency in which cash and cash equivalents are retained, were relevant factors indicating that the Ch$ will not be the currency to reflect the principal economic environment in which the Company will generate and expend its cash. Consequently, the Company determined that the economic events and those that occurred as a result of the corporate reorganization process completed in 2016, provided in its judgment, sufficient evidence to support that there was a change to the underlying

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transactions, events and conditions previously considered to determine the Company’s functional currency. Accordingly, in accordance with IAS 21.36, the Company determined that the US$ is the new functional currency that will most faithfully reflect the underlying transactions, events and conditions relevant to the Company following the corporate restructuring process.

Under IAS 21.35, when there is a change in an entity’s functional currency, the entity should apply the translation procedures applicable to the new functional currency prospectively from the date of the change. The Company, based on its judgment and considering that the underlying transactions, events and conditions that justify the change in its functional currency have developed gradually, and those of greater relevance took place towards the end of fiscal year 2016 and beginning of fiscal year 2017, it has decided due to practical expedient, to apply the translation procedures applicable to the new functional currency prospectively beginning on January 1, 2017.

This change in functional currency was accounted for prospectively from the date of the change by translating all items of the financial statements into the new functional currency, using the exchange rate of Ch$669.47 per US$ at the date of the change.

The change in the presentation currency was accounted for as a change in accounting policy and applied retrospectively, as if the new presentation currency had always been the presentation currency of the consolidated financial statements. Consequently, comparative figures for years prior to the effective date of January 1, 2017 have been restated to the new presentation currency in accordance with IAS 21, The Effects of Changes in Foreign Exchange Rates. The consolidated statements of comprehensive income and the cash flows for the years ended December 31, 2016 and 2015 have been restated to the presentation currency using the average exchange rates. The consolidated statements of financial position as of December 31, 2016 and January 1, 2016 have been translated into US$ using the closing exchange rates of Ch$669.47 per US$ and Ch$710.16 per US$, respectively. Issued capital, retained earnings and other reserves within equity have been translated using the historical exchange rates.

All of resulting exchange differences have been recognized in equity under the reserve for exchange differences in translation.

The change in the functional currency of Enel Américas S.A. was approved by the Extraordinary Shareholders’ Meeting held on April 27, 2017, amending article five of its by-laws in order to re-denominate its issued capital into U.S. dollars.

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Statements of Comprehensive Income for the year ended December 31, 2016:

	12-31-2016
	As reported		As Restated
Comprehensive Income	ThCh$		ThUS$
Total Revenue and Other Operating Income	5,167,837,226		7,642,582
Raw materials and consumables used	(2,615,650,061	)	(3,868,218	)
Contribution Margin	2,552,187,165		3,774,364
Operating income	1,217,155,025		1,800,020
Income before taxes	930,483,597		1,376,069
Income tax expense, discontinued operations	(359,368,522	)	(531,461	)
NET INCOME FROM CONTINUING OPERATIONS	571,115,075		844,608
Net income from discontinued operations	115,130,387		170,263
NET INCOME	686,245,462		1,014,871
Other Comprehensive Income	133,302,988		197,139
TOTAL COMPREHENSIVE INCOME	819,548,450		1,212,010
Net income attributable to:
Shareholders of Enel Américas	383,059,534		566,497
Non-controlling interests	303,185,928		448,374
NET INCOME	686,245,462		1,014,871
Comprehensive income attributable to:
Shareholders of Enel Américas	533,275,016		788,647
Non-controlling interests	286,273,434		423,363
TOTAL COMPREHENSIVE INCOME	819,548,450		1,212,010
Basic and diluted earnings per share
Basic and diluted earnings per share from continuing operations	6.1300		0.00907
Basic and diluted earnings per share from discontinued operations	1.5700		0.00232
Basic and diluted earnings per share	7.7000		0.01139
Weighted average number of shares of common stock	49,768,783,340		49,768,783,340

4.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 measured at acquisition cost, net of accumulated depreciation and any impairment losses they may have experienced. In addition to the price paid to acquire each item, the cost also includes, where applicable, the following concepts:

·Financing expenses accrued during the construction period that are directly attributable to the acquisition, construction, or production of qualified assets, which require a substantial period of time before being ready for use such as, for example, electricity generation or distribution facilities. The Group defines “substantial period” as one that exceeds twelve months. The interest rate used is that of the specific financing or, if none exists, the weighted average financing rate of the company carrying out the investment (see Note 19.b.1).

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·Employee expenses directly related to construction in progress (see Note 19.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 corresponding 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 25).

Items for construction work in progress 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 increasing the cost of the corresponding 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 for the respective assets, derecognizing the replaced or overhauled components.

Expenditures for periodic maintenance, conservation 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.

The following are the main categories of property, plant and equipment with their respective estimated useful lives:

Categories 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

Additionally, the following table sets forth more details on the useful lives of plant and equipment items:

Categories 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.

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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	69 years
Enel Generación El Chocón S.A. (Generation)	Argentina	1993	30 years	5 years
Transportadora de Energía S.A. (Transmission)	Argentina	2002	85 years	69 years
Compañía de Transmisión del Mercosur S.A. (Transmission)	Argentina	2000	87 years	69 years
EGP Cachoeira Dourada S.A. (Generation)	Brazil	1997	30 years	9 years
Central Generadora Termoeléctrica Fortaleza S.A (Generation)	Brazil	2001	30 years	13 years
Enel CIEN S.A. (CIEN - Line 1)	Brazil	2000	20 years	1 years
Enel CIEN S.A. (CIEN - Line 2)	Brazil	2002	20 years	3 years

To the extent that the Group recognizes the assets as Property, plant and equipment, they 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 inflow.

The Group’s management analyzed the specific contract terms of each of the aforementioned concessions, which vary 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 4.c.1 for concession agreements within the scope of IFRIC 12).

On April 19, 2011, the subsidiary Enel CIEN successfully completed its change in business model. Under the new agreement, the government continues to control the infrastructure, but Enel CIEN receives fixed payments, which puts it on an equal footing 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.

Gains or losses that arise from the sale or disposal of items of property, plant and equipment are recognized as “Other gains (losses”) in the comprehensive income statement and are calculated by deducting the net carrying amount of the asset and any sales costs from the consideration received in the sale.

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b)Investment Properties

“Investment property” includes basically land and buildings that are kept for the purpose of obtaining profits in future sales or lease arrangements.

Investment property is measured at acquisition cost, net of accumulated depreciation and any impairment losses they may have experienced. Investment properties, excluding land, are depreciated by distributing the cost of the various elements that make them up 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 that arise from the sale or disposal of items of investment property are recognized as “Other gains (losses)” in the comprehensive income statement and are calculated by deducting the net carrying amount of the asset and any sales costs from the consideration received in the sale.

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 corresponding 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 the corresponding 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 acquired company and translated to US 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, it impairment loss is immediately recognized in profit or loss (see Note 4.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 they may have 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, 2018 and 2017, 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 on disposal, or when no future economic benefits are expected from use or disposal.

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Gains or losses arising from derecognition of an intangible asset, measured as the difference between the net disposal proceeds and the carrying amount of the asset are recognized in profit or loss when the asset is derecognized.

d.1) Concessions

Public-to-private service concession agreements are recognized according to IFRIC 12 “Service Concession Agreements.” This accounting interpretation applies if:

a)The grantor controls or regulates which 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 agreement.

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; or as 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 consideration are classified as a contract asset during the construction or improvement period, in accordance with IFRS 15 (see Note 11).

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 recognized provisions (see Note 4.m).

Finance expenses attributable to the concession agreements are capitalized based on 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 agreements are the following:

Concession holder and operator	Country	Year concession started	Concession term	Period remaining to expiration
Enel Distribución Río S.A. (ex — Ampla) (Distribution) (*)	Brazil	1996	30 years	8 years
Enel Distribución Ceará S.A. (ex Coelce) (Distribution) (*)	Brazil	1997	30 years	9 years
Enel Distribucion Goias S.A. (Distribution) (*)	Brazil	2015	30 years	26 years
Enel Green Power Proyectos I (Volta Grande) (**)	Brazil	2017	30 years	29 years
Enel Distribucion Sao Paulo S.A. (Electropaulo) (Distribution) (*)	Brazil	1998	30 years	10 years

(*)   Given that part of the rights acquired by these subsidiaries are unconditional an intangible asset and financial asset at fair value through profit an loss have been recognized for the concession (See Notes 4.g.1 and Note 10).

(**) Given that all of the rights acquired by this subsidiary are unconditional, only a financial asset at fair value through profit and loss has been recognized for this concession (See Note 2.4.1, Note 4.g.1 and Note 10).

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At the end of each concession period it can be renewed at the discretion of the granting authority, otherwise all assets and facilities will be returned to the government or its designee, 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.

e)Impairment of non-financial assets

During the period, and principally at the end of each reporting period, the Group evaluates whether there is any indication that an asset has been impaired. If any such indication exists, the Group estimates the recoverable amount of that asset to determine the amount of the impairment loss. In the case of 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, in the case of CGU’s to which goodwill or intangible assets with indefinite useful life have been allocated, a recoverability analysis is performed routinely at each period end.

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 projections based on the most recent budgets available. These budgets incorporate management’s best estimates of a CGU’s revenue and costs using sector projections, past experience and future expectations.

In general, these projections cover the next five 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.

		Growth rates
Country	Currency	12-31-2018
Argentina	Argentine peso	10.4	%
Brazil	Brazilian reals	4.2	%
Peru	Peruvian soles	2.5	%
Colombia	Colombian peso	3.5	%

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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.

The following are the pre-tax discount rates applied as of December 31, 2018, expressed in nominal terms:

		December 31, 2018
Country	Currency	Minimum		Maximum
Argentina	Argentine pesos	22.9	%	36.4	%
Brazil	Brazilian reals	9.1	%	21.3	%
Peru	Peruvian soles	7.2	%	12.1	%
Colombia	Colombian pesos	7.9	%	12.9	%

If the recoverable amount of the CGU is less than the net carrying amount of the asset, the corresponding impairment loss is recognized for the difference, and charged to “Reversal of impairment loss (impairment loss) 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 its fair value less costs of disposal, or its value in use, a negative amount may not 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 and crediting profit or loss, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the asset. In the case of goodwill, impairment losses are not reversed.

The restatement of the financial statements of Argentine companies due to the effect of inflation adjustment (see Note 8) gave rise to the recognition of an impairment provision in our subsidiary Enel Generación Costanera S.A., as a result of the negative difference between the recoverable value of the company and the carrying amount of its restated assets. The impairment loss, recorded as of January 1, 2018, amounted to ThUS$76,658. As of December 31, 2018, the impairment tests performed gave rise to a reversal of the impairment loss in the amount of ThUS$70,513, as a result of the increase in the recoverable value of the company.

f)Leases

In order to determine whether an arrangement is, or contains, a lease, the Group assesses the economic substance of the agreement, in order to determine whether fulfillment of the arrangement depends on the use of a specific asset and whether the agreement conveys the right to use an asset. If both conditions are met, at the inception of the arrangement, the Group separates the payments and other considerations relating to the lease, at their fair values, from those corresponding to other components of the agreement.

Leases that substantially transfer all the risks and rewards of ownership to the Group are classified as finance leases. All others leases are classified as operating leases.

Finance leases in which the Group acts as a lessee are recognized at the inception of the arrangement. At that time, the Group records an asset based on the nature of the lease and a liability for the same amount, equal to the fair value of the leased asset or the present value of the minimum lease payments, if the latter is lower.

Subsequently, the minimum lease payments are apportioned between finance expenses and reduction of the lease obligation. Finance expenses are recognized immediately in the income statement and allocated over the lease term, so as to achieve a constant interest rate on the remaining balance of the liability. Leased assets are depreciated on the

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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.

In the case of operating leases, payments are recognized as an expense in the case of the lessee and as income in the case of the lessor, both on a straight-line basis, over the term of the lease unless another type of systematic basis of distribution is deemed more representative.

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 4.i and 16) and non-current assets and disposal groups held for sale or distribution to owners (see Note 4.k), into three categories:

(i)Amortized cost:

This category includes the financial assets that meet the following conditions (i) the business model that supports it aims to maintain the financial assets to obtain the contractual cash flows, and (ii) the contractual terms of 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: accounts receivable, loans and cash equivalents. These 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 rate method.

The effective interest rate method is a method of 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 financial expenses 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 comply with the SPPI criterion.

These investments are recognized in the consolidated statement of financial position at fair value when it is possible to determine reliably. In the case of holdings in unlisted companies or companies with low liquidity, it is usually not possible to determine the fair value reliably. Therefore, when this circumstance 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 such time as the disposal of these

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investments takes place, at which time the accumulated amount in this section is fully posted in the profit or loss for the period.

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 losses 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 administered and assessed according to the fair value criterion, and the financial assets that do not meet the conditions to be classified in the two above categories.

They are valued 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. The new impairment model is applied to financial assets measured at amortized cost and those measured at fair value through other comprehensive income, except for investments in equity instruments.

Under IFRS 9, the allowance for impairment losses are measured based on:

·12 months expected credit losses; or

·Lifetime expected credit losses if the credit risk of a financial asset at the reporting date has increased significantly since initial recognition.

The Group applies a simplified approach for trade receivables, contract assets and lease receivables so that the impairment is always recognized in reference to the lifetime expected credit losses for the asset.

Based on the reference market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for such accounts receivable, the Group mainly applies a predetermined definition of 180 days to determine the expected credit losses, since this is considered an effective indicator of a significant increase in credit risk. Therefore, financial assets with an aging of more than 90 days are generally not considered to be in default.

g.4)Financial liabilities other than derivatives

Financial liabilities are recognized based on cash received, net of any costs incurred in the transaction. In subsequent periods, these obligations are measured at their amortized cost using the effective interest rate method (see Note 4.g.1).

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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 23, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and variable 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 a variable interest rate, i.e., each coupon is established at the beginning of each period based on the reference 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 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 hedge instrument (in a cash flow hedge) and all of the conditions for applying hedge accounting established by IFRS are met, including that the hedge be highly effective. In this case, changes are recognized as follows:

·Fair value hedges: The underlying portion for which the risk is being hedged (hedged risk) and the hedge instrument are measured at fair value, and any changes in value of both items are recognized in the statement of comprehensive income by offsetting the effects in the same comprehensive income statement account.

·Cash flow hedges: Changes in the fair value of the effective portion of the hedged item and hedge instrument are recognized in other comprehensive income and accumulated in an equity reserve known as “Reserve for cash flow hedges”. The cumulative loss or gain in this reserve 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 account. Gains or losses from the ineffective portion of the hedge 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 projected transaction affects the statement of comprehensive income. When a projected transaction is no longer expected to occur, the gain or loss accumulated in equity is immediately transferred to the income statement.

The Group does not apply hedge accounting to its investments abroad.

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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: (i) in the case of fuel purchase agreements such use is to generate electricity; (ii) in the case of electrical energy purchased for sale, its sale is to the end-customers; and (iii) in the case of 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 evidence that they are “own use” agreements, except in certain isolated cases when for exceptional reasons or reasons associated with logistical issues, they have been used for other purposes beyond the control and expectations of the Group.

·The agreement does not stipulate net settlement of monetary differences and the parties have not made it a practice to net settle 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. Thus, 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, if the contractual rights are retained, 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 ownership of the financial asset, or, if it has neither transferred 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 transferred asset, its continues recognizing the transferred asset in its entirety and recognizes a financial liability for the consideration received. Transactions costs are recognized in profit and loss by using the effective interest method (see Note 4.g.1).

Financial liabilities are derecognized when they are extinguished, that is, when the obligation arising from the liability has been paid or cancelled, or has expired.

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g.7)Offsetting of financial assets and 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 recognized amounts; and

·the Company intends to settle them on a net basis, or to realize the asset and settle the liability simultaneously.

The right of offset 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 of the counterparties.

g.8)Financial guarantees

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.

Subsequentl 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 4.m; and

·the amount of the asset initially recognized less, if appropriate, any accumulated amortization recognized in accordance with the revenue recognition policies described in Note 4.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 within 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 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 carried out using external tools such as Bloomberg); and

Level 3:Inputs for assets or liabilities that are not based on observable market data (unobservable inputs).

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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 on 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 close 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 (creditor or borrower position) and the risk profile of both the counterparties and the Group itself.

·For financial assets and financial liabilities with offsetting positions in market risks or counterparty credit risks, it is permitted to measure the fair value on a net basis. 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 liabilities measured at fair value are shown in Note 23.3.

i)Investments accounted for using the equity method

The Group’s interests in joint ventures and associates are recognized using the equity method.

Under the equity method, 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 its equity that the Group’s interest represents in its 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 support the investee’s negative equity situation, in which case a provision is recognized.

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 equity method.”

The companies classified as “Associates” and “Joint Ventures” (see Notes 2.5 and 2.6, respectively) in these consolidated financial statements are accounted for under this method.

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 estimated costs necessary to make the sale.

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The cost of inventories includes all costs of purchase and all necessary costs incurred in bringing the inventories to their present location and condition. Trade discounts, rebates and other similar items are deducted in determining the costs of purchase.

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 and joint ventures and disposal groups (a group of assets to be disposed of and the liabilities directly associated with those assets), are classified as:

·Held for sale, if their carrying amount will be recovered principally 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 its sale or distribution is highly probable. For the 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 will be made or that the plan will be withdrawn. 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.

Non-current assets or disposal groups 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 depreciations, amortizations or revaluations that would have been recognized if they had not been classified as held for sale or held for distribution to owners and their recoverable amount at the date of subsequent decision that they would be reclassified as 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 called “Non-current assets or disposal groups held for sale or for distribution to owners”, and the respective liabilities are presented as a single line item within liabilities called “Liabilities included in disposal groups held for sale or for distribution to owners”.

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 resale.

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The components of profit or loss after taxes from discontinued operations and the post-tax gain or loss recognized on the measurement to fair value less costs to sell or on the disposal of the assets or groups constituting the discontinued operation are presented as a single line item in the consolidated comprehensive income statement as “Income after tax from discontinued operations”.

l)Treasury shares

Treasury shares are deducted from 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 “Equity — Retained earnings”, 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 cost expected to be incurred in resolving a legal claim is 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 they are 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

Some of the Group’s subsidiaries have pension and similar obligations to their employees. Such obligations, related to defined benefit plans, are basically formalized through pension plans, except for certain non-monetary benefits, mainly electricity supply commitments, which, due to their nature, have not been externalized and are covered by the related in-house provisions.

For defined benefit plans, the cost of providing benefits is determined using the Projected Unit Credit Method, with actuarial valuations being carried out at the end of each reporting period. Past service costs relating to changes in benefits are recognized immediately.

The defined benefit plan obligations in the statement of financial position represent the present value of the accrued obligations, adjusted, once the fair value of the different plans’ assets has been deducted, if any.

For each of the defined benefit plans, any deficit between the actuarial liability for past services and the plan assets is recognized under line item “Provisions for employee benefits” within current and non-current liabilities in the consolidated statement of financial position, and any surplus is recognized under line item “Other financial assets” within non-current assets in the consolidated statement of financial position, provided that any surplus is recoverable

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by 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 in 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 their services.

n)Translation of balances in foreign currency

Transactions carried out 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, any differences that arise 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 exchange differences” in the consolidated statement of comprehensive income.

Likewise, at the end of each reporting period, receivable or payable balances denominated in a currency other than each entity’s functional currency are translated using the closing exchange rate. Any differences are recorded as “Foreign currency exchange 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 reclassified to profit or loss when the hedged cash flows affect profit or loss. This term has been estimated at ten years.

o)Current/non-current classification

In these consolidated statements of financial position, assets and liabilities expected to be recovered or settled within twelve months are presented as current items, except for post-employment and other similar obligations. Those assets and liabilities expected to be recovered or settled in more than twelve months are presented as non-current items. Deferred income 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 credit 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 permitted deductions 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 are calculated using the tax rates expected to apply 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 make use of 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

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·At initial recognition 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 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 there exists uncertainty about their tax realization, in which case they are not recognized until they are effectively realized, or when they correspond to specific tax incentives, in which case they are recorded as government grants.

At the end of each reporting period, the Group reviews the deferred tax assets and liabilities recognized, and makes, if any necessary corrections 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 taxation 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 it 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 of the 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.

·Generation: revenue is recorded according to the physical deliveries of energy and power, at the prices established in the respective contracts, at the prices stipulated 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 respective contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate.

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These revenues include an estimate of the service provided and not invoiced, at the balance sheet date (See Note 2.3 and Note 28).

·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 (performance completed to 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 have been transferred to the buyer, which generally occurs at the time of the physical delivery of the goods. 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 to two or more transactions jointly, when these are linked to contracts with customers that are negotiated with a single commercial 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 solution 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 figure. The Group only records as revenue the payment or commission to which it expects to be entitled.

Given that the Group mainly recognizes revenue for the amount to which it has the right to invoice, it has decided to apply the practical disclosure solution provided in IFRS 15, through which it is not required to disclose the aggregate amount of the transaction price allocated to the obligations of performance not met (or partially not met) 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. 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.

Interest revenue (expenses) is (are) recorded considering the effective interest rate applicable to the principal with pending amortization, during the corresponding 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 shares of common stock 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

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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 net income attributable to shareholders of the Parent Company by the weighted average number of shares of common stock outstanding during the period plus the weighted average number of shares of common stock that would be issued on conversion of all the potential dilutive securities into shares of common stock, if any.

s)Dividends

Article No. 79 of the Chilean Corporations Act Law No. 18,046, 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 to 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 the 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 current payables” and “Accounts payable to related parties”, as appropriate, and recognized in equity.

The interim and final dividends are deducted from equity when approved by the competent body, which in the first case is normally the Board of Directors and in the second case is the shareholders as agreed at an Ordinary 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”.

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 expressions and corresponding 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.

v)Functional currency

The Company’s management has concluded that the currency of the main economic environment in which the Company operates is the United States dollar (US$), and has decided that this is the Company’s functional currency.

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This conclusion is based on the fact that the US$ is the currency that fundamentally influences financing activities, capital issues and cash flows and their equivalents.

Due to the foregoing, the US$ reflects the underlying transactions, events and conditions which are relevant to the Group.

·All information presented in US$ has been rounded to the nearest thousand (ThUS$) or million (MUS$) unit, except when otherwise indicated.

5.SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS

a)Regulatory Framework

Argentina

Argentina has shown signs of intervention in the electricity market since the crisis of 2002. Under the previous regulations, generators sold to distributors at prices obtained from centralized calculations of the average spot market price. The distributers’ purchase price was the average price forecast for the next six months, called the Seasonal Price (Precio Estacional). Any differences between the Seasonal Price (the purchase price) and the actual spot price (the selling price) was charged to the Seasonal Fund (Fondo Estacional) managed by the Wholesale Electricity Market Administration Company (CAMMESA - Compañía Administradora del Mercado Mayorista Eléctrico).

However, after the 2002 crisis, the authorities changed the price-setting criteria, bringing the marginal pricing system to an end. First, marginal prices were calculated without taking into consideration the natural gas shortages. In effect, despite the fact that generation is dispatched on the basis of the fuels actually used, SE Resolution No. 240/2003 establishes that the marginal price is to be calculated taking into consideration all of the generation units as if there were no restrictions in effect on natural gas supplies. In addition, the expense of water is not included in the calculations if its opportunity cost is higher than the cost of generating power with natural gas. Second, it established a spot price ceiling of Ar$120 per MWh. However, CAMMESA pays the actual variable costs of the thermal plants that run on liquid fuels through the Temporary Dispatch Cost Overruns program.

In addition, as the dollarized economy was devalued and went back to the Argentine peso, payment for capacity fell from US$10 to Ar$10 per MWh. Capacity payments have subsequently risen slightly to Ar$12 per MWh.

Additionally, the freezing of prices paid by distributors caused a gap in relation to actual generation costs, resulting in various types of special agreements for recovering costs, in accordance with regulations in force.

It was in this context that the government announced in 2012 its plan to change the current regulatory framework to one based on an average cost scheme.

Resolution No. 95/2013 was published in March of 2013, significantly changing the system for generators’ remunerations and setting new prices for capacity depending on the type of technology used and availability. It also set new values for paying for non-fuel variable costs, as well as additional remuneration for energy generated.

In May 2013, the Group’s generating companies (Enel Generación Costanera, Enel Generación El Chocón and Dock Sud) accepted the terms of SE Resolution No. 95/2013.

This resolution marked the end of marginal pricing as a payment system in the Argentine power generation market and established, instead, a payment system by type of technology and size of plant. For each case, it recognizes fixed costs (determined on the basis of fulfillment of availability) and variable costs, plus an additional remuneration (the two parts are determined based on energy generated). Part of the additional remuneration is placed in a trust for future investments.

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Commercial management and fuel dispatch are handled by of CAMMESA; Terminal Market agreements cannot be extended or renewed, and large users, once their respective contracts are up, must purchase their supply from CAMMESA. However, the Secretary of Energy (“SE”), in Note SE 1807/13, gave generators the opportunity to express their intention to continue handling collections for their entire contract portfolio, thus ensuring a certain amount of cash flow and a continuing relationship with the customer.

It is also important to mention that Enel Generación Costanera has availability contracts signed in 2012 that are still in effect, as well as combined cycle contracts (until 2016) and turbosteam generation contracts (until 2019) that will enable the company to implement an investment plan for the Costanera plant generation units in order to optimize the reliability and availability of that plant. The contracts also include payment of the commitments under the Long-Term Service Agreement (LTSA) for the plant’s combined cycles.

The values of SE Resolution 95/2013 were updated on an annual basis by SE Resolutions 529/2014, 482/2015 and SEE Resolution 22/2016. SE Resolution 529/2014 created a remuneration for non-recurring maintenance for the steam-electric power plants, and SE Resolution 482/2015 provided remuneration for non-recurring maintenance also to hydroelectric power stations. In addition, Resolution 482/2015 created a new charge of 15.8 Ar$/MWh for steam-electric power plants and 6.3 Ar$/MWh for hydroelectric power stations, in order to finance investments, applicable from February, 2015 to December, 2018 only for those generating companies participating in the project.

On March 22, 2016, the SE through Resolution No. 21/16, requested bids to offer new capacity for thermal generation for the summer 2016/17, winter 2017 and summer 2017/18 periods. The resolution stated that the offer cannot include, as of the date the resolution was published, pre-existing generation units already interconnected to the Argentine Interconnection System (“SADI” in its Spanish acronym) or capacity that was already offered in other agreements. The five (5) – ten (10) year contract will be entered into with CAMMESA as a representative of Wholesale Electricity Market (“MEM”) agents and monthly remuneration for capacity will be in US$ per MW, while energy generated with each fuel will be in US$  per MWh, as the payment priority equivalent to that of payment for liquid fuel. The supply and recognition of fuel costs will be based on current regulations, as appropriate. The minimum capacity at each interconnection node must not be less than 40MW and preferably must be of dual capacity for fuel consumption, with specific maximum consumption of up to 2,500 kcal/kWh. CAMMESA will make known the expected locations for generation between 50MW to 150MW. The order of priority for the offers was based on increasing costs, therefore, the assessment formulas must be made available to the bidders.

On September 14, 2016, the results of the New Thermal Generation Bid were published in the Official Bulletin, granting a total of 1,915 MW (out of 6,000 MW total offers). Four offers propose to deliver new energy (545 MW of capacity) to the SADI in December 2016; ten offers propose to deliver new energy (685 MW) in the first quarter of 2017 and four more offers are expecting to deliver new energy (229 MW) in the second quarter of 2018. In addition, 26 offers are committed to start their service in the second half of 2017, and five other offers in 2018. Likewise, through Note No. 355, the SE instructed CAMMESA to encourage pricing improvements to those entities whose offers were considered acceptable but no bid was granted. As a result of new pricing offers, an additional 956 MW were granted to seven offers proposing to deliver new energy within the period from January 30 to December 1, 2017. Lastly, on October 28, 2016, the SE, through Resolution No. 387/E/2016, instructed CAMMESA to add two additional projects for a total of 234 MW. None of the Group’s entities participated in the bidding process.

On November 16, 2016, by means of Secretariat of Electrical Energy (“SEE”) Resolutions 420-16 and 455-16, the SE summoned those entities interested in developing infrastructure projects that contribute in the reduction of costs in the MEM and to increase the reliability of the Argentinean Power Grid, to express their interest, considering in particular the contribution of the preliminary plans presented with responsibility in supplying fuel for generating electrical energy. Enel Group presented two projects located on the premises of Enel Generación Costanera, for 350 MW and 415 MW. The specifications for the new combined cycles are expected to be issued in the next few months, to close the bidding process during Spring of 2017. On the other hand, by means of SEE Resolution 287 - E/2017 of May 10, 2017, the SEE instructed CAMMESA to summon all interested parties to submit their proposals (Stage I) for a new thermal generating plant with (a) combined cycle closure or (b) cogeneration technology, with the commitment to be available to meet the demands of the MEM, attaching the respective specifications and terms and conditions. 40

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projects were submitted for a total of 4,597 MW. On September 25, 2017, SEE Resolution 820 was published awarding 506 MW at an average price of 17,769 US$/MW-month and instructing CAMMESA to invite the remaining technically accepted proposals to improve their proposal, with a submission deadline on October 6 and the award on October 13, 2017, so that CAMMESA could send its analysis to the SEE.

On February 2, 2017, the SEE issued Resolution No. 19/2017 replacing SEE Resolution No. 22/2016, which set the remuneration guidelines for existent power generating plants. Resolution No. 19/2017 defines the minimum remuneration for the energy capacity of technology and scale, and allows thermal units to offer equal remuneration for availability energy contracts for all technologies. Thermal generators may declare the price of firm capacity to be committed for a three-year period per unit each summer period, and may also provide the information by summer and winter periods (adjustments could be made during the period). As an exception applicable to 2017, Resolution No. 97/2017 authorized the declaration of the Guaranteed Availability Commitments (Compromisos de Disponibilidad Garantizada, in Spanish) in conjunction with the information required for the Winter Seasonal Programming, effective from May 1, 2017 to October 31, 2017. Generators will sign a Guaranteed Availability Commitment contract with CAMMESA, which may be transferred to demand as defined by SEE. The remuneration will be received by each generation unit with a committed capacity and will be in proportion to its compliance, with the minimum remuneration calculated based on the minimum price. On the other hand, the thermal generation could offer additional capacity availability for bi-annual periods, which will be auctioned at a maximum price.

In relation to hydroelectric power plants, a new scheme is defined to assess energy capacity, which is based on actual energy capacity available (that will result in a higher value for capacity than under prior regulations). Likewise, a base is defined for the price of energy capacity, a second for the period from May 2017 to October 2017, and a third from November 2017.

The remuneration values under Resolution No. 19/2017 are denominated in U.S. dollars and will be translated to Argentine pesos using the last business day exchange rate published by the Argentine Central Bank, and will be effective for the term established in CAMMESA’s procedures. Subsequently, the SEE established that the conversion rate to be used to translate to Argentine pesos should correspond to the spot exchange rate from the day before the transaction due date, starting from November 2017.

SEE Resolution 1085/17 amends the payment process to agents for the transportation system as of December 1, 2017 (the transporter’s remuneration does not change as it was set in the RTI). Synthetically it stipulates:

·The costs associated with the transportation remuneration will be distributed proportionately in accordance with the demand.

·The Generating Agents will only pay charges from direct connection.

·Instructs CAMMESA to propose, in the next 90 days. All necessary changes in order to implement the procedures (MEM regulations).

On August 1, 2018, Resolution ME No. 46 was published that reduces the price of gas from US$ 5.20 to US$ 4.20 per MMBTU (on average) that is allocated to the electricity generation segment.

The SEE is also instructed to implement a competitive mechanism for the provision of gas for generation at a maximum defined price.

In this sense, the SEE instructed CAMMESA to carry out natural gas purchases under firm and interruptible conditions through the Electronic Gas Market (MEGSA) to supply thermal generation.

Finally, the bid on interruptible contracts for the period September-December of 2018 was tendered.

The average price of offers was US$ 3.69 per MMBTU, 13% cheaper than the price of Resolution ME No. 46.

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On November 7, 2018, Resolution 2018-70-APN-SGE was published in the Official Gazette, through which the Generators, Cogenerators and Self Generators of MEM are enabled to procure their own fuel supply for the generation of electric power.

Initially, the standard is in force for natural gas and allows generators to obtain an additional margin when producing with their own fuel, only if the gas purchase price is lower than the price recognized by CAMMESA.

With this resolution, the generators charge the variable production cost (CVP) according to the recognized prices.

CAMMESA is responsible for continuing to supply the other generators that do not buy their fuel.

Out of a total of 60 companies authorized to declare, 22 of them were registered, 6 of which correspond to Generation under 100% of Resolution 19/17.

In December 2018, the authorities allowed the export of natural gas, establishing a new procedure to authorize exports.

The surplus is generated from the availability of gas resulting from higher production from Vaca Muerta.

The authorized exports were destined to Chile and Brazil, with a total volume of 479,250,000 m3, under interruptible conditions, and for the period up to June 2020 towards Chile and for approximately 600 MW of electricity to Brazil.

Brazil

Legislation in Brazil allows the participation of private capital in the electricity sector, upholds free competition among companies in electricity generation, and defines criteria to avoid certain levels of economic concentration and/or market practices that may cause a decline in free competition.

Based on the contract requirements as stated by distribution companies, the Ministry of Energy has been involved in planning the expansion of the electricity system, setting capacity quotas by technology on the one hand and, on the other, promoting separate tender processes for thermal, hydraulic or renewable energies, or directly holding tender processes for specific projects. The operation is being coordinated in a centralized fashion in which one National System Operator (“ONS” in its Portuguese acronym) coordinates centralized load dispatch based on variable production costs and seeks to guarantee to meet demand at the minimum cost for the system. The price at which transactions take place on the spot market is called the Difference Liquidation Price (Precio de Liquidación de las Diferencias, PLD).

Generation companies sell their energy on the regulated or unregulated market through contracts, and trade their surpluses or deficits on the spot market. The free market is aimed at large users, with a limit of 3,000 kW (this limit will change to 2,500 kW as of July 1, 2019, and to 2,000 kW as of January 1, 2020) or 500 kW if they purchase Non-Conventional Renewable Energy (“NCRE”).

In the unregulated market, suppliers and their clients directly negotiate energy purchase conditions. In the regulated market, in contrast, where distribution companies operate, energy purchases must go through a bidding process coordinated by the National Electricity Agency (“ANEEL” in its Portuguese acronym). In this way, the regulated purchase price used in the determination of tariffs to end users is based on average prices of open bids, and there are separate bidding processes for existing and new energy. Bidding processes for new energy contemplate long-term generation contracts in which new generation projects must cover the growth of demand foreseen by distributors. The open bids for existing energy consider shorter contractual terms and seek to cover the distributors’ contractual needs arising from the expiry of prior contracts. Each bidding process is coordinated centrally. The ANEEL sets maximum prices and, as a result, contracts are signed where all distributors participating in the process buy pro rata from each offering generator.

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These regulatory mechanisms ensure the creation of regulatory assets/liabilities, whose rate adjustment for deficits in 2014 will take place in the tariff adjustments starting in 2015 (March for Enel Distribución Río S.A. (formerly Ampla) and April for Enel Distribución Ceará S.A. (formerly Coelce)). This mechanism has existed since 2001, and is called the Compensation Clearing Account - Part A (Cuenta de Compensación de Valores — Parte A, or “CVA”). They aimed to maintain consistent operating margins for the dealer by allowing tariff revenue due to the costs of Part A.

The CVA helps maintain stability in the market and enables the creation of deferred costs, which is compensated through tariff adjustments based on the fees necessary to compensate for deficits the previous year.

On December 2014, an addendum was signed to the concession contract for distributors in Brazil Enel Distribución Río S.A. and Enel Distribución Ceará S.A., which allows these regulatory assets (CVA’s and others) to be included in indemnitee assets at the end of the concession, and if this is not possible over time, it allows compensation through tariffs. Therefore, the recognition for these regulatory assets/liabilities is allowed under IFRS (see Note 4.d.1).

Brazil experienced drought conditions throughout 2014. In November 2014, the system reached the maximum risk of energy rationing. The average reservoir levels were 1% lower than at the last rationing. However, the government stated that there was no risk to supply.

The government created the ACR account to cover the additional energy costs through bank loans to be paid within two years through the tariff. Distributors had used approximately R$ 18,000 million (approximately US$ 3.7 billions) from the ACR account by December 31, 2014. However, this was not sufficient to cover the shortfall. In March 2015, a new loan was approved against the ACR account to cover the shortfall of November and December 2014. In addition, an extension in the payment period was approved for all loans, which currently will have to be paid in 54 months from November 2015.

In January 2015, based on the mismatches between the costs recognized in tariffs and actual costs other than those related to operations of the distribution entities, and increased inherent drought conditions costs, ANEEL began the application of a system (known as Tariffs Flags) of monthly charges over the tariff to the customers, provided that the marginal cost of the system is higher than the regulatory standard. The purpose of the regulator is to indicate the customers the generating cost of the following month, and paying in advance to the distribution companies an amount that would only be available in the next tariff review process.

The Tariff Flags system initially consisted of three levels of colored flags: Green, Yellow and Red as follows:

	Description	To be applied when CMO (R$/MWh)	Additional Tariff (R$/MWh)
Green	Favorable generation of energy conditions	<200	None
Yellow	Less favorable generation of energy conditions	>200<388.48	+ 0.025
Red	Higher costs generation conditions	>388.48	+ 0.045

From January 2015 until the reporting date of these financial statements, the values have been changing based on new expectations of future generation costs.

In summary, with this mechanism the generation cost that is currently transferred to the customer only once a year (when the annual tariff adjustment is performed) will generate a monthly variation and the customer can improve control over his/her electricity consumption. That is, the consumers will notice a lower tariff adjustment as they are paying a higher amount during the month. The flags system implemented by the ANEEL, is an accurate indicator of the actual cost of energy generated, allowing consumers a rational use of electrical energy.

As of February 1, 2016, the Red flag was separated into two levels — R$3.00 and R$4.50 — applicable to a consumption of 100kWh. Also, the Yellow flag value was reduced from R$2.5 to R$1.5 applicable to a consumption of 100kWh (or portions). The improved conditions of the rainy season in 2016 increased hydroelectrical reserves to their normal levels and the combined effect of a decrease in demand together with the addition of new power plants in the Brazilian

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electricity system, led to a change in the Tariff Flags, such that the flag was Yellow in March 2016 and Green in April 2016.

As of 2017, the values of the flags are:

·Green flag rate: Favorable generation conditions

·Yellow flag rate: R$2.00 per 100 (kWh)

·Red flag rate - level 1: R$3.00 per 100 (kWh)

·Red flag rate - level 2: R$3.50 per 100 (kWh

Green flag rate: It will be activated in the next few months when the value of the last CVU plant to be sent is less than R $211.28 / MWh;

Yellow flag rates: It will be activated in the next few months when the value of the last CVU plant is verified to be equal to or more than R$211.28 / MWh and less than R$422.56 / MWh; and

Alert signal rate: It will be activated in the next few months when the value of the last CVU plant is verified to be equal to or higher than R$422.56 / MWh, according to the following levels of application:

Level 1: It will be activated in the next few months when the value of the variable unit cost - CVU last plant is verified to be equal to or higher than R$422.56 / MWh and less than R$610 / MWh; and

Level 2: It will shoot up in the next few months when the value of the variable unit cost - CVU last plant is verified to be equal to or higher than the ceiling of R$610 / MWh.

There was a methodological alteration in the proposal regarding the metrics. Now the operation of the flags takes into account the definition the cost of the hydrological risk, given the indirect relationship between the hydroelectric generating deficit and the short-term price of electrical energy. The incorporation of these two variables to the system makes the projected collection, with the proposed values, to be more accurate in relation to the actual incurred costs.

As of November 2017, the flag values are:

·Green flag rate: Favorable generating conditions

·Yellow flag rate: R$1.00 per 100 (kWh)

·Red flag rate - level 1: R$3.00 per 100 (kWh)

·Red flag rate - level 2: R$5 per100 (kWh)

Energy tenders of recent years

In 2015, six electric power tenders were carried out for purposes of reestablishing the energy supply:

·One A-1 tender: 1,954 MW (avg.), allocated to Hydro (94%), Biomass (4%) and Gas (2%); from 1 to 3 years of energy supply;

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·Four A-3 tenders and reserve:

·97 MW (avg.), allocated to Wind (30%) and Biomass (70%), at an average price of R$200/MWh;

·233 MW (avg.), allocated to Solar (100%), at an average price of R$301.8/MWh;

·314.3 MW (avg.), allocated to Wind (72%), Hydro (15%), Gas (7%), and Biomass (6%), at an average price of R$189/MWh; and

·508 MW (avg.), allocated to Wind (52%) and Solar (48%), at an average price of R$249/MWh.

·One A-5 tender: 1,147 MW (avg.), allocated to Gas (76%), Hydro (18%) and Biomass (7%), at an average price of R$259.2 MWh.

Also, a Tender for Contracting Hydroelectrical Plants Concessions was carried out through the quota regime, in which the seller is granted energy (3,223 MW (avg)) and capacity (6,061 MW) for an Annual Operational Revenue from Generation.

In 2016, two electric power tenders were carried out as follows:

·One A-5 tender for 202 MW (avg.) allocated to Gas (2%), Hydro (58%) and Biomass (40%), at an average price of R$198.59MWh.

·One A-1 tender for 21 MW (avg.) at an average price of R$118.15 MWh.

In 2017, four tender processes were carried out as follows:

(i)A-4, set out a tender on 12/18/2017 for 2,202 MW of energy, awarded at an average price of R$ 144.51 per MWh, the distribution by nature of generation was 3% to hydroelectric, 4% to steam-electric, 16% to wind and 77% to solar;

(ii)A-6, set out a tender on 12/20/2017 for 27,366 MW of energy, awarded at an average price of R $ 189.45 per MWh the distribution by nature of generation was 3% to hydroelectric, 72% to steam-electric, 25% to wind;

(iii)A-1 and A-2, set out a tender on 12/22/2017, for 288 MW and 423 MW of energy, respectively, sold at an average price of R $177.46 per MWh and R$174.52 per MWh, respectively.

In 2018, there were three tenders with the following result:

·One tender A-4: 356.19 MW-media, assigned to Hydro (6.6%), Biomass (9.7%), Wind (16.2%) and Solar (67.5%) at an average price R $ 124.75 MWh.

·One tender A-6: 1,228.59 MW-media, assigned to Gas (26.6%), Hydro (18.9%), Biomass (0.9%) and Wind (53.6%) at an average price R $ 140.87 MWh.

·One tender A-1 and A-2, on 12/07/2018, in the A-1 were 4 MW of average energy sold at an average price of R $ 142.99 per MWh and in the A-2 were 359 MW of energy operated at an average price of R $ 161.35 per MWh

Pro rata allocation due to judicial matters

At the end of September 2016, ANEEL, based on certain judicial outcomes referring to the suspended collection of CDE charges of certain industrial participants (members of the Associação Brasileira de Grandes Consumidores

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Industriais de Energia e de Consumidores Livres or “ABRACE”), had to recalculate the CDE pro rata allocation to the rest of the applicable participants, despite having transferred Parcel A costs. Subsequently, specific tariffs applicable to the members of ABRACE will be published and the distribution companies will have to promote the new invoicing to those customers. The distribution companies must maintain the payments of the CDE parts under actual amounts (published in the resolutions); and, finally the deficit originated for the revenue losses will be included in the tariff adjustments of the distribution companies.

CDE’s Monthly Rate: Indemnification for discounts granted to consumers under judicial orders

Resolution No. 1,576 authorized electric energy distributors to recover the lower amounts billed due to judicial orders against the Energy Development Account, through the CDE’s monthly installments.

The difference between the regular tariff and the judicial order tariffs will be deducted from the CDE’s monthly installment. This adjustment will not be implemented through the tariffs and no regulatory assets will be included in the tariffs. The discount applied to the CDE’s monthly installment of consumers with judicial orders will be compensated, that is, the monthly payment of the installments will be lower than the installments defined in the resolution.

Distributed Generation

In May 2015, the regulator in a public hearing began the process to modify the regulations related to the distributed micro- and mini-generation aimed to making it more viable. The most important modification is to allow the installation of generation systems (of any renewable source, up to 3MW for hydro and 5MW for other sources) in locations other than where the load is located.

On November 24, 2015, ANEEL through Resolution No. 687/15 approved the regulation on distributed micro- and mini-generation by using an energy compensation mechanism.

Under the new regulations, effective on October 27, 2017, the use of any source of renewable energy as well as qualified co-generation is allowed. Distributed micro-generation is defined as a generating power plant with installed capacity of up to 75 kW. Distributed mini-generation is defined as a generating power plant with installed capacity of more than 75kW and less than 5 MW (3 MW for water supply) connected to the distribution network through consumption unit facilities.

On the same date, the regulation prohibits the framing as a distributed micro generation of generating plants that have already been subject to registration, concession, permit or authorization, or have entered into commercial operation or had their electric power accounted for within the scope of the CCEE or directly engaged with a concessionaire or permit holder of electric power distribution, the distributor must identify those cases.

If the volume of energy generated in a particular month is higher than the energy consumed in that particular month, the consumer has a credit that can be used to reduce the next month’s invoice. In accordance with the new regulation, the effective period for energy credits was increased from 36 to 60 months and the credits may be applied to the consumption of units by the same owner located in other places, as long as the service area is from the same distributor. This type of use for credits is referred to as “distance auto-consumption”.

Another new feature available under the regulation is the ability to install distributed generation in condominiums (companies with multiples consumption units). Under this feature, the energy generated can be distributed in specific percentages defined by the consumers.

ANEEL also created the “shared generation” scheme which allows parties interested in being part of a consortium or cooperative to install distributed mini/micro generation and use the energy generated to reduce the invoices of all members of the consortium or cooperative.

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In terms of the procedures necessary to connect the micro/mini generator to the distribution network, ANEEL set up rules that simplify the process for access requests by creating specific forms to be completed by the consumers and reducing the period, from 82 days to 34 days, which distributors have to connect the 75kW plants. In addition, from January 2017, customers will be able to make access requests and monitor their progress online.

In 2018 ANEEL made a Public Consultation, CP 10/2018, to discuss the improvement of the rules applicable to micro and distributed mini-generation (Normative Resolution No. 482/2012) where it seeks to evaluate alternatives to reduce the loss of reception of distributors.

Resolution No. 771

Public Hearing No. 81/2016 resulted in repricing related to the billing of the technical losses from the connections to the consumer units, in the cases of external measurement (SMC - System of centralized measurement) made through locations in poles or other structures owned by the Distributor.

A calculation method was established to discount from the customer’s bill the losses that occurred in the connections made through branches of external measurement systems.

Resolution No. 237

On June 6, 2016, the Ministry of Mining and Energy (“MME”) issued Resolution No. 237 allowing energy distribution companies to request to the MME that their investments in high voltage distribution systems and in substations be categorized as priority. Such classification allows the distributors to issue “infrastructure debentures”, which are financing bonds with maturities longer than those of normal bonds, and that also have tax benefits for creditors. The grant of this benefit to energy distribution companies was as a result of an initiative carried out between the Brazilian Electric Energy Distributors Association (“ABRADEE” in its Portuguese acronym) and the Ministry of Mining and Energy.

Provisional Measure No. 735

On June 22, 2016, ANEEL issued Provisional Measure No. 735, establishing the following changes:

1)Sectoral Commissions:

·Beginning on January 1, 2017, the Chamber of Electric Energy Commercialization (“CCEE” in its Portuguese acronym) will replace Eletrobás in performing the collection activities for the Global Reserve of Reversal (“RGR” in its Portuguese acronym), Energy Development Account (“CDE”) and the Fuel Consumption Account (“CCC”), as well as, in managing the financing for the payment of the administration and operational expenditures incurred in this sectorial funds.

·Beginning on January 1, 2030, the CDE’s annual installments allocation will be made in proportion to the electric energy consumer market in MWh served by the distribution companies and the distribution and transmission concessionaires. The geographical location will no longer be taken into account. From January 1, 2017 to December 31, 2029, a gradual and uniform reduction will be applied in order to eliminate the actual proportion (4.53 for the CDE installments in the South, South East, North and North East regions).

·Beginning on January 1, 2030, the cost per MWh of the CDE’s annual installments paid by the consumers will be pro rata allocated to their voltage levels, as follows:

·High Voltage = 1/3 x Low Voltage cost

·Medium Voltage = 2/3 x Low Voltage cost

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·From January 1, 2017 to December 31, 2029, a gradual and uniform reduction will be applied in order to reach the above proportions.

2)Itaipú Binacional’s Tariff

Itaipú Binacional (“Itaipú”) is a hydroelectrical power plant constructed as part of the International Agreement signed between Brazil and Paraguay on April 26, 1973, for the development of the hydroelectric resources of the Parana River located at the Brazilian-Paraguayan border (from the Seven Falls to the Iguazú’s River mouth).

The transfer tariff of Itaipu’s energy is fixed in US$/kW for monthly contracted capacity. Brazilian energy distribution companies must pay Eletrobas monthly through Itaipu’s Electric Energy Commercialization account an amount equal to the product of the monthly contracted capacity quota multiplied by the transfer tariff of Itaipu’s energy, both as approved by ANEEL.

Beginning on January 1, 2016, in accordance with Article 6 of Provisional Measure No. 735, a new transfer tariff of Itaipu’s energy was established, which will be included in the total cost of the 15.3 multiplier factor over the energy transfer cost referred to in Appendix C of the Brazilian-Paraguayan Itaipu Agreement.

3)Tenders

·For the electric energy generation, transmission and distribution concessions that will not be renewed, the Brazilian government may propose a sale/tender of the new 30-year concession period.

Law No. 13, 2013: Beneficiaries to the discount in the Tariffs for Using Distribution System (“TUSD”) and Tariffs for Using Transmission System (“TUST”)

Law No. 13,203, published on December 8, 2015, broadened the scope of beneficiaries able to use the discount under TUSD/TUST, as well as, the volume and use of the energy when it is considered and used for self-generation:

·ANEEL will establish a discount of up to 50% to the TUSD/TUST tariffs for those hydroelectrical energy projects with total capacity less than or equal to 3,000 kW and those energy projects based on solar, wind, biomass and qualified co-generation whose total capacity connected to the distribution and transmission systems is less than or equal to 30,000 kW. The discount will be applicable to energy production and consumption that is:

(i)purchased/sold for this type of projects and

(ii)used as own production for those entities beginning operations on January 1, 2016.

·ANEEL will establish a discount of up to 50% to the TUSD/TUST tariffs for those solar, wind, biomass and qualified co-generation energy projects whose total capacity connected to the distribution and transmission systems is more than 30,000 kW and less than 300,000 kW and that comply with the following criteria:

(i)the project was originated as a result of the energy auction carried out on January 1, 2016; or

(ii)the project was authorized to begin operations on January 1, 2016.

In implementing Law No. 13,203, ANEEL established Public Audience No. 38 that will replace Resolution No. 77/2004. The discounts will result in a significant increase in the amounts that are subsidized by the CDE, thus, increasing the tariffs for consumers of our subsidiaries Enel Distribución Río S.A. and Enel Distribución Ceará S.A. The fixed percentage discount of 50% proposed by ANEEL for these type of energy projects is the minimum that may be applied based on current regulations.

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White Tariff

On September 12, 2016, ANEEL Resolution No. 733/2016 approved the conditions for applying a low voltage time-of-use tariff, the “White Tariff”.

The “White Tariff” is a new time-of-use tariff option that indicates to consumers the fluctuation in the value of energy at a particular date and time of consumption. It will be offered to consumers supplied low voltages (127V, 220V, 380V and 440V, Group B) and those consumers from Group A (high voltage) that comply with certain criteria under the White Tariff.

Resolution No. 733/2016 states the following with regard to the White Tariff:

·The application will begin in January 2018 for consumers already connected with monthly consumption greater than 500 kWh (12 cycles average) and for new connections;

·The application will begin in January 2019 for consumers already connected with monthly consumption greater than 250 kWh (12 cycles average);

·After January 2020, it will be applied to all consumers;

·The value of energy, under this tariff option, will be obtained from peak, intermediate and off-peak periods and are approved by ANEEL during its periodic review of the distribution companies.

·The “low income” (under specific regulation of ANEEL) and public lighting consumers cannot opt for the White Tariff;

·The energy meter equipment cost will be charged to the distributor, except for meter equipment with additional features; and

·Any potential customization of the consumption unit will be charged to the owner.

Adjustment to pricing rate for Enel Distribución Río S.A. (formerly Ampla)

On March 14, 2017, Enel Distribución Río S.A. signed the New Concession Contract (Sixth amendment) as a result of the public hearings No. 95 and No. 58. During the hearings, the regulations and application of the rates to the registered distributors were discussed, in order to amend the rules of the concession contract, in accordance with Decree 2194/2016.

The new rules applied to determine the adjusted rates for 2017, included, among other modifications, the use of the IPCA index instead of the general market price index (“IGP-M”). The unrecoverable revenue was transferred from Part B to Part A and new regulatory loss indexes were applied. As a result, ANEEL approved an average adjustment of -6.51% for Enel Distribución Río S.A. For low voltage consumers, especially residential ones, the average adjustment was of -6.24%. The average adjustment for medium and high voltage customers was of -7.12%.

Transfer of other Transmission Installations (Demais Instalações de Transmissão or “DIT”) for distribution companies

On February 13, 2017, ANEEL issued Resolution 758/2017 establishing that voltage installations under 230 kV (Basic Grid) (hereinafter referred to as “DIT”) property of electrical energy transmission companies, should be transferred to and classified in property, plant and equipment of concessionary companies providing electrical energy distribution services.

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The following DIT will be transferred to Enel Distribución Río S.A. on its first ordinary rate review after January 1, 2019. Enel Distribución Ceará S.A. will not receive any DIT.

Other Transmission Installations (DIT)	Km	Classification	Operational situation	Responsible Distributor	Proprietary Transmitter
IMBARIE	—	SE DIT	In operation	Enel Distribución Río S.A.	Furnas
IRIRI	—	SE DIT	In operation	Enel Distribución Río S.A.	Furnas
Transmission line 138 KV ADRIANOPOLIS/MAGE RJ	48	LD	In operation	Enel Distribución Río S.A.	Furnas
Transmission line 138 KV CAMPOS/IRIRI RJ	98	LD	In operation	Enel Distribución Río S.A.	Furnas
Transmission line 138 KV IMBARIE/ARIANOPOLIS RJ	15	LD	In operation	Enel Distribución Río S.A.	Furnas
Transmission line 138 KV IRIRI/ROCHA LEAO RJ	12	LD	In operation	Enel Distribución Río S.A.	Furnas
Transmission line 138 KV ROCHA LEAGO /MGE RJ	108	LD	In operation	Enel Distribución Río S.A.	Furnas

ANEEL considers that this measure will improve the operating efficiency of the power grid. The incorporation of the DIT into the distribution companies will take place in the first rate review after January 1, 2019. According to current regulations, at that time, the power lines and substations will be accounted for as part of the property, plant and equipment of the distribution Company, and they have to be incorporated on the calculation rate process. The distributing companies will be compensated for a value equivalent to the non-depreciated assets, within 30 days after the rate review of the distribution Company receiving the DIT.

Adjustment to energy rate for distribution companies including the devolution of the cost of the Reserve Energy Order (EER) with the highest included in the adjustments.

Through Resolution No. 2,214 / 2017, ANEEL published the rates of all of the power sector distribution companies to return in April 2017 the highest cost values of Angra III included in the rates.

For the period of April 2017, the energy rate for Enel Distribución Rio, Enel Distribución Ceará and Enel Distribución Goias were reduced in order to return the values of the costs of Angra III. The objective is to return the effects of the inclusion of the Part A of the Reserve Energy Order (“EER”) corresponding to the contracting of the Angra III plant one time only. Remembering that, via the natural rate adjustment process of the distribution companies, these amounts would be returned to the consumers in 12 months.

The procedure was divided into two stages: In the first, in April 2017, the rate will be reduced to revert the values of Angra III included from the previous rate-setting process and, at the same time, it will cease to consider the future cost of the EER of that plant. In the second stage, which started on May 1, 2017, and continues until the next rate-setting process of each distribution Company, the rate will cease to include (i) the future cost of the EER of Angra III and (ii) for the distribution companies which already experienced the adjustment in 2017, as is the case of Enel Distribución Rio, the value of the return in 12 months that was already included in the rate.

Modifications to review period of Enel Distribución Goias pricing from October 2017 to October 2018

In a Public Meeting, ANEEL approved ENEL’s request to change the review period of the rates of Enel Distribución Goias to 2018, after discussing the issue in a Public Hearing. As a result, the decision was to perform the review, which will be performed in October 2018 and every 5 years, with the new cut-off date for investments being April 30, 2018.

In addition to working on the quality of the information, the postponement will allow us to recover within the Remuneration Base past costs assigned as OPEX (capitalization of additional costs) and immediately recognize the investments made in the first year of ENEL’s operation in the company, as of such moment and until April 2018.

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Enel Distribución Goias Adjustment

On October 17, 2017, ANEEL authorized the rate price adjustment of Enel Distribución Goias by means of Resolution No.2,317. The annual rate adjustment of Enel Distribución Goias had an average effect on the rates of the consumers of 14.65%, with 12.03% on average for High Voltage consumers and 15.89% for Low Voltage consumers.

Public Hearing 066/17- WACC

On March 6, 2018, ANEEL approved the result of AP066, established to review the weighted average cost of regulatory capital of the distribution segment related to Sub-module 2.4 of the Tariff Regulation Procedures - “PRORET”. The Board of Directors, unanimously, decided to revoke the forecast for updating the weighted cost of capital in 2018 and approve a new version of Sub-module 2.4 of the Tariff Regulation Procedures — “PRORET”, which establishes the anticipation of the methodological revision for the year 2019, with application from January 2020.

Public Hearing 052/17 — Operating Cost

On March 6, 2018, ANEEL approved the result of the AP052 with updating of the parameters related to the definition of the Regulatory Operating Costs - Submodules 2.2 and 2.2A of the Tariff Regulation Procedures - PRORET. The efficiency of Enel Distribución Ceará remained unchanged at 100%, remaining as one of the most efficient distributors in management of operating costs in Brazil according to ANEEL.

Operating Cost Efficiency Index

Enel Distribución Ceará	100.00	%
Enel Distribución Goias	78.37	%
Enel Distribución Rio	59.50	%

Enel Distribución Rio Adjustment

On March 13, 2018, ANEEL approved the provisional result of the Fourth Periodic Tariff Review of Enel Distribución Rio, as of March 15, 2018, consolidated after evaluating the contributions made at Public Hearing No. 078/2017.

The result leads to the average effect on consumers of 21.04%, which is 19.94% for consumers connected to High Voltage and 21.46% for those connected to Low Voltage. The T component of Factor X is fixed 0.00% and the technical losses is fixed at 9.1%.

Enel Distribución Ceará S.A. Tariff Adjustment

On April 17, 2018, ANEEL approved the provisional inflation results of Enel Distribución Ceará, as of April 22, 2018.

The result leads to the average effect on consumers of 4.96%, which is 7.96% for consumers connected to High Voltage and 3.8% for those connected to Low Voltage.

Enel Distribución Goiás S.A. Tariff Adjustment

On October 16, 2018, ANEEL conformed the result of the review of Enel Distribución Goiás, as of October 22, 2018.

The result leads to the average effect on consumers of 18.54%, which is 26.52% for consumers connected to High Voltage and 15.31% for those connected to Low Voltage.

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Enel Distribución São Paulo (ex Eletropaulo) Tariff Adjustment

On April 04, 2018, ANEEL approved the tariffs applicable for the consumers.  This process resulted in a tariff adjustment of +16.4%, made up by an economic adjustment of +10.5% and a financial adjustment of +5.9%.  After eliminating the financial adjustment of the previous year (0.6%), the average effect to the consumer amounted to +15.8%, which is greater for consumers connected to High Voltage (+17.7%), while those connected to Low Voltage received a lower increase of 15.1%.

Enel CIEN Adjustment

Resolution No. 2408, dated October 22, 2018, established the annual income allowed (RAP) for the public service concessionaires of electric power transmission, for those available transmission facilities under its responsibility.

The values of Enel CIEN are: Garabi I (RAP: R$ 72,667,795.35 and adjusted PA: R$ - 6,579,727.76) and Garabi II (RAP: R$ 179,367,079.58 and adjusted PA: R$ - 6,834,803.35).

Electric Vehicles Charging

Through Normative Resolution No. 819 of 2018, ANEEL established the procedures for electric vehicle recharging activities.

The distributor may, at its discretion, install charging stations in its concession area intended for the public charging of electric vehicles, which must be classified in the subclass electric vehicle charging station of the consumption class itself (Group Tariffs A - MV and HV or Tariff B3 - LV).

In the event of revenue generation at the distributor’s charging station, these may be established at freely negotiated prices, applying to the activity the procedures and conditions for the provision of ancillary activities, in the terms of Res. 581/2013 (partial reversion to reasonable tariffs and a separate accounting standard);

The provision of electric vehicle charging activities by the distributor is at its own risk, and the assets that make up the infrastructure of the charging stations will not be part of its asset base;

The charging of other electric vehicles, not of property of the consumer is permitted, even for commercial exploitation purposes at freely negotiated prices;

The installation of the charging station shall be notified in advance to the distributor, in the event that the installation results in the need to create or alter the consumer unit;

Information from the charging stations shall be sent by the distributor to ANEEL every six months on a consolidated basis (January and July);

In the event that it is necessary to adapt the electricity network and the metering system, the costs will be made using the criteria set forth in the regulations in force;

Any interested consumer may register with ANEEL, using their own form, a charging station for consumers of their ownership;

Public charging equipment shall be compatible with open protocols in the public domain for communication and remote supervision and control.

Electric vehicle charging equipment shall comply with the regulations and standards established by the distributor, as well as other applicable standards issued by the competent official bodies, including ANEEL’s regulations;

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The injection of electric energy into the distribution network from electric vehicles is prohibited, as well as participation in the Energy Compensation System (Res. 482);

The rules on compensation for electrical damage are fully applied to electric vehicle charging installations, and the distributor may establish specific electrical safety standards for installations (only LV);

Enel Generación Fortaleza

The Fortaleza Thermoelectric Generating Plant (hereinafter CGTF), the Enel Group’s natural gas-operated thermal plant in Brazil, is without fuel supply due to the unilateral termination of the supply contract by Petrobras. The plant was built under the guidelines of the Programa Prioritario de Termoelectricidad (Thermoelectric Priority Program or PPT), a government program established during the energy rationing period that occurred in the country in 2001 that aimed to stimulate the construction of thermoelectric plants in the system. To this end, the government secured the financing of the projects by BNDES, as well as the supply of fuel by Petrobras for up to 20 years. The formula for adjusting the gas price of fuel contracts was regulated and defined through Portaria published by the Ministry of Mines and Energy.

In this context, Enel Brasil filed a lawsuit against Petrobras in order to re-establish the supply of gas to the plant, stating that Petrobras cannot unilaterally rescind the contract as it was guaranteed by the Union through a government PPT program. We obtained a mandate that determined Petrobras’ gas supply for the plant, which was rejected on July 2, 2018. Enel Brasil appealed the decision and in the judicial instance, the Special Court of the Federal Regional Court (TRF) has granted a new mandate to force Petrobras to return the gas supply to the CGTF under the conditions of the contract signed under the PPT. On December 11, 2018, Petrobras was notified of the decision, which will remain in effect until the appeal is heard. Petrobras may file an appeal before the Superior Court of Justice in Brasília.

It should be noted that, during the last few months, Enel Brasil has worked with the Brazilian Government and Congress to find the best solution to the problems related to the electricity sector mentioned above, and with the rejection of PLC No. 77/2018 (formerly PL10.332), Enel Brasil will act institutionally together with the Ministries to seek the publication of an interministerial regulation that deals with the solution of gas supply within the framework of the PPT and together with the advisors of the presidential candidates to define a way of moving forward on the consensual issues that were not approved in PLC 77/2018.

In addition, on August 3, 2018, CGTF requested suspension together with the Regulator ANEEL of the contractual obligations in which it required : (i) determination of gas supply or determination that Petrobras deliver energy for CGTF under penalty of short-term market exposure associated with lack of gas supply; (ii) recognition of exclusion of CGTF’s liability by the public authority from the breach of the PPT between July, 1,2018 and the date of commencement of operation, under the conditions established by MME’s one-time solution, eliminating the application of any penalty and incidental contractual, commercial and regulatory obligations on CGTF.

To date ANEEL has not pronounced a final decision, because in the last Board meetings in which the process was discussed, there were requests further points of view by other Directors. Consequently, Enel Brasil continues working with ANEEL’s Board of Directors for a positive solution.

Proposal for a solution to the short-term lack of market liquidity

The Brazilian short-term market has been illiquid since 2015, the year in which several legal limits were granted to hydro generators for their assumption of non-hydrological risks. This is because the thermal dispatch carried out outside the order of costs of service , the import of energy without physical guarantee and the impact of the structuring plants (Belo Monte, Jirau and Santo Antônio plants) displaced their generation and exposed them to the market in the short term on account of non-manageable factors unrelated to hydrological risk. In this way, the hydro generators would be exempted to pay their debts in the market in the short term, sum that currently amounts to R$ 6.95 billion and represents about 70% of the total book value of the market.

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In substitution of the rejected PLC 77/2018, an amendment to PLS 209/2015 was presented that calculates the impact of the non-hydrological risks assumed by the hydro power plants and compensates them through the extension of their concession term, with the condition of the abandonment of judicial processes and the payment of their debts. The objective of this solution is to solve the impasse of the hydro generators and restore the liquidity of the Brazilian market in the short term.

In addition to the legislative solution, ANEEL is discussing an agreement based on Law 13.203/2015 that recognizes the compensation for the impacts of the year 2015 as a regulatory asset to be received through the extension of the granted term. It also includes the condition of desisting from legal processes and payment of its debts.

Public Consultation ANEEL- No. 15

ANEEL opened a public consultation to obtain subsidies on the WACC’s methodology and update for the distribution, transmission and generation segments.

It proposes three alternative methodologies:

Alternative A

·Maintenance of the current methodology (WACC / CAPM)

·Replacement of some further series in the calculation

·That data windows used in Dx / Tx / Gx become compatible

Alternative B

·Maintenance of the current methodology (WACC / CAPM)

·Nationalization of the WACC calculation

·That data windows used in Dx / Tx / Gx become compatible

Alternative C

·Adoption of an alternative methodology to define the WACC to be adopted

The agents had until September 30, 2018 to contribute. In summary, Enel Brasil contributed the following elements:

1)with the objective of obtaining coherent parameters for the WACC calculation, it understands that these are tools that the regulator must provide when calculating the WACC:

a)Adequate statistical treatment to the series of data used, with the use of the average as a measure of a tendency for all the series and with the withdrawal of eventual outliers, in order to bring greater consistency and robustness to the results;

b)The correct selection of data series to correctly reflect the real risks faced by energy distributors, especially for the beta parameter.

c)In the case of the risk-free asset parameter, the use of other criteria to choose the series (such as Convexity), not exclusively the duration as a model for assessing the sensitivity of a flow of capital to the time of duration as a function of changes in interest rates.

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2)The reduction verified in the calculation of the beta parameter based on the American market is not consistent with the current business risk of the distribution segment in Brazil.

3)corroborates the current methodology for calculating the cost of capital of third parties and refutes the substitution of its calculation based on data from the secondary debentures market

Public Hearing No. 61/2018

The Superintendencies of ANEEL are working together to develop the Transmission Geographic Data Base (BDGT) that will be used in the future for various purposes, such as, survey of assets and attributes of transmission facilities, support to the processes of annual income review and technical analysis of blackouts in the transmission system.

In this context, ANEEL has composed the list of assets and their attributes to compose the database. The creation of the BDGT will lead to the publication of a specific Normative Resolution, which will define the main issues related to obligations and deadlines.

The proposal is that the regulation of the BDGT enters into force at the close of publication of the standard. With regard to the accounting part in the BDGT the term will be up to 6 (six) months after ANEEL creates the loading routine and these data.

The contribution period is from December 20, 2018 to February 17, 2019.

Public Hearing No. 60/2018

ANEEL decided for the opening of the Public Hearing, with a view to collecting subsidies and additional information for the improvement of the voltage conformity regulation.

In summary, the problem to be addressed is related to the improvement of the control stages of the sample measurement process, in particular the stage of installation of measurement, extraction and data processing. According to the regulator, there is currently a low inspection capacity at these stages of the process, where reduced traceability is detected.

Therefore, the problem analyzed in the Regulatory Impact Analysis focused on the reinforcement of the inspection capacity and on the reduction of information asymmetry, in the stages of installation of the measurements and treatment of the data from these measurements. The deadline established by the regulator for the receipt of contributions closes on February 18, 2019.

Public Hearing No. 56/2018

ANEEL established the Public Hearing to collect subsidies and additional information to improve the proposal for adaptation of article 24 of Normative Resolution No. 414/2010, which deals with the requirement imposed on the National Observatory to carry out studies regarding the necessary time for the use of public lighting and lighting in internal roads of condominiums, taking into consideration the specificities of each locality.

Article 24 of REN 414/2010 provides for studies to be carried out by the National Observatory (NO) for alteration of the time to be considered for consumption of electric energy in public lighting and in condominium internal roads. However, the NO requested ANEEL to exclude this allocation, since it does not have sufficient elements to carry out the studies in question.

ANEEL presents 4 alternatives to solve the previous problem:

·Maintain the current regulation.

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·Only withdraw the accomplishment of the studies by the NO and maintain the possibility of performance of studies by the interested parties.

·Change the regulation, withdrawing the performance of studies by the NO and carrying out studies through existing tools (by ANEEL), maintaining the possibility of performance of studies by the interested parties.

·Change the regulation, withdrawing the performance of studies by the NO and promoting a tender (by ANEEL) to contract the studies for the calculation of the time of artificial illumination by Municipality, maintaining the possibility of performance of studies by the interested parties.

·Change the regulation, withdrawing the performance of studies by the NO and forcing the distributors to carry out the studies for all the municipalities in their areas within a certain period (1 year).

Public Hearing No. 28/2018

ANEEL established the second phase of the Public Hearing to obtain subsidies and additional information to improve the proposal for the review of Module 5 of the Distribution Procedures (PRODIST) and the improvement of the recurrent reading process with respect to Normative Resolution No. 414/2010.

Among the proposals presented by ANEEL, the following stand out:

·Impeded access - access: The alternative proposed in the first phase of AP No. 28/2018 was to offer the distributor a minimum list of solutions to the consumer, mandatory in the cases of impeded access and optional, for the others. Now, ANEEL proposes that distributors offer solutions at their discretion, considering their operational reality and that of the location of the consumer units.

·Impeded access - Instruments that verify the visit to the meter: The initial proposal considered that the distributor should present proof that it has visited the consumer unit with access restriction. As some distributors said that they already use georeferencing techniques and photographs to check where impeded access exists, ANEEL understood that it is necessary that the other distributors need to adapt.

·Impeded access - Charge for inability to do a reading: ANEEL maintained the initial proposal of maintaining the regulations in force, that is, not allowing the distributor to charge the consumer when there is an unsuccessful attempt to read, even due to responsibility of the latter.

·Impeded access — Invoicing: value to be invoiced, as long as the impeded access persists: ANEEL opted for invoicing considering the arithmetic average of the last twelve months. Criterion for the adjustment of the invoicing, after the regularization of the reading: Limitation of retroactive collection, with period of limitation with the application of the provisions of article 113 of Normative Resolution No. 414/2010.

·ANEEL’s proposal foresees that self-reading will be a prerogative of the distributor, who can evaluate the benefits and risks of delegating that activity to the consumer. Therefore, the problems derived from self-reading should be treated in a manner equivalent to the failures derived from the readers hired by the distributors, i.e., if there is incorrect invoicing due to self-reading, the application of article 113 of Normative Resolution No. 414/2010 should be considered.

·Reading by group of months: ANEEL proposes to maintain the regulations in force, allowing this modality only for consumers located in rural areas.

·The consumer units invoiced by estimate (articles 72 and 91 of Normative Resolution No. 414/2010) for the non-obligation of the installation of the measurement, such as public lighting, traffic lights and others, was evaluated not to be reasonable in that the invoicing does not occur in the calendar month but as if there were a fictitious

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metering reading. Thus, the agency proposes that, in these situations, the invoicing corresponds mandatorily to the calendar month, in order to improve the consumer’s understanding of the days invoiced and to avoid the proportionality of the tariff bands.

·Regarding the possibility of postponing the receipt of low-value invoices, ANEEL understood this to be a timely practice. Thus, the proposal is to allow such procedure, provided that the accumulation of invoices does not occur for more than three cycles and that the consumer can, at any time, choose not to have his invoices accumulated.

ANEEL intends to define the validity of the changes from the beginning of 2020.

Public Hearing No. 46/2018

In the period from October 4 to December 3, 2018, ANEEL established Public Hearing No. 46/2018, with the objective of collecting subsidies and additional information for the improvement of the review of the regulation of the continuous supply of electricity.

This is the first phase of the improvement process, in which the alternatives presented in the Regulatory Impact Analysis will be discussed.

The objective is to encourage the improvement of service quality, addressing the following issues: focus of the compensations for violation of individual continuity indicators, formulation of compensations, tariff reviews and structure of continuity indicators. With regard to compensation, the proposal is to update the limits established to guarantee quality improvement for consumers with lower service levels than expected, based on higher compensated values.

The formulation of compensation will be simplified, excluding quarterly and annual limits. The proposal is to modify the basis for calculating the value to be compensated, which withdraws from the compensations items that cannot be handled by the distributors, such as the purchase of energy and sectoral expenses.

Another proposal is that interruptions of external origin should not be considered in the compensations. Thus, distributors will be held responsible only for events that occur in their area of operation, aligning Brazilian regulation to international practice. The calculation of the indicators, however, will continue to count all the amounts that impact consumers.

The contribution period ended on December 3, 2018 and the second phase of the public hearing was opened in the first semester of 2019.

Decree No. 9.642 of December 27, 2018

The ANEEL, in the use of its mandate, vetoed the cumulative application of tariff discounts, using the one that grants the greatest benefit to the consumer.

Office No. 18 of January 4, 2019

The ANEEL, in the use of its mandate, received the preliminary negative judicial decision determining the suspension of paragraph II of article 113 of Normative Resolution No. 414/2010, ordering that, when a billing error occurs for reasons attributable to the distributor, the limit of the return to consumers will be 10 years instead of 36 months, as determined by the resolution.

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Colombia

In 1994, the Public Utility Law (Ley de Servicios Públicos Domiciliarios, Law 142) and the Electricity Law (Ley Eléctrica, Law 143) were passed. These laws set out the general criteria and policies ruling the public utility service provision in Colombia, as well as the procedures and mechanisms for regulating, monitoring and overseeing them.

The Electricity Law puts the constitutional focus into practice, regulating the generation, transmission, distribution and sale of electricity, creating the market and competitive environment, strengthening the industry and setting the boundaries for government intervention. Taking into account the nature of each activity or business, general guidelines were established for developing the regulatory framework, creating and implementing the rules that would allow for free competition in the power generation and sales industries, while the directives for the transmission and distribution industries were geared toward treating these activities as monopolies while seeking out competitive conditions wherever possible.

The main institution in the electricity sector is the Mining and Energy Ministry, whose Mining Energy Planning Unit, (Unidad de Planeación Minero Energética, or UPME) draws up 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, and the Superintendency of Industry and Commerce is the national authority for free trade protection issues.

The electricity industry operates on the basis of electricity-selling companies and the large consumers being 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, long-term auctions of Firm Energy within a Reliable Charge scheme are carried out to promote the expansion of the system. The market is operated and administered by XM, which is in charge of the National Dispatch Center (Centro Nacional de Despacho, CND), and the Commercial Interchange System Manager (Administrador del Sistema de Intercambios Comerciales, ASIC).

Peru

The main legislations in the regulatory framework for doing business in the power industry in Peru are:

·Electricity Concessions Law (DL 25,844) and its regulations (DS 009-93-EM).

·Law to Ensure Efficient Development of Electricity Generation (Law No. 28,832); and its Regulations, DS 019-2007-EM (Regulation of the Compensation Mechanism among the regulated users of the SEIN), DS 027-2007-EM (Transmission regulations), DS 052-2007-EM (Supply of Electricity Bidding Regulations), DS 022-2009-EM (Unregulated electricity users Regulations) and DS 026-2016-EM (Regulation of Electricity Wholesale Market.).

·Decree promotion of generation with non-conventional renewable sources in Peru (DL 1,002) and its Regulation (DS 050-2008-EM)).

·Decree improving the regulation of electricity distribution to promote access to electrical energy in Peru (DL 1,221) and its Enabling Regulations (DS 018-2016-EM).

·Decree amending several rules of the Electric regulation framework of Peru (DL 1,041) and Regulations (DS 001-2010-EM).

·Law that Strengthens Energy Security and Promotes the Development of the Petrochemical Complex in the South of the Country (Law 29,970) and its Regulation (DS 038-2013-EM).

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·Anti-Monopoly and Oligopoly Law of the Electricity Sector (Law 26,876) and Regulations (DS 017-98-ITINCI).

·Law Creating the Energy and Mining Investments Supervisor Agency “OSINERGMIN” (Law 26,734) and its Regulations (DS 054-2001-EM).

·Technical Standard of the Quality of the Electricity Services (DS 020-97-EM).

·Regulations for the conservation of the Environment in Electrical Activities (DS 029-94-EM) and Hydrocarbon Activities (DS 015-2006-EM).

·Framework law on Climate Change (Law 30,754).

Law 25,844 specifies that the Peruvian power sector is divided into three large segments — Generation, Transmission and Distribution — in such a way that more than one activity cannot be carried out by the same company. The Peruvian power grid is made up of a single power grid called National Interconnected Grid (SINAC), in addition to a few isolated power grids. The Company performs its operations in the electrical energy generating segment as a member of SINAC.

According to the Law, the operation of the generating companies will be subject to the provisions of the Economic Operation Committee of the National Interconnected Grid - COES-SINAC, with a view to coordinating their operation at minimum cost, guaranteeing the security of the supply of electrical energy and better use of the energy resources. The COES-SINAC administers the transfers of power and energy between generating companies, considering the injections and withdrawals according to the contracts, and it sets a value on such transfers every month, as well as also compensation for the owners of the power grids and compensation for other generating companies, according to the regulations stipulated in that regard by OSINERGMIN.

The main purposes of Law 28,832 are to i) ensure the sufficiency of efficient generation of electricity, which reduces the exposure of the electricity system to price volatility and the risk of rationing due to lack of energy; and ensures the consumer a competitive electricity rate; ii) reduces administrative intervention in calculating generating prices by means of market solutions; and iii) promote effective competition in the generation market.

The main changes introduced by the Law are related to the participation in the short-term market of generation companies, the distribution companies and the unregulated large customers, including both distribution companies and unregulated customers as members of COES-SINAC, modifying the structure of this agency. In addition, the bidding mechanism that must be followed by the electricity distribution companies in order to enter into electricity supply contracts with the generating companies aimed at supplying the public electricity service and optionally for the unregulated users was introduced.

The sale of energy that the generators make to distributors that are destined to the public service of electricity, will be carried out at Generation Level Prices that are calculated as the weighted average of Contracts without Bidding and Contracts resulting from Tenders. The purpose of this provision is to establish a mechanism that promotes investments in new generation capacity through long-term electricity supply contracts and firm prices with distribution companies.

By means of Supreme Decree No. 026-2016-EM, the Regulation of the Wholesale Electricity Market (MME Regulation) was approved. Among the main aspects of the MME Regulation are: it incorporates the definition “MME” which is made up of the short-term market (“MCP”) and the mechanisms for assigning complementary services, operational inflexibilities and allocation of congestion rents.

The participants authorized to buy on the MCP are: the generators to meet their supply contracts; the distributing companies to serve their unregulated users, up to 10% of the maximum demand; and large users to attend to up to 10% of their maximum demand.

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The COES will calculate the marginal energy costs and marginal congestion costs, evaluate the transactions on the MME on a daily basis and the results will be made available to the participants on the COES web portal. The Congestion Rents will be assigned among the Participants in accordance with the provisions of the respective Procedure. The participants must have guarantees of payment of their obligations in the MME, in addition to incorporating the actions by the COES in the event of non-compliance with the payment obligations by a participant.

Decree No. 1,002 creates a promotional regime for non-conventional renewable sources of energy “RER”; it also creates a mechanism that guarantees income paid through the demand via the rate charged at the connection usage charge. Its purpose is to incorporate up to 5% of the production of electrical energy by means of renewable energy sources and the generation of RER is promoted via tenders.

Decree No. 1,221 amends several articles of the Law on Electricity Concessions DL 25844, introducing mainly the following changes in the scope of distribution:

·The Ministry of Energy and Mines will determine a Technical Responsibility Zone for each distribution concessionary Company, with the possibility of expanding their current concession zone by assuming nearby rural areas, whose Works may be financed by the State and received by the concessionary companies with a recognition of actual audited Operating and Maintenance costs.

·It establishes the carrying out of studies and the setting of Value Added Distribution (VAD) individually for each distribution concessionary Company providing services to more than 50,000 suppliers, according to the procedure set in the Regulations.

·Recognition of an additional charge for technological innovation projects previous approved by OSINERGMIN, equivalent to a maximum percentage of the annual revenues.

·Incentives to improve the quality of the service as of the current quality until the target value is achieved.

Supreme Decree No. 018-2016-EM amended the Enabling Regulations of the Electricity Concessions; the main amendments are that it incorporates the possibility of installing supplies with intelligent metering; these installations and their investment costs will be owned by the distribution Company; O&M will be considered in the VAD; the proposed Technical Responsibility Zones (ZRT) will be published in advance; technological innovation projects will be included in the VAD and they will be compensated by means of a charge for power.

Likewise, with respect to customers who may choose to belong to the regulated or free market, Supreme Decree No. 018-2016 maintained the following provisions:

·The range for customers who may choose to be regulated or unregulated was maintained between 200 and 2500 kW.

·The change of condition shall be notified to the current supplier at least one year in advance. The user must remain in the new condition for at least 3 years.

·Customers whose peak demand is greater than 2,500 kW are unregulated customers.

Legislative Decree No.1,041 amended several articles of the Law on Electrical Concessions (DL No. 25,844) and the Law to Ensure Efficient Development of Electrical Generation (Law No. 28,832).

Supreme Decree No. 001-2010-EM regulated DL 1041, which amends the electrical regulatory framework, for dispatching natural gas and the remuneration of power and energy. A special remunerative regime was also created for the cold reserve that will be put out to tender by PROINVERSION, to prevent any rationing due to a deficit in

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generation. As far as the transmission regime is concerned, the responsibility of payment of the rate base of the Guaranteed Transmission System was finally amended to assign it exclusively to the users.

Law No. 29,970 extends the guaranteed income mechanism of Law No. 27,133 to energy security projects and promotes the participation of State-owned companies in those projects. It creates a system of compensation for costs of natural gas in the north and south charged to the transmission usage charge. This law creates a subsidy mechanism to be paid for electrical demand to finance natural gas infrastructure (transportation, storage, support and others) and generation using natural gas, which results from the planning and awards processes managed by the State.

Within this framework, the South Peruvian Gas Pipeline Project (GSP) was tendered, a contract that was terminated in February 2017 due to the fact that the concessionaire did not comply with the financial closing within the established contractual term.

Through Law No. 30,754, the Framework Law on Climate Change was enacted. It is governed by the principles of Law 28,611, General Environmental Law; Law 28,245, Framework Law of the National Environmental Management System, National Environmental Policy, and the United Nations Framework Convention on Climate Change. It will allow the State to issue standards related to the development of RER generation, electric vehicles and sustainable investments consistent with the Paris Agreement.

Legislative Decree No. 1394 modifies articles of the National Environmental Impact Assessment System Law (SEIA), and the Law creating SENACE. The objective is to strengthen the functioning of the competent authorities, in order to modernize and ensure a timely and efficient evaluation of environmental management instruments.

Legislative Decree No. 1451 modified article 122 of the Law of Electrical Concessions, which defines the criteria for restricting vertical or horizontal integration in the sector. The modification incorporates provisions for those cases of vertical integration that do not qualify as acts of concentration according to the regulations of the matter.

Supreme Decree No. 033-2017-EM, stipulates that the Enabling Regulations of the Electricity Wholesale Market, approved by means of Supreme Decree No. 026-2016-EM, come into force as of January 1, 2018.

Supreme Decree No. 040-2017-EM amended articles 95 and 96 of the Enabling Regulations of the Law on Electricity Concessions, related to operating the system in Exceptional Situations and with the information on the generating units as provided by the agents that imply operating inflexibilities; article 7 of the Enabling Regulations of the Electricity Wholesale Market with regard to assigning costs for operating inflexibilities; and Final Provision Sixteen of the Technical Standard of Quality of the Electricity Services with regard to the fact that no sanctions and/or compensations are applied in Exceptional Situations.

Supreme Decree No. 043-2017-EM amended: article 5 of Supreme Decree No. 016-2000-EM, stipulating that the generating companies that use natural gas as fuel must declare the single price of gas once a year, coming into force as of July 1, 2018, except for the first period of the declaration. The COES checks that the declared value is at least the result of applying a formula that considers the Contractual Daily Amount, the specific consumption, take or pay contracts and the price of the supply of natural gas, without including transportation and distribution.

Supreme Decree No. 005-2018-EM modifies several articles of the Regulations of the Wholesale Electricity Market, approved by Supreme Decree No. 026-2016-EM, are modified in order to specify aspects related to the participation, guarantee, default, elimination or exclusion of participants in the MME.

Supreme Decree No. 017-2018-EM establishes the Rationing Mechanism for situations that place at risk the supply of natural gas, understood as an “emergency”, which is the total or partial shortage of natural gas in the internal market, duly qualified by the Ministry of Energy and Mines.

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Supreme Decree No. 022-2018-EM (modified by D.S. No. 026-2018-EM) modifies the Regulation of Electricity Supply Tenders, approved by Supreme Decree No. 052-2007-EM, in order to establish provisions on the procedure for the evaluation of proposals for modification of contracts resulting from tenders.

Non-Conventional Renewable Energy

·In Brazil, ANEEL holds auctions by technology considering the expansion plan set by the Empresa de Pesquisa Energética (“EPE”), the planning agency; so that the target amount set for non-conventional renewable energy capacity is met.

·In Colombia, Law No. 1,715 was enacted in 2014, which created a legal framework for the development of non-conventional renewable energy, in which guidelines for declarations of public interest, as well as tax, tariff and accounting incentives were established. As part of the implementation, the Ministry of Mines and Energy enacted Decree No. 2,469 in 2014, establishing guidelines for energy policy on supply of self-generation surpluses. In 2014, CREG published resolution 132 defining the methodology for determining the firm energy of the geothermic plants to be able to access the Reliability Charge. Likewise, CREG issued Resolution No. 24/2015, regulating high-scale self-generation activity, and the Mining Energy Planning Unit (“UPME”) issued Resolution No. 281/2015, establishing the limit for low-scale (equal to 1MW) self-generation.

In addition, CREG issued Resolution Nos. 11 and 212 in 2015, encouraging mechanisms to act in response of the demand. Likewise, the regulatory authority published resolution 61 of 2015 to determine the methodology for calculating the firm energy of wind farms in order to enable them to participate in the Reliability Charge scheme, which was recently amended by resolution No. 167 of 2017. The Ministry of Mines and Energy issued Law Decree No. 1,623 in 2015 that established guidelines on zone expansion policies, and Law Decree No. 2,143 that outlined the application of fiscal and tax incentives established in Law No. 1715. In 2016, the UPME issued Resolution No. 45/2016, establishing procedures for the request of certificates to support Sources of Non-Conventional Energy’s (FNCE in its Spanish acronym) projects and to obtain the list of goods and services exempted from duties or value added tax (“VAT”).

In 2017, CREG published Document 161 in which it set forth four alternatives for integrating Non-Conventional Sources of Renewable Energy (FNCER) into the generating capacity, including: i) Green bonus, ii) Long-term contracts pay for what is generated, iii) Long-term contracts of average energy, and iv) Long-term contracts pay for what is contracted.

In 2016, the Ministry of Environment and Sustainable Development (Ministerio de Ambiente y Desarrollo Sostenible or MADS) issued Resolution No. 1,283, which establishes the procedures and requirements for

obtaining environmental certifications for new investments in projects for sources of non-conventional energy and the efficient management of energy, in order to obtain the tax benefits specified in Articles 11, 12, 13 and 14 of Law No. 1,715. Likewise, MADS issued Resolution No. 1.312/2016 that establishes referral terms for preparing Environmental Impact Study’s required for environmental licenses for sources of wind energy projects, as well as Resolution No. 1,670 of August 15, 2017 by which it adopted the terms of reference for the preparation of the Environmental Impact Study (EIA), required for the processing of the environmental license for projects using photovoltaic solar energy.

Finally, the Ministry of Environment and Sustainable Development, through Decree 2.462 of December 28, 2018, establishes that only projects exploring and using alternative energy sources that come from biomass to generate energy with an installed capacity greater than 10 MW, excluding solar, wind, geothermal and tidal energy sources, will require an Environmental Diagnosis of Alternatives, or DAA.

In February 2017, the Energy and Gas Regulatory Committee, through Resolution No. 243 of 2016, issued the methodology for calculating the Firm Energy of the Photovoltaic Solar Plants, necessary for this technology to be able to participate in the assignations of the Reliability Charge. This resolution was amended by Resolution No. 201 of 2017.

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In September 2017, the Ministry of Mines and Energy issued decree 1543, which regulates the Non-Conventional Energy and Efficient Energy Management Fund, or FENOGE, whose purpose is to finance FNCER and efficient energy management programs, by fostering them, promoting them, stimulating them and incentivizing them, through the autonomous equity. Among others, programs and projects aimed at the residential sector of stratus 1, 2 and 3 may be financed in whole or in part both for implementing small-scale self-generation solutions and improving the energy efficiency by promoting good practices, equipment for the final use of energy, adapting internal installations and architectural remodeling.

The FENOGE Operating Manual, which contains aspects related to sources of financing, destination of resources, organizational structure, methodology for presenting and selecting projects and the execution process, was published recently by means of Resolution MME No. 41407 of 2017.

In February 2018, CREG Resolution No. 030 of 2018 was issued with simplified procedures to authorize the connection of Small Scale Distributed Autogenerators (less than 1 MW), Large Scale Autogenerators up to 5 MW and Distributed Generators (up to 0.1 MW) using Non-Conventional Renewable Energy Sources (NCRE). In the case of resources less than 100 kW, a procedure was defined by means of a registration form with the Distributor, without the need for connection studies which entails very short periods of review of the application (5 days), as well as testing and connection (2 days), which in all cases requires minimum technical conditions in terms of electrical protection and safety.

In March 2018, the Ministry of Mines and Energy issued Decree No. 0570 of 2018, by which the public policy guidelines for the contracting of Long-Term Energy are dictated. The objectives of the Decree are to strengthen the resilience of the generation matrix through risk diversification, promote competition and efficiency in price formation through new and existing projects, mitigate the effects of climate variability and change through the use of available renewable resources, strengthen national energy security and reduce GHG emissions, in accordance with COP 21 commitments. The Ministry of Mines and Energy, CREG, UPME, and other competent entities have a period of 12 months from the entry into force of the Decree to update the current regulations that allow planning, connection, operation, and measurement for the integration of electricity generation projects that are developed from the application of the mechanism.

Giving continuity to the mentioned Decree, the Ministry of Mines and Energy issued Resolutions 40791 and 40795 of August 2018, finalizing the construction cycle of the public policy that will allow to comply with the objectives of strengthening, complementing and diversifying the energy matrix of the country and establishing a historical milestone such as the launching of the first long term electric energy auction in the country. As a fundamental element of the issuance of these resolutions, a long-term energy auction is created that will allow, among others, the greater incorporation of renewable energies into the national energy system.

Through Resolutions 41,307 and 41,314 of December 2018, the Ministry of Mines and Energy officially called for the first auction of electricity for long-term contracting, which took place on February 26, 2019 which seeks to diversify, complement and boost the competitiveness of the energy matrix, making it more resilient to climate variability, contributing to the reduction of carbon dioxide emissions and guaranteeing the country’s energy security.

This process will award 1,183,000 megawatt-hours per year, through long-term average annual energy contracts valid for 12 years. The start date of the obligations of the assigned generation projects will be December 1, 2021.

The auction will only consider power generation projects whose initial date of operation is after December 31, 2017, which will be evaluated based on four criteria: resilience, complementary state of resources, regional energy security and reduction of CO2 emissions.

The Ministry of Mines and Energy will publish the minutes of the contract no later than the first week of January 2019, while the UPME, the entity responsible for the administration of the mechanism, will disclose the specifications and specific conditions for the auction on the same date.

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·In Peru, a target up to 5% has been set as the Non-Conventional Renewable Energy share in the country’s energy system. It is a nonbinding target and the regulatory agency, OSINERGMIN, holds differential quota tenders by technology and limited prices to help reach the goal.

In 2016, the Fourth Tender of Energy Supply with Renewable Energy Resources (“RER” in its Spanish acronym) for the National Interconnected Electricity System (“SEIN” in its Spanish acronym) was carried out. The tender was awarded to thirteen projects consisting of two biomass plants, two solar plants, three wind plants and six hydroelectrical plants, and will add 430.1 MW to the SEIN. The reference date for commercial operation of these RER generation projects of this tender is until 2020. The average tariffs per MWh awarded were: US$ 77 for biomass; US$ 37 for wind; US$ 48 for solar; and US$ 46 for hydro.

·In Argentina, on October 21, 2015, Law No. 27,191 for Renewable Energy was published, replacing Law No. 26,190. 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 mid-objectives of 12%, 16% and 18% for the years ended 2019, 2021, and 2023. The enacted law creates a Fiduciary Fund (“FODER”) to finance works, grant tax benefits for renewable energy projects and establish exemptions for specific taxes and national, provincial and municipality royalties until December 31, 2025. The customers categorized as Large Users (>300 Kw) will comply on an individual basis with the renewable share goals, establishing that the price of contracts will not exceed US$ 113 per MWh, and setting sanctions for those not fulfilling the goals.

On March 30, 2016, Decree No. 531/16 was published and established the following formalities for the implementation of Law No. 27,191 and the modified Law No. 26,190:

·The Ministry of Energy and Mining (“MEyM” in its Spanish acronym) is the regulator authority.

·Generators/traders are allowed to enter into contracts requesting a demand equal to or more than 300 KW or with distribution companies acting on their behalf.

·CAMMESA will call public tenders to supply consumers with a demand of less than 300 KW.

·All CAMMESA’s purchases are guaranteed by the Fiduciary Fund (“FODER”).

·The FODER will be financed with funds from the Treasury and a specific fee will be applied to the demand supplied by CAMMESA.

·The energy goals must be fulfilled with renewable energy generated from power plants within the country.

·To use the tax benefits, it is necessary to have an authorized certificate of inclusion within the renewable energy regime.

The MEyM, CAMMESA and the Executive Committee will be responsible for establishing the methodology for determining fines for the non-compliance of goals, the use of the Fiduciary Fund (FODER) and tender specifications.

MEyM Resolution Nos. 71/2016 and 72/2016, both issued on May 17, 2016, as part of the implementation of Law No. 27,191 and Decree No.531/16, began the process of public tenders for contracts within the Wholesale Electricity Market of renewable energy under the so called “Programa RenovAr — Ronda 1” with a total requirement of 1,000 MW distributed as: Wind: 600 MW; Solar: 300 MW; Biomass: 65 MW; Mini-hydro: 20 MW; and Biogas: 15 MW.

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The tender is structured with a maximum price for technology as established by the government. CAMMESA is the buyer of the energy with prices in US$ per MW (without indexation) and contracts for a 20 -year term.

A total of 123 offers with an aggregate 6,366 MW participated in the tender, of which 105 complied with the specifications (42 wind energy offers, totaling 2,870 MW; 50 solar energy offers, totaling 2,305 MW; 8 biomass and biogas energy offers, totaling 23 MW and 5 micro-hydro offers, totaling 11 MW. On September 30, 2016, after reviewing the economic offers, the results indicated that most of the offers were below the Maximum Tender Price established by the MEyM. The minimum price for wind energy was US$ 49 per MWh and US$ 59 per MWh for solar energy. Finally, the Ronda 1 of the Programa RenovAr awarded 29 projects for a total of 1,142 MW.

Subsequently, a new tender (“Ronda 1.5”) was carried out for Programa RenovAr, which awarded 30 projects with a total of 1,281.5 MW at an average price of US$ 54 per MWh (765.4 MW wind and 516.2 MW solar).

Finally, Programa RenovAr (Ronda 1 and 1.5) awarded 59 projects with a total of 2,423.5 MW at a weighted average price of US$ 57.44 per MWh. All of the Ronda 1 projects already signed their contracts and subsequently the same will be done with the Ronda 1.5 contracts.

On August 17, 2017, by means of MEyM Resolution No. 275-E/2017 The National and International Open Call for Bids was made to interested parties in bidding for contracting, in MEM, electrical energy from renewable sources of generation within the framework of “Programa RenovAr (Ronda 2)”. The idea is to award 1,200 MW (550 MW wind and 450 MW solar). The date for submitting the bids is October 19, 2017, and the award will be made on November 29, 2017.

Subsequently via Resolution No. 473/2017, the qualified, but unsuccessful projects, were invited following the original order of merit until an additional number equivalent to 50% of the original call for bids was filled.

In all, for Ronda 2 of the Programa RenovAr, 88 projects for 2,043 MW were awarded in 18 provinces at an average price of US$51.5 per MWh.

Furthermore, on August 18, 2017, MEyM Resolution 281/2017, stipulating the regime of the Market of Electrical Energy from Renewable Sources was published. Subsequently, various administrative aspects were regulated by means of provision No. 1/18 of the Undersecretariat of Renewable Energy.

In September 2018, the Undersecretary for Renewable Energies presented Round 3 of the Programa RenovAr, known as MiniRen, whose main characteristic is the use of the capacities available in medium voltage networks and the promotion of regional development in Argentina.

The RenovAr MiniRen program offers 400 MW of power throughout Argentina, to be connected to medium voltage networks of 13.2 kV, 33 kV and 66 kV. The maximum allowed power per project is 10 MW, while the minimum is 0.5 MW.

In regards to the contractual part, the awarded projects will sign an electric power supply contract (PPA) with CAMMESA, in the same way as in the previous rounds, and an agreement to adhere to the FODER to guarantee 3 months of invoicing for the contracted projects.

The schedule for Round 3 began in October with the publication of the specifications, and will continue from March 2019 with the period for submitting bids, the process of qualification, award and signing of contracts that will end in July 2019.

On the other hand, from Round 2 a total of 82 projects were signed for 1,969.1 MW out of 88 awarded projects. The Secretariat of Energy of the Ministry of Finance reported that the period for signing contracts for the supply of renewable electricity had ended.

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Limits on integration and concentration

In general, all of the countries have legislation in effect that defends free competition and, together with specific regulations that apply to the electricity market, defines criteria to avoid certain levels of economic concentration and/or abusive market practices.

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.

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, although two criteria have been established for generating activity. 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.

Market for unregulated customers

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	> 3,000 kW or > 500 kW (1)
Colombia	> 100 kW or 55 MWh-month
Peru	> 200 kW (2)

(1)The >500 kW limit applies if energy is purchased from renewable sources, for which the government provides incentives through a discount on tolls.

(2)On July 24, 2016, Supreme Decree No. 018-016-EM established that:

·the demand of customers that can choose between regulated and unregulated markets (those clients with a demand between 200 kW and 2,500 kW) is measured by each point of supply;

·regulated customers whose demand is over 2,500 kW, will remain as regulated customers for one year; and

·customers whose demand at each point of supply is more than 2,500 kW are classified as unregulated customers.

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b)    Tariff Revisions:

General Aspects

In the countries where the Group operates, selling prices charged to clients are based on the purchase price paid to generators plus a component associated with the value added in distribution. Regulators set this value periodically through reviews of distribution tariffs. As a result, distribution is essentially a regulated activity.

Argentina

In Argentina, the first review of Edesur’s tariffs scheduled for 2001 was cancelled by the authorities due to the country’s economic and financial crisis, and tariffs were frozen starting with that year. Edesur’s tariff restructuring started in 2007 with the enforcement of the “Acta Acuerdo,” or Agreement Act. The last tariff adjustment made to date went into effect in 2008 (with a positive effect on the added value distribution, or VAD), when tariffs were adjusted for inflation (applying the cost monitoring mechanism, or MMC, provided for in the Agreement Act).

In November 2012, ENRE passed Resolution No. 347 authorizing a fixed charge to be added on invoices which differs for various categories of customers. This charge will finance infrastructure works and corrective maintenance through a trust (FOCEDE). Additionally, in July 2012, the ENRE appointed an observer in Edesur; the appointment is still in effect, although this does not imply loss of control of the company.

SE Resolution No. 250/13 was published in May 2013 authorizing compensation for Edesur’s debt corresponding to revenues originating from the application of the Program for the Rational Use of Electricity (PUREE) until February 2013, with a credit in its favor from recognition of the MMC for the six-month periods between May 2007 and February 2013. In addition, the SE Resolution No. 250/13 instructed CAMMESA to issue in Edesur’s favor what are termed as Sales Settlements with Unspecified Due Dates for values exceeding the compensation mentioned above, and authorized CAMMESA to receive these settlements as partial payment of Edesur’s debt.

Subsequently, SE Resolution No. 250/13 was supplemented and extended to December 2014 by SE Nos. 6852, 4012, 486 and 1136. The accounting effects of these compensations positively affect the company’s financial results. However, to date, the Comprehensive Tariff Review included in the Renegotiation Agreement Act is still pending in order to adapt revenues to Edesur’s costs and obligations.

On March 11, 2015, the Secretary of Energy issued Resolution No. 32/2015, which among other things: (i) approved a transitory revenue increase for Edesur as of February 1, 2015 to pay for the energy acquired from the electricity market, salaries and assets and services supply; such increase, on account of the Integral Tariff Review (“RTI” in its Spanish acronym), arose from the difference between a theoretical tariff framework and the tariff framework in force for each category of user, according to the calculations of the Ente Nacional Regulador de la Electricidad (“ENRE”), and will not be converted into a tariff, but instead will be satisfied with transfers from CAMMESA to Edesur with Argentine National Government funds; (ii) provided that as of February 1, 2015, the funds from the PUREE will be considered part of Edesur revenues, also on account of the RTI; (iii) confirmed the procedure for the Cost Monitoring Mechanism (“MMC”) through January 31, 2015; and (iv) instructed CAMMESA to issue LVFVD in amounts determined by ENRE as a result of higher salary costs for Edesur due to the application of Resolution No. 836/2014 of the Secretary of Labor. In addition, Resolution No. 32/2015 allowed payment plans to be defined for the payment of remaining balances with the Wholesale Electricity Market (“MEM”) and instructed ENRE to initiate actions prior to the RTI process. As a consequence of the above, during the year ended December 31, 2015, revenues of US$ 538 million were recognized, which are presented in the statement of comprehensive income as follows: for point (i), US$ 405 million under “Other operating income” and ThUS$ 984 under “Financial income”; for point (ii), US$ 51,889 million under “Revenues” (Energy Sales); for point (iii) US$ 17 million  under “Other operating income”; and for point (iv), US$ 62 million under “Other operating income”.

Although SE Resolution No. 32/2015 represented the first step towards an improvement in the economic situation of Edesur, it anticipates that investments will still be financed with mutual loans with CAMMESA. Mechanisms for the

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payment of remaining balances with MEM are still pending, as well as, revenue updates from increases in operational costs. On the other hand, tariffs have remained frozen since 2008.

On December 16, 2015, the National Executive Branch enacted Decree No. 134/2015, which declared a state of emergency for the National Electricity sector through December 31, 2017, and instructed the newly created Ministry of Energy and Mining (“MEyM” in its Spanish acronym) to prepare and implement a national program to improve the quality and safety of the electrical supply and guarantee that it is provided under the best technical and economic conditions.

In following with those instructions, on January 27, 2016, MEyM Resolution No. 6/2016 was published, which approved the Summer Quarterly Re-Scheduling (February 2016 – April 2017) tariffs for the MEM that are determined based on the “Procedures to Schedule the Operations, Dispatch of Generation Units and Pricing”. The tariffs consider a reduction in tariff subsidies and differentiate pricing schemes for those residential customers saving energy, and a new social tariff. This resolution is a significant step in the process of reconstructing the payment chain in the electric market.

In addition, on January 28, 2016, MEyM Resolution No. 7 applicable specifically to Edesur S.A. and Edenor S.A. was published, instructing the ENRE to adjust, through the RTI, the value added from distribution (“VAD”) in the tariff tables for energy distribution companies, by using the Transition Tariff Regime. MEyM Resolution No. 7 further instructed that a social tariff be applied instead of PUREE to the population of consumers falling under the criteria defined by the resolution. Finally, the resolution instructed that all necessary procedures be carried out to apply the RTI to energy distribution companies before December 31, 2016.

On January 29, 2016, ENRE issued Resolution Nos. 1 and 2 to return to Law No. 24,065 and normalize the electricity sector that was claimed by Edesur’s representative’s multiple times. Resolution No. 1/2016 established the new tariff table to be applied to each type of customer as of February 1, 2016 and in accordance with the guidelines of MEyM Resolution No. 7/2016, as well as, the new rules on supplying for streamlining with monthly invoicing. Resolution No. 2 terminated FOCEDE, which was created on January 31, 2012, and created a new mechanism for funds collected through Resolution No. 347/12 that are now deposited to a bank account authorized by the Argentine Central Bank instead of a fiduciary fund.

On April 5, 2016, the Secretary of Energy issued Resolution Nos. 54 and 55. Resolution No. 54 approved the tender specifications expected to be granted on May 27, 2016, for contracting an advisor for the RTI of Edesur. Resolution No. 55 approved the RTI program for 2016, which defined the criteria and methodology that Edesur must follow to perform its tariff studies. To prepare tariff proposals, the ENRE defined target quality parameters and the managing criteria to be used by Edesur, as well as the internal rate of return to be used in the calculation of their distribution cost.

On August 8, 2016, as part of the tariff renegotiation process, ENRE issued Resolution No. 463/2016, establishing the quality parameters for technical services and the value of costs for non-supplied energy required to complete the RTI.

Likewise, on August 29, 2016, ENRE issued Resolution No. 492/2016, establishing the quality parameters for commercial services and technical products. This resolution contains economic parameters for compliance with terms and time reductions for re-establishing energy supplies.

On August 30, 2016, ENRE stated that the Internal Rate of Return would be 12.46% pre-tax and 8.10% after tax.

Edesur submitted reports requested under ENRE Resolution No. 55/2016. On September 1, 2016, it submitted the reports “Red Ideal” and “Plan de Inversiones Plurianuales”, and on September 6, 2016, it submitted reports related to the basis and criteria for (i) operating costs; (ii) requirements for revenues and tariff calculations; (iii) tariff structure and transferring of costs to wholesale consumers; (iv) the mechanism for updating its own distribution costs; and (v) results and its economic-financial model.

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On September 28, 2016, ENRE through Resolution No. 522/2016, summoned a public audience for a hearing on October 28, 2016, to notify and allow comments on tariff proposals presented by distribution companies for the next five-year period; this is part of the Comprehensive Tariff Review Process and prior to the definition of tariffs applicable by the distributors in such five-year period.

On December 30, 2016, ENRE issued Resolution No. 626, which approved the document titled “Final Resolution Public Audience” (Resolución Final Audiencia Pública, in Spanish) prior to defining the tariffs to be applied. Likewise, it transferred to the MINEM’s Undersecretary for Coordination of Tariff Policy (Subsecretaría de Coordinación de Política Tarifaria in Spanish) the topics discussed at the hearing that fall within the purview of that regulatory body.

The resolutions that contain the new Tariff Tables and Tariff Regime were issued in February 2017.

On February 1, 2017, ENRE issued Resolution No. 64/2017, which finalized the RTI and that as a result of it establishes the annual remuneration recognized to Edesur S.A. in the sum of Arg$14,539,836,941 (ThUS$944,448).

In connection with the new tariff structure and charges, MEyM instructed ENRE to limit the VAD increase as a result of the RTI process to be applied as of February 1, 2017 to 42% as compared to the VAD currently in effect. The application of the remaining VAD increase would be made in two stages: the first stage in November 2017 and the second stage in February 2018.

In addition, it instructed ENRE to compensate Edesur S.A. and Edenor S.A. for the difference in VAD as a result of the gradual application of the tariff increases in the RTI, in 48 installments beginning on February 1, 2018, which will be incorporated to the VAD determined on that date.

The new regulation also sets the method for updating the revenues of distribution companies based on fluctuations in economic prices, and all other matters related to service quality and supply requirements.

Upon setting the distribution tariff tables, including the instruction of the MEyM, and the provisions of SEE Resolution No. 20/2017 on seasonal prices from invoicing effective February 1, 2017, the temporary tariff stage of Edesur and the Agreement Act were finalized. Consequently, Edesur will be ruled by the terms stated in its concession contract.

In compliance with the requirements of Article 29 of ENRE Resolution No. 64/17 (Physical follow-up of the works plan), on March 20, Edesur sent a note Ratifying the Investment Plan reported at the proper time for the RTI (in physical terms). It also specified the possibility of adapting it in the future in the event of any changes in the demand. And the need for a prompt resolution of the Liabilities and Assets in order to expedite access to financing for compliance purposes.

Likewise, according to the Law of Administrative Procedures, on March 20, 2017, Edesur S.A. formally filed an appeal with ENRE containing its questioning of ENRE Resolution 64/17, which basically were focused on the treatment of easements, some optimization criteria in defining the capital base, the treatment for recognizing certain tax burdens and objections to the quality regime. We stress the fact that whether the observations and petitions for clarification are accepted or rejected by the regulator will not significantly alter the RTI.

On July 26, 2017, ENRE issued its Resolution 329/2017, which defines the procedure for invoicing the deferred income established in ENRE Resolution 64/2017 (Article 4), specifying that  “…The amount owed corresponding to each rate category will be the sum of the accrued monthly values recognized per rate category…”; establishing the certainty of collection when recalculating, each year, the unrecovered amount owed, deducting the amount actually received from the initial amount owed, and recalculating the remaining installments so as to cover the rest of the amount owed; and the mechanism for updating it, specifying that “…Charges so calculated will be adjusted, as components of the CPD, as stipulated in the ‘trigger clause’ and in the ‘Adjustment Mechanism’ …”

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On May 17, 2017, Law 27351 on ELECTRICITY-DEPENDENTS was ratified; it stipulates the gratuity and continuity of the electricity supply, together with the priority of attention, for those people who, due to health problems, require a constant supply of electricity at adequate voltage levels to be able to provide power to the medical equipment prescribed by a registered doctor and which is necessary to prevent risks to the person’s health or life. In this context, on July 26, 2017, by means of ENRE Resolution 292, that regulatory agency stipulated the gratuity of the service and the cost of the connection for this category of users of Edenor and Edesur. Along these same lines, on September 25, 2017, the Ministry of Health, via Resolution 1538-E, created the “Record of Electricity-dependents for Health Reasons”. With the regulations of the operating questions in order to guarantee the continuity of the supply still to be determined at this date, the compensation for the distribution companies (Law 27351 ARTICLE 11. The Executive will designate the authority to apply this law and will allocate the necessary budget items to comply with its purposes), and the limits of liability of the players involved.

On November 1, 2017, ENRE published Resolution 525 partially sustaining the Appeal for Reconsideration of Judgment filed by Edesur against ENRE 64/2017, accepting its points about the treatment of easements and requesting the company to remit its annual easement regularization plan to be implemented in the period 2017/2021 within sixty days of this notification, and likewise with regard to recognition of the CAMMESA expenses, rates and others that must be present in any future ex-post adjustments and minor modifications to the quality regime and other recognitions.

In an unprecedented event, on October 27, 2017, ENRE, in compliance with resolution of the Ministry of Energy and Mines No. 403 of October 26, 2017, by means of resolutions 526 and 527, summoned a Public Hearing on November 17, 2017. It would address in first place the new reference prices for power and energy and the references prices for power and stabilized reference prices for energy for distribution companies in each one’s equivalent node, for the Summer Seasonal Period of 2017-2018; electrical energy savings incentives plan; welfare rate and distribution methodology, between the requirement of the MEM, the cost represented by the remuneration for transporting extra high voltage electrical energy and between the requirement of the respective region, and that corresponding to transportation by trunk line distribution. And, in second place, report the impact that the measures that the Ministry of Energy and Mines will have to implement as a result of the Public Hearing summoned by that Ministry via MEyM Resolution 403/2017 will have on the bills of the users of the distribution companies, with regard to the prices of the MEM, the withdrawal of electrical energy transportation subsidies and the criteria for distributing the remuneration of the Transportation Companies among the users of the transportation that this Agency resolved when the Comprehensive Rate Review of Electrical Energy Transportation was performed.

As a result of this, on December 1, 2017, via Resolution 602, ENRE resolved to approve the new values of the Own Distribution Cost of Edesur, by applying the mechanisms provided for in the RTI. At the same time, it issued the Rate Tables reflecting the Seasonal Prices (generation and transportation) contained in the resolution of Secretariat of Electrical Energy No. 1091 of 2017, as well as the new Welfare Rate subsidy tables and bonus for savings in consumption for residential users. As a continuation of the same event, on January 31, 2018, the ENRE approved the new values effective as of February 1, 2018. These tables include a new reduction of wholesale price subsidies, taking it up to a value of 90% of the seasonal price operated in 2017. In addition, they maintain the subsidies to the social rate and a bonus of the stimulus plan, for reduction of the smaller power consumption.

Regarding the Distribution Added Value component, the third installment of the Distribution Cost Increase corresponding to the RTI, the proportional part of the deferred revenue, the Cost Monitoring Mechanism was included in this rate schedule corresponding to the period and the application of the Efficiency Factor. Reflecting, the latter, the compliance by Edesur of the Investment Plan committed in the RTI whenever the expected value was reached.

In this way, the Edesur rate reaches Ar$2.2828 per kWh without taxes as of February 1, 2018. In parallel and in order to resume the normal structural conditions, the Argentine National Government decided not to extend the validity of the Electric Emergency Law (valid until December 31, 2017) and the Economic Emergency (effective until January 6, 2018).

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On the other hand, on April 17, 2017, the MEyM issued a note which instructs the Secretariat of Electric Energy (SEE) to determine within 120 working days if there are pending obligations of the Agreement and the treatment to be granted, and to issue a final resolution report during the following 30 days. For these purposes, the SEE requested that Edesur, ENRE and CAMMESA provide the pertinent information.

During December 2017, the MEyM presented its proposal and criteria to consider the treatment of regulatory liabilities. In this proposal, the MEyM clarifies that it accepts to cancel the commercial debt for the purchase of energy from CAMMESA, the fines destined for the State and the difference in the penalties for adjustments applied according to the interpretation of the ENRE. While sanctions for users are applied to additional investments with funds from the State and the debt with CAMMESA for mutual loans and pre-existing sanctions to the Agreement for users, the company should pay them.

With respect to the procedure initiated on December 28, 2017, the MEyM issued another note by which communicated to CAMMESA that the Argentine government is responsible of the obligations that Edesur maintains with CAMMESA for the purchase of electric power in the MEM. This procedure is in accordance to article 15 of Law No. 27,341 by which Edesur must comply with the determination that the MEyM will make regarding the outstanding obligations in relation to the Act Agreement and prior withdrawal of any administrative, arbitral or judicial claim against the Argentine government.

On December 29, 2017, Edesur agreed to the terms of this note.

Likewise, the Company must agree to the determination that the MINEM will make of the obligations pending compliance with the Agreement Act and of the conditions and modalities contemplated for the compensation of such obligations and of the obligations mentioned in this paragraph, prior waiver of any administrative, arbitral or judicial claim against the National State related to the application of the Agreement Act. In the absence of such agreement, the assignment of debt shall be null and void.

To date, drafts have been exchanged with the MEyM, obtaining improvements in terms of terms and rates, leaving elements for final consideration. As of the date of issuance of these financial statements, said process has not been completed.

On March 7, 2018, through Decree PEN 187/18, the National Executive Branch published the new organizational chart of the MEyM. And, subsequently, by means of resolution 64/2018 of the MEyM, the functions of the Ministry of Electricity were transferred to the new Sub-Secretary of Electric Power.

Continuing with what was previously reported on April 20, 2018, the Agreement for the solution of the Regulatory Assets and Liabilities was initialized under the terms previously negotiated. The next steps are the submittal by the Authorities to the Procuration and SIGEN for validation.

On April 25, 2018, the ENRE issued resolution No. 119 which, making use of the figure of “Extraordinary Affectation of the Rendering of the Service” established in the RTI, instructed Edesur to pay compensation to residential users (T1R tariff) for interruptions between March 1 and 6, 2017 (6 days) and between July 14 and 20, 2017 (7 days), whose interruptions were of a duration greater than or equal to 20 hours. This compensation amounted to 49 million pesos.

During May 2018, the Law on Reasonability in Public Service Rates was debated, seeking to bring them back to the value they had in November 2017 and that their update is not greater than the salary variation. The bill was approved by the Chambers of Deputies and Senators and then vetoed on June 1, 2018 (published in Official Gazette) by President Macri.

Also on May 31, 2018, ENRE issued Resolution 0170 which resolves to approve the sanctioning regime for departing from the Investment Plan presented by the distribution companies at the time of the RTI. This resolution is being appealed in view of the fact that it introduces a modification to the current Concession Contract.

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Finally, on June 16, 2018, the national government announced the replacement of the Ministers of Production and Energy. Mr. Dante Sica was appointed as Minister of Production and Mining and Mr. Javier Iguacel as Minister of Energy. Mr. Iguacel was previously to be in charge of the National Roads Agency. He is an oil engineer who graduated from the Instituto Tecnológico de Buenos Aires (ITBA) with a vast experience in the oil industry.

These changes are added to the departure on June 14, 2018 of the president of the Central Bank Mr. Federico Sturzenegger, who was replaced by Mr. Luis Caputo, and the elimination of the Ministry of Finance by incorporating it into the Treasury Department.

On July 19, 2018, ENRE issued Resolution 0199, which elevates the quality control of the current Commune/Districts to MT Feeder. It penalizes deviations of 2, 3 or more times over the theoretical indicators that would correspond to each feeder to comply with the objective quality level of the RTI. It is applicable when 100 or more customers are affected, for values of 300 kWh and 600 kWh per user. Valid from Semester 45 (September 2018-February 2019). To date, the new regulations have been analyzed jointly with the legal and technical areas and an appeal has been filed.

On July 30, 2018, within the framework of the Ministry of Energy’s intention to gradually increase tariffs, a commitment was signed between MINE and Edesur whereby Edesur will receive 50% of the increase corresponding to the adjustment mechanism foreseen in the tariff as of August 1, receiving the remaining 50% in 6 installments adjusted as of February 1, 2018 and maintaining the Agreed Investment Plan in the RTI.  The same commitment was also signed by Edenor simultaneously.

On the other hand, MINE formally committed itself to promote the Approval (by the Attorney General’s Office and SIGEN) and the subsequent signing of the Agreement begun on April 20 for the Solution to the Regulatory Assets and Liabilities corresponding to the Contractual Transition period. It also undertook to move forward with the signing of a new Addendum to the Framework Agreement (collective supplies from underprivileged neighborhoods) in accordance with the proposals made by Edesur.

In addition, verbally, it undertook to resume negotiations for the approval of the Resolution associated with the Remuneration of the Sub-transmission provided by Edesur (PAFTT) and pending in the RTI.

Under the agreed commitment, on August 1, 2018, 50% (7.925%) of the increase corresponding to the August 2018 application of the MMC to Distribution Added Value was applied. Together with this increase continued the intention of elimination of subsidies to the wholesale price of energy, which had been delayed by the devaluation of June and July. With an increase of almost 50%, this led to the price of the Distributors’ Large Users (demand greater than 300 kW-months) at approximately Ar$2,700 per MWh and the rest of the distributors’ demand at approixmately Ar$1,400 per MWh. In addition the ex-post adjustments were applied corresponding to the reimbursement of the AT Transportation costs of the previous Tariff Schedule (modification of regulations) and to the amounts recognized as compensation for the Debit/Credit tax and the Safety and Hygiene Rates.

On the other hand, MINE used this occasion to modify the TOPES to the Social Rate (maximum % of invoicing with respect to a normal residential customer), thus reducing the subsidies to this rate and the distortions caused in this concept to Distributors that are still pending solution and analysis by ENRE. Regardless of which, the resolution was appealed on August 13, 2018.

On August 23, 2018, the ENRE, through Resolution 222, rejected the appeal filed by Edesur against the sanctioning regime for deviating from the Investment Plan presented in the RTI and published on May 31, 2018. In turn, on September 5, 2018, Edesur filed a new Subsidy Appeal against said resolution.

As for the Agreement for the solution of the Regulatory Assets and Liabilities, beyond the delay in the deadlines, the administrative advances for the definitive signature of the agreement continue to be fulfilled. The Undersecretary of Electric Energy having requested, in the last week of September 2018, both ENRE and the companies involved, the necessary information to be submitted to the National Attorney General’s Office and SIGEN.

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Also, on September 18, 2018, the 2019 Budget Bill entered Congress with a primary deficit of zero foreseen for that year., and on September 25, 2018, the economist Mr. Guido Sandleris was appointed as president of the Central Bank, replacing Mr. Luis Caputo.

On the other hand, last November 1, 2018, the National Executive Power published Decree 986/2018 which seeks to achieve the installation of a total of 1,000 MW of power within 12 years. In order to obtain the connection authorization, the user must comply with a series of requirements established by the Application Authority, which will also establish the requirements for the technical and safety evaluation that the Distributor must perform on the distribution network, the distributed generation equipment and related devices.

Returning to the scope of electrical distribution, on December 10, ENRE published Resolution 318/2018 in which it approved the methodology and updated the values of remuneration for the sub-transmission service (PAFTT) offered among the distributors Edesur, Edenor and Edelap, effective as of March 6, 2017. This was pending in the Comprehensive Tariff Review. This mechanism makes it possible to remunerate operation and maintenance costs, as well as the recognition of the corresponding losses and the transfer to the tariff of the costs incurred by Edesur for this concept. The net accumulated to date represents for Edesur income of approximately 60 million Argentine pesos (approximatelyThUS$1.5).

Additionally, by means of Resolution No. 366 of the Secretariat of Energy of December 27, 2018, announced  that the new supply cost is approximately 68 US$/MWh, which is 13% lower than the one established in August 2018 due to the improvements in the gas contracts obtained by CAMMESA and the decrease in the international price of oil. On the other hand, the future Seasonal Prices to be transferred to the end users’ tariff continue with   subsidy reductions foreseen by the authorities going from around 30% in February to 15% subsidy in August 2019. However, these prices translated into local currency mean an initial increase of 26% in February 2019 and subsequent increases of 6% in May and August 2019.

It is the Government’s intention to report all tariff changes during the month of January in order to prevent the issue from seeping into the electoral campaign for the October presidential election.

For Edesur, increases in VAD are expected to be granted in March and December 2019, similar to what happened in 2017 (also an election year). As in this opportunity all deferrals will be recognized and updated to the date of application.

Additionally, on January 7, 2019, through Decree No. 28 of the National Executive Power, Mr. Gustavo Sebastián Lopetegui was appointed official in the position of Minister of Energy as a result of the resignation of Mr. Javier Iguacel, subsequent to the press conference in which the expected tariff increases were communicated.

Brazil

In Brazil, there are three types of tariff adjustments: i) Ordinary Tariff Reviews (“RTO”) which are conducted periodically in accordance with the provisions in the concession contracts (in Enel Distribución Ceará every 4 years and in Enel Distribución Río every 5 years); (ii) Annual Adjustments (“IRT”) since Brazil, unlike other countries, does not automatically index its tariffs to inflation; and (iii) Extraordinary Reviews (“RTE”) when important events have occurred that may affect the financial situation of the distributors.

In September 2012, the government approved Temporary Measure 579, one purpose of which was to reduce certain electricity tariff taxes and special charges paid by the final user, which will be paid in the future with the state budget. In January 2013, the Temporary Measure became Law 12,783, giving rise to Extraordinary Tariff Reviews that resulted in tariffs dropping an average of 18% throughout the country. This reduction affected Enel Distribución Río S.A. and Enel Distribución Ceará S.A. from the end of January 2012 to April 2013 (when the respective annual readjustments went into effect).

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In April 2014, ANEEL finalized its periodic tariff review of Enel Distribución Río S.A. for the 2014-2019 period with retrospective effect on March 15, 2014.

On March 1, 2015, through Resolution No. 1858/2015, Enel Distribución Ceará S.A. had an extraordinary review when its rate increased by 10.28% for purposes of face the increases in charges (Energy Development Account - CDE) and the costs of energy purchase.

The last periodic tariff review of Enel Distribución Ceará S.A. was made in 2015 (the first of our distribution companies using the new fourth tariff cycle technology) for the 2015 – 2019 period, effective beginning on April 22, 2015. Such review was provisional as the methodologies of tariff review were not approved in time. The additional average increase in tariffs was 11.69% as approved under Resolution No. 1882/2015.

Enel Distribución Ceará S.A. will begin to use the fourth tariff cycle methodology in its tariff review in March 2019; however, in March 2015 it has a final average increase of 37.3% (Resolution No. 1.869/2015) essentially due to increases in Section A.

Finally, still in the scope of the fourth tariff cycle, on November 17, 2015, Chapter 2.3 of the Tariff Review Procedures related to the determination of the Basis for Remuneration was approved, under which a Database of Referential Prices was created to value certain variables of the basis for remuneration in the upcoming tariff reviews.

ANEEL approved the results of the first periodic review of Enel Cien S.A. (formerly named CIEN S.A.). Beginning on July 1, 2015, the tariffs decreased 7.49%, as approved by Resolution No. 1.902/2015.

On March 8, 2016, ANEEL approved the tariff adjustment of Enel Distribución Rio (formerly Ampla). Beginning on March 15, 2016, the tariffs were adjusted by an average of 7.38% for all of its customers (7.15% for low voltage consumers and 7.89% for high voltage consumers).

ANEEL, through Resolution No. 2.061 dated April 12, 2016, approved the final results of the fourth periodic tariff review (“RTP”) of Enel Distribución Ceará S.A., which were included in the 2016 adjustments.

ANEEL, through Resolution No. 2.065 dated April 19, 2016, approved the energy tariffs of Enel Distribución Ceará S.A. as a result of the 2016 tariff adjustments. The average increase in tariffs to consumers was 12.97%.

Colombia

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”). Currently, these charges include the new replacement value of all operational assets, the Administration, Operation and Maintenance (“AOM”) and non-electrical assets used in the distribution business.

In Colombia, the current distribution charges for Codensa were published by CREG in October 2009.

The current review of regulated distribution charges began in 2013 with the publication of the assumptions for the remuneration methodology proposed by CREG Resolution No. 43 dated 2013. These assumptions were complemented by the development of the Purposes and Guidelines for Compensation of the Distribution Activity for the period 2015-2019 in CREG Resolution No. 79 dated 2014.

In February 2015, CREG issued a proposal for Resolution No. 179 of 2014, which proposed a methodology for remunerating distribution activity. The methodology is based on a regulated revenue scheme. Annual revenues are determined using a Regulated Net Assets Basis (“BRA”) and a rate of return (to be defined in separate resolution). Also, it included an annual revenue for incentives to investments and expenditures efficiency and quality improvements.

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Additionally, CREG issued Resolution No. 95 dated 2015, which defined a method for calculating the regulated remuneration tariff (“WACC”) for electricity transmission and distribution, as well as for natural gas transportation and distribution.

In February 2018, CREG published Resolution No. 015 of 2018, which definitively decides on the Distribution Remuneration Methodology for the new tariff period, which determines the remuneration over the existing asset base, the presentation of investment plans, the remuneration of operating and maintenance expenses and defines ways to decrease losses and service quality.

Subsequently, as a result of the comments sent by the agents in July 2018, CREG Resolution No. 085 of 2018 was issued by which some provisions of CREG Resolution No. 015 are clarified and corrected. It is expected that by 2019, according to the indicative agenda of the CREG, the new charges that were requested from the regulator in accordance with the aforementioned methodology will be approved.

In September, CREG published Resolution No. 114 of 2018, by which it determined the general principles and conditions that must be met by the mechanisms for the marketing of electric energy in order for its prices to be recognized in the component of costs of energy purchases from the regulated user.

Peru

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 in 2015 by Legislative Decree 1221.

In November 2017, the Terms of Reference for the cost studies that distribution companies submit to the regulator in order to begin the process of establishing the VAD for the period 2018-2022 were approved. In this regard, during 2018, the regulator reviewed the proposed cost studies, made observations, and the distribution companies supported technically their proposals.

Throughout 2018, the process of determining the VAD for Enel Distribución for the period 2018-2022 was carried out. At the end of this tariff process, in general, the annual revenues that the company received before the beginning of the process, which corresponded to the tariff period 2013-2017, are maintained.

It should be noted that the Peruvian regulation follows the theory of the efficient model company, so that in each regulatory 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). Prior to the reform approved by Law Decree No. 1221, the model company was set by typical distribution sectors, which in practice meant grouping the companies that in some cases had different characteristics; while as of this regulatory period, the efficient model company is built individually for each distributor with more than 50,000 clients.

6.    NON-CURRENT ASSETS OR DISPOSAL GROUPS HELD FOR SALE OR HELD FOR DISTRIBUTION TO OWNERS AND DISCONTINUED OPERATIONS

6.1   Corporate Reorganization

I. Background

On April 28, 2015, the Company informed the SVS (now CMF) through a significant event notice, that its Board of Directors decided by unanimous vote to initiate an analysis of a corporate reorganization (the “reorganization”) aimed at separating the activities of generation and distribution of electricity in Chile from activities outside of Chile. The objective was to resolve certain duplications and redundancies arising from Enersis S.A.’s complex corporate structure and generate value for all its shareholders, while maintaining its inclusion in the Enel S.p.A. group.

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The Spin-Off stage of the Reorganization process was carried out as follows:

The Reorganization began with the spin-offs by Enersis S.A. (“Enersis”) and its subsidiaries, Empresa Nacional de Electricidad S.A. (“Endesa Chile”) and Chilectra S.A. (“Chilectra”).

Each of Endesa Chile and Chilectra effected spin-offs of their non-Chilean businesses and related assets and liabilities, resulting in the formation of Chilectra Américas S.A. (“Chilectra Américas”) as a separate new company from Chilectra and the formation of Endesa Américas S.A. (“Endesa Américas”) as a separate new company from Endesa Chile, which were allocated the equity interests and related assets and liabilities of Chilectra’s and Endesa Chile’s businesses outside of Chile, respectively. After the spin-offs, the continuing companies, Chilectra and Endesa Chile, retained the equity interests and related assets and liabilities of Chilectra’s and Endesa Chile’s businesses in Chile, respectively.

Following the Endesa Chile and Chilectra spin-offs, Enersis effected a spin-off of its Chilean businesses and related assets and liabilities, resulting in the formation of Enersis Chile S.A. (“Enersis Chile”) as a separate new company from Enersis, which was allocated the equity interests and related assets and liabilities of Enersis’ businesses in Chile, including the equity interests in each of Chilectra and Endesa Chile (after the spin-offs of these entities as discussed above). After the spin-off, the continuing company, Enersis, was renamed “Enersis Américas S.A.” and retained the equity interests and related assets and liabilities of Enersis’ businesses outside of Chile, including the businesses, assets and liabilities held by each of the new companies, Chilectra Américas and Endesa Américas that were created as a result of the spin-offs by Chilectra and Endesa Chile.

On March 1, 2016, upon having satisfied all conditions precedent, including a capital decrease and modifications to the by-laws, the separation of the Chilean and non-Chilean businesses of Enersis, Endesa Chile and Chilectra became effective. Consequently, the new company Enersis Chile became the holding entity of the businesses carried out by Endesa Chile and Chilectra, and the surviving company Enersis Américas S.A. (“Enersis Américas”) became the holding entity of the non-Chilean businesses carried out by Endesa Américas and Chilectra Américas.

On October 4, 2016, the extraordinary shareholders’ meetings of Enersis Chile, Endesa Chile and Chilectra approved the change of name of these companies to Enel Chile S.A., Enel Generación Chile S.A. and Enel Distribución Chile S.A., respectively. The change of name finally took place on October 18, 2016, through the modification of the bylaws of each of these companies.

The Merger stage of the Reorganization process was carried out as follows:

On September 28, 2016, the respective shareholders of Enersis Américas, Endesa Américas and Chilectra Américas met, voted and approved by more than two-thirds of the outstanding voting shares of each company, the merger of Endesa Américas and Chilectra Américas with and into Enersis Américas, with Enersis Américas continuing as the surviving company under the new name “Enel Américas S.A.” (the “Merger”). On December 1, 2016, the Merger was completed, and Enersis Américas (the “Surviving Company”) absorbed Endesa Américas and Chilectra Américas by incorporation, each of which was then dissolved without liquidation, and the Surviving Company assumed all their rights and obligations.

Enel Américas S.A. shares are publicly traded and listed in Chile on the Chilean Stock Exchanges and its ADSs are traded on the NYSE. In the Merger, the shares and ADSs of Endesa Américas and the shares of Chilectra Américas were converted into shares and ADSs of Enel Américas, as applicable, and Endesa Américas and Chilectra Américas shares ceased trading on the Chilean Stock Exchanges, and Endesa Américas ADSs ceased trading on the NYSE.

For more detailed information on the merger stage of the corporate restructuring process and its effects on the issued capital and other equity items, refer to Note 27.

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II. Accounting Aspects

As of December 31, 2015, upon compliance with the criteria in IFRS 5 Non-Current Assets Held for Sale and Discontinued Operations, the following accounting treatment was applied:

i. Assets and liabilities

All assets and liabilities related to the generation and distribution businesses in Chile were classified as non-current assets or disposal groups held for distribution to owners and as liabilities associated with disposal groups held for distribution to owners, in accordance with the criteria described in Note 4.k.

ii. Accumulated Other Comprehensive Income in Net Equity

The accumulated other comprehensive income balance related to assets and liabilities held for distribution to owners were the following:

Reserves originated from	03-01-2016 ThUS$		01-01-2016 ThUS$
Exchange differences on translation	(17,187	)	19,155
Cash flow hedges	190,388		(203,776	)
Gains on remeasuring available-for-sale financial instruments	(25	)	25
Other miscellaneous reserves	934		13,082
Total	174,110		(171,514	)

iii. Revenue and expenses

All revenues and expenses related to the generation and distribution businesses in Chile recognized until the effective date of the spin-off of the Company were classified as discontinued operations and presented under the caption “Income after tax from discontinued operations” in the consolidated statement of comprehensive income.

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The following table sets forth the breakdown by nature of the line item “Income after tax from discontinued operations” as of February 29, 2016:

Statement of Income	02-29-2016 ThUS$
Revenues	595,706
Other operating income	3,788
Total Revenue and Other Operating Income	599,494
Raw materials and consumables used	(350,008	)
Contribution Margin	249,486
Other work performed by the entity and capitalized	4,980
Employee benefits expense	(23,808	)
Depreciation and amortization expense	—
Reversal of impairment loss (impairment losses) recognized in profit or loss	(1,433	)
Other expenses	(24,536	)
Operating income	204,689
Other gains	—
Financial income	3,791
Financial costs	(12,743	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	1,913
Foreign currency exchange differences	(31	)
Gains from indexed assets and liabilities	393
Income before taxes	198,012
Income tax expense, discontinued operations	(27,749	)
NET INCOME FROM DISCONTINUED OPERATIONS	170,263

Due to classification of generation and distribution of energy activities in Chile as discontinued operations, those lines of business are not included in Note 35 “Information by segment.”

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The following table sets forth the breakdown by nature of total comprehensive income from discontinued operations as of February 29, 2016, which are part of the Consolidated Comprehensive Income by Nature for the period ended March 30, 2016:

Statement of Comprehensive Income	02-29-2016 ThUS$
Net income from discontinued operations	170,263
Components of other comprehensive that will not be reclassified subsequently to profit or loss, net of taxes
Actuarial gains (losses) from defined benefit plans	—
Components of other comprehensive that will be reclassified subsequently to profit or loss, net of taxes
Foreign currency translation gains (losses), net of tax	(2,773	)
Gains (losses) from available-for-sale financial assets, net of tax	—
Share of other comprehensive income from associates and joint venture accounted for using the equity method, net of taxes	(20,441	)
Gains (losses) from cash flow hedge, net of taxes	18,712
Total Other Comprehensive Income from Discontinued Operations	(4,502	)
TOTAL COMPREHENSIVE INCOME FROM DISCONTINUED OPERATIONS	165,761
Comprehensive income attributable to:
Shareholders of Enel Américas	112,481
Non-controlling interests	53,280
TOTAL COMPREHENSIVE INCOME FROM DISCONTINUED OPERATIONS	165,761

iv. Cash flows

The following table sets for the net cash flows from operating, investing and financing activities attributable to discontinued operations as of February 29, 2016:

Statement of cash flows	02-29-2016 ThUS$
Net cash flows from (used in) operating activities	224,787
Net cash flows from (used in) investing activities	(68,237	)
Net cash flows from (used in) financing activities	(130,432	)
Net increase (decrease) in cash and cash equivalents before effect of Exchange rate changes	26,118
Effect of exchange rate changes on cash and cash equivalents	2,701
Net increase (decrease) in cash and cash equivalents	28,819
Cash and cash equivalents at beginning of period	203,140
Cash and cash equivalents at end of period	231,959

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6.2 Operation Central Rio Negro (CODENSA).

In October 2018, Codensa’s Board of Directors approved the start of the sale process of the Small Hydroelectric Power Plant PCH Rio Negro (the “Río Negro SHP”).

The Rio Negro SHP was received as a result of the merger with Empresa de Energía de Cundinamarca, or EEC, in 2016. Considering that Codensa was constituted after 1992, the restriction of vertical integration is applicable and therefore it cannot operate or commercially represent any generation asset. To date, the sale process has begun with the advice of an investment bank, Bancolombia, based on a schedule that finalizes  the sale in 2019.

Taking into account the sale process and the provisions of IFRS 5 Non-Current Assets Held for Sale and Discontinued Operations prior to classification as a non-current asset held for sale, the Rio Negro SHP has been recorded at fair value; the foregoing implied recognizing an impairment loss of ThUS$5,234 (see Note 31), which has been determined in accordance with the valuation made.

The non-current assets and liabilities held for sale as of December 31, 2018 are presented below:

	12/31/2018
	ThUS$
Property, plant and equipment	5,825
TOTAL NON-CURRENT ASSETS	5,825
Other non-current non-financial liabilities	3,835
TOTAL NON-CURRENT LIABILITIES	3,835

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7.   BUSINESS COMBINATION

7.1.ACQUISITION OF ENEL DISTRIBUCION GOÍAS (FORMERLY CELG DISTRIBUIÇÃO S.A.)

On February 14, 2017, the Company’s subsidiary Enel Brasil S.A. obtained the relevant authorizations from the antitrust authority, Conselho Administrativo de Defensa Econômica (“CADE”), and the sectoral regulator, Agência antimonopólica de Energía Eléctrica (ANEEL), and, consequently, it has proceeded to sign the respective purchase and sale contract for 99.88% of the capital stock of Enel Distribución Goias, for a total consideration of R$2,269 million (about US$720 million), which was the date from which the purchase accounting established in IFRS 3 Business Combinations, applies. Established in 1956 and with its headquarters in Goiania, Enel Distribución Goias operates in a territory covering more than 337.000Km2; its concession is in force until 2045 and it has a customer base of 2,828,459.

The purchase of Enel Distribución Goias was financed completely with funds raised in the capital increase of Enel Américas approved towards the end of 2012. This acquisition increases the number of customers of Enel Brasil by 2,828,459, reaching a total of 9,817,668 (the total number of customer before the incorporation was 6,989,209).

The functional currency of Enel Distribución Goias is the Brazilian Real (R$). Enel Américas has converted the initial effects of the business combination into its presentation currency, using the exchange rate in effect on the date of acquisition. At each reporting period-end, the financial statements of Enel Distribución Goias are converted using the accounting criterion specified in Note 2.7.3.

Since the date of acquisition, Enel Distribución Goias contributed revenue of ThUS$1,519,239 and pretax losses of ThUS$30,826 to the profit and loss of Enel Américas for the period ended December 31, 2017. If the acquisition had occurred in January 1, 2017, it is estimated that the consolidated revenue for the year ended December 31, 2017 would have increased by ThUS$1,624,297 and the consolidated gain before tax would have decreased by ThUS$35,585.

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a)    Identifiable assets acquired and identifiable liabilities assumed

	Final Fair Value		Final Fair Value
Identifiable net assets acquired	ThR$		ThUS$
Cash and cash equivalents	29,643		9,538
Other current non-financial assets	198,054		63,727
Trade and other current receivables	973,382		313,199
Inventories	24,618		7,921
Current tax assets	2,173		699
Other non-current financial assets	89,514		28,802
Other non-current non-financial assets	698,435		224,731
Trade and other non-current receivables	204,480		65,794
Intangible assets other than goodwill	5,936,985		1,910,306
Property, plant and equipment	42,998		13,835
Deferred tax assets	—		—
Other current financial liabilities	(480,165	)	(154,500	)
Trade and other current payables	(1,754,071	)	(564,395	)
Other current provision	(33,965	)	(10,929	)
Other non-current financial liabilities	(562,823	)	(181,096	)
Other non-current payables	(1,584,665	)	(509,888	)
Other non-current provision	(712,465	)	(229,245	)
Deferred tax liabilities	(529,958	)	(170,521	)
Provisions for non-current employee benefits	(273,502	)	(88,003	)
Total	2,268,668		729,975

During 2018, the final allocation of the purchase price to the identifiable net assets of Enel Distribucion Goias was completed without differences from the provisional purchase price allocation.

b)    Determination of the Goodwill

	ThR$		ThUS$
Cash consideration transferred	2,268,667		729,975
(-) Net assets acquired and liabilities assumed	(2,268,667	)	(729,975	)
Goodwill determinated	—		—

c)The amounts paid to obtain control of CELG are shown below:

Cash and Cash equivalents to obtain control of CELG	ThUS$
Amounts paid for the acquisition in cash and cash equivalents	(729,975	)
Amounts of cash and cash equivalents in the acquired entity	9,573
Net, Total	(720,402	)

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7.2.ACQUISITION OF ENEL DISTRIBUCIÓN SAO PAULO S.A. (FORMERLY ELETROPAULO METROPOLITANA DE ELETRICIDADE DE SAO PAULO S.A.)

On April 17, 2018, the Company’s subsidiary Enel Brasil S.A., through its 100% owned subsidiary Enel Investimentos Sudeste S.A. (Enel Sudeste), launched a voluntary public tender offer all the shares issued by the Brazilian electric power distributor Enel Distribución Sao Paulo S.A. subject to the acquisition of more than 50% of such shares in order to obtain control thereof.

On June 4, Enel Sudeste received the approval of the Brazilian authority for Free Competition, or Conselho Administrativo de Defensa Econômica (“CADE”). On the same date, the success of the public tender offer and the acquisition of the initial auction was confirmed, which was perfected through the payment of the price and transfer of the shares in favor of Enel Sudeste, which took place on June 7, 2018, the date on which the purchase accounting was established in IFRS 3, Business Combinations, applies. Specifically, 122,799,289 shares were acquired, all of the same class, corresponding to 73.38% of the capital stock of Enel Distribución Sao Paulo S.A. for a total of ThR$5,552,984 (approximately US$1,484 million).

In addition, on June 11, 2018, the ANEEL issued a technical note approving the taking over of control of Enel Distribución Sao Paulo S.A., which occurred with the purchase of the shares mentioned in the preceding paragraphs. This technical note was published by ANEEL on June 26, 2018.

Given that the shareholders of Enel Distribución Sao Paulo S.A. had until July 4, 2018 to sell the remaining shares to Enel Sudeste at the same price offered in the public tender offer (R$45.22 per share), additional increases in participation were perfected during the months of June and July. In effect, on June 22 and 30 and July 2 and 4, 2018, 4,692,338, 4,856,462, 14,525,826 and 9,284,666 shares were acquired, respectively, equivalent to a total of ThR$1,516,362 (approximately US$ 384 million). These subsequent acquisitions represented an increase in Enel Sudeste’s ownership from 73.38% to 95.05%.

On September 19, 2018, the Board of Directors of Enel Distribución Sao Paulo S.A. approved an increase in the company’s capital stock in the amount of ThR$1,500,000, through the issuance of 33,171,164 new shares. Enel Sudeste participated in this capital increase, acquiring 33,164,964 of the new shares (approximately US$ 395 million), thus increasing its ownership interest to 95.88% of the company.

The functional currency of Enel Distribución Sao Paulo S.A. is the Brazilian Real (R$). Enel Américas has converted the initial effects of the business combination into its presentation currency using the exchange rate prevailing at the date of acquisition. At each reporting period end, the financial statements of Enel Distribución Sao Paulo S.A. are converted following the accounting criteria detailed in Note 2.7.3.

Enel Distribución Sao Paulo S.A. has a concession area covering 4,526 km², which concentrates most of the gross domestic product and the highest population density in Brazil, with 1,581 consumer units per km², corresponding to 33.3% of the total electricity consumed in the State of Sao Paulo and 9.3% of the total in Brazil. It serves a demand of approximately 7.2 million consumer units, has 7,355 employees of its own, and has an infrastructure made up of 156 substations.

Since the date of acquisition, Enel Distribución Sao Paulo S.A. has contributed revenue of ThUS$2,214,855 and pretax losses of ThUS$39,227  to the profit and loss of Enel Américas for the period ended December 31, 2018. If the acquisition had occurred on January 1, 2018, it is estimated that the consolidated revenue for the year ended December 31, 2018 would have increased by ThUS$3,587,161 and the consolidated gain before tax would have decreased by ThUS$14,678.

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Assets acquired and liabilities assumed at the acquisition date

	Fair Value		Fair Value
Identifiable net assets acquired	ThR$		ThUS$
Cash and cash equivalents	1,037,105		273,439
Other current non-financial assets	400,311		105,544
Trade and other current receivables	3,948,137		1,040,949
Inventories	275,129		72,539
Current tax assets	41,179		10,857
Other non-current financial assets	3,205,469		845,140
Other non-current non-financial assets	1,056,711		278,608
Trade and other non-current receivables	205,249		54,115
Intangible assets other than goodwill	11,055,574		2,914,866
Property, plant and equipment	65,804		17,350
Investment property	44,049		11,614
Deferred tax assets	3,229,417		851,455
Other current financial liabilities	(2,266,501	)	(597,576	)
Trade and other current payables	(3,551,676	)	(936,420	)
Other current provision	(759,862	)	(200,342	)
Other current non-financial liabilities	(600,990	)	(158,454	)
Other non-current financial liabilities	(2,505,299	)	(660,537	)
Other non-current payables	(567,355	)	(149,586	)
Other non-current provision	(2,788,278	)	(735,146	)
Deferred tax liabilities	(3,009,203	)	(793,394	)
Provisions for non-current employee benefits	(3,327,621	)	(877,347	)
Total	5,187,349		1,367,674

Determination of goodwill

	ThR$		ThUS$
Cash consideration transferred	7,069,345		1,863,874
Non-controlling interests assumed in the acquisition	256,616		67,658
(-) Net assets acquired and liabilities assumed	(5,187,349	)	(1,367,674	)
Goodwill determinated	2,138,612		563,858

Goodwill is mainly attributable to the value of the synergies that are expected to be achieved through the integration of Enel Distribución Sao Paulo into the Group. These synergies are related, among others, to the generation of new businesses, efficiencies in investments and administrative costs.

The amounts paid to obtain control of Enel Distribución Sao Paulo S.A. are shown below:

Cash and Cash equivalents to obtain control of Enel Distribución Sao Paulo	ThUS$
Amounts paid for the acquisition in cash and cash equivalents	(1,863,874	)
Amounts of cash and cash equivalents in the acquired entity	273,439
Net, Total	(1,590,435	)

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8.   ARGENTINA’S HYPERINFLATIONARY ECONOMY

Since July 2018, Argentina’s economy is considered hyper-inflationary under the provisions of IAS 29 - Financial Reporting in Hyperinflationary Economies. A number of qualitative and quantitative criteria led to this qualification; chief among them is the cumulative inflation rate over three years exceeding 100%.

In accordance with the provisions of IAS 29, the financial statements of the companies in Argentina in which Enel Américas has an interest have been retrospectively restated by applying a general price index to the historical cost, in order to reflect changes in the purchasing power of the Argentine currency as of the closing date of these financial statements.

Non-monetary assets and liabilities were restated since February 2003, which was the last date on which an adjustment for inflation was made for accounting purposes in Argentina. In this regard, please note that the Group made its transition to IFRS on January 1, 2004 by applying the attributed cost exception for Property, plant and equipment.

For consolidation purposes in Enel Américas and as a result of the application of IAS 29, the profit or loss and the financial position of our Argentine subsidiaries was translated using the closing exchange rate (Ar$/ US$) as of December 31, 2018 in accordance with the provisions of IAS 21 The Effects of Changes in Foreign Exchange Rates due to the fact that the Argentine economy qualifies as a hyper-inflationary economy (see Note 2.7.4). Previously, the profit or loss of the Argentine subsidiaries were translated using the average exchange rate of the period, as is the case for the translation of the profit or loss of the rest of the subsidiaries operating in other countries whose economies do not qualify as hyper-inflationary economies.

Considering that Enel Américas’ functional and presentation currency is not that of a hyper-inflationary economy according to the guidelines of IAS 29, the restatement of comparative periods is not required in the Group’s consolidated financial statements.

The general price indices used at the close of the reporting periods are as follows:

	General price index
Historical inflation accumulated up to December 31, 2017	652.29	%
From January to December 2018	47.83	%

The first time application of IAS 29 resulted in a positive adjustment to retained earnings of Enel Américas in the amount of ThUS $961,106 (net of taxes) as of January 1, 2018, of which ThUS$ 668,693 is attributable to the shareholders of Enel Américas. On the other hand, during 2018 the application of this standard resulted in a financial income of ThUS$ 270,380 (before tax). See Note 34.

The following is a summary of the effects of hyperinflation on the Consolidated Statements of Financial Position and Consolidated Statements of Comprehensive Income of Enel Américas:

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	Initial balance as of 01-01-2018	Hyperinflation effects during period	Translation difference		Final hyperinflation balance as of 12-31-2018
	ThUS$	ThUS$	ThUS$		ThUS$
ASSETS
Current inventories	5,861	2,099	(2,886	)	5,074
TOTAL CURRENT ASSETS	5,861	2,099	(2,886	)	5,074
Investments accounted for using the equity method	512	128	(252	)	388
Intangible assets other than goodwill	8,163	4,042	(4,020	)	8,185
Goodwill	29,432	8,495	(14,492	)	23,435
Property, plant and equipment	1,219,598	556,270	(600,494	)	1,175,374
TOTAL NON-CURRENT ASSETS	1,257,705	568,935	(619,258	)	1,207,382
TOTAL ASSETS	1,263,566	571,034	(622,144	)	1,212,456
LIABILITIES
Deferred tax liabilities	302,459	111,518	(148,930	)	265,047
TOTAL NON-CURRENT LIABILITIES	302,459	111,518	(148,930	)	265,047
TOTAL LIABILITIES	302,459	111,518	(148,930	)	265,047
EQUITY
Equity attributable to the owners of the parent	668,693	324,542	(329,230	)	664,005
Non-controlling interests	292,414	134,974	(143,984	)	283,404
TOTAL EQUITY	961,107	459,516	(473,214	)	947,409
TOTAL EQUITY AND LIABILITIES	1,263,566	571,034	(622,144	)	1,212,456

	Effect of IAS 29		Effect of IAS 21		Total Adjustments
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME Profit (loss)	ThUS$ (I)		ThUS$ (II)		ThUS$ (III)
Revenues	279,128		(425,640	)	(146,512	)
Other operating income	3,436		(8,489	)	(5,053	)
Revenues and Other Operating Income	282,564		(434,129	)	(151,565	)
Raw materials and consumables used	(136,703	)	222,594		85,891
Contribution margin	145,861		(211,535	)	(65,674	)
Other work performed by the entity and capitalized	9,092		(15,909	)	(6,817	)
Employee benefits expenses	(48,709	)	76,287		27,578
Depreciation and amortization expense	(133,813	)	14,060		(119,753	)
Reversal of impairment losses recognized in the period’s profit or loss	63,256		18,621		81,877
Other expenses	(27,213	)	39,638		12,425
Operating loss	8,474		(78,838	)	(70,364	)
Other gains (losses)	5		(24	)	(19	)
Financial income	13,292		(33,256	)	(19,964	)
Financial costs	(33,526	)	68,025		34,499
Share in profits (losses) of associates and joint ventures accounted for under the equity method	259		(616	)	(357	)
Foreign currency exchange differences	(200	)	(37,573	)	(37,773	)
Gains (losses) from indexed assets and liabilities	270,380		—		270,380
Income (loss) before taxes	258,684		(82,282	)	176,402
Income tax expenses, continuing operations	(117,301	)	30,386		(86,915	)
Income (loss) from continuing operations	141,383		(51,896	)	89,487
NET INCOME (LOSS)	141,383		(51,896	)	89,487
Net income (loss) attributable to:
The owners of the parent	119,402		(23,364	)	96,038
Non-controlling interests	21,981		(28,532	)	(6,551	)
NET INCOME (LOSS)	141,383		(51,896	)	89,487

(i)Corresponds to the profit or loss arising from the net position of monetary assets and liabilities, as defined by IAS 29. This profit or loss is determined by restating non-monetary assets and liabilities, as well as those income statement accounts that have not already been updated.

(ii)Corresponds to the difference that arises from translating the profit or loss of the Argentine subsidiaries using the closing exchange rate, as defined by IAS 21 with respect to hyper-inflationary economies, as opposed to the average exchange rate, which is the methodology

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previously applied to Argentine companies and to the rest of the subsidiaries of Enel Américas operating in other countries in the region (non-hyper-inflationary economies).

(iii)Sum of (i) + (ii).

9.   CASH AND CASH EQUIVALENTS

a)   The details of cash and cash equivalents as of December 31, 2018 and 2017 are as follows:

	Balance as of
Cash and Cash Equivalents	12-31-2018 ThUS$	12-31-2017 ThUS$
Cash balances	4,647	8,410
Bank balances	784,957	655,226
Time deposits	1,065,378	629,716
Other fixed-income instruments	49,303	179,411
Total	1,904,285	1,472,763

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.

b)   The detail of cash and cash equivalents by currency is as follows:

	Balance as of
Currency	12-31-2018 ThUS$	12-31-2017 ThUS$
Chilean peso	151,714	475
Argentine peso	101,209	219,761
Colombian peso	372,361	322,022
Brazilian real	633,635	470,360
Peruvian soles	129,263	145,950
U.S. dollar	513,667	306,590
Euros	2,436	7,605
Total	1,904,285	1,472,763

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c)   The following table sets forth the components of “Other payments for operating activities” line item in the Statement of Cash Flows:

	For the years ended December 31,
Other Payments from Operating Activities	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
Payment for other taxes (VAT, ICMS, PIS/COFINS, Sales taxes, Custom taxes, taxes on bank transfers) (1)	(2,774,024	)	(1,921,496	)	(1,228,307	)
Payments for collections made under Codensa Hogar contract (2)	(514,595	)	(566,795	)	(452,883	)
Payments for the Energy Development Account (CDE) (3)	(926,642	)	(608,591	)	(249,856	)
Other miscellaneous itemized payments for operating activities (4)	(1,012,571	)	(532,677	)	(383,035	)
Total other payments from operating activities	(5,227,832	)	(3,629,559	)	(2,314,081	)

(1)  The main elements of payments for other taxes are related to:

·ICMS is a Brazilian state value added tax (VAT) on the circulation of goods, telecommunication and transportation services. The ICMS payments were ThUS$ 2,154,158, ThUS$ 1,411,772 and ThUS$857,582 for the years ended December 31, 2018, 2017 and 2016, 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 workers, 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$474,826, ThUS$347,608 and ThUS$203,095 for the years ended December 31, 2018, 2017 and 2016, respectively.

·Payment for taxes on sales in Peru for ThUS$81,694, ThUS$70,271 and ThUS$88,084 for the years ended December 31, 2018, 2017 and 2016, 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 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 aggregate payments for operating activities includes several types of individually non-significant payments related to operating activities.

d)  The table below details the changes in the liabilities originating in the Group’s financing activities at December 31, 2018 and 2017, including those changes representing cash flows and changes that do not represent cash flows.

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Liabilities originating in financing activities are those for which the cash flows were or will be classified in the cash flow statement as cash flows from financing activities:

		Cash flows from financing								Changes that do not represent cash flows
Liabilities from	Balance at 1/1/2018(1)		From	Used (3)		Paid interest		Total		Acquisition of subsidiaries	Sale of subsidiaries	Changes in fair value		Exchange differences		Financial costs(2)		New financial leases	Other changes		Balance at 31/12/2018(1)
financing activities	ThUS$		ThUS$	ThUS$		ThUS$		ThUS$		ThUS$	ThUS$	ThUS$		ThUS$		ThUS$		ThUS$	ThUS$		ThUS$
Bank Loans (Note 21.1)	1,501,723		933,146	(744,730	)	(99,667	)	88,749		248,027	—	—		(129,975	)	165,292		—	22,093		1,895,909
Unsecured obligations with public (Note 21.1)	3,178,008		3,605,019	(3,475,288	)	(289,093	)	(159,362	)	1,123,222	—	—		(337,715	)	315,051		—	(60,605	)	4,058,599
Financial lease (Note 21.1)	104,492		—	(31,619	)	(7,037	)	(38,656	)	22,677	—	—		(2,992	)	8,170		28,143	139		121,973
Other liabilities (Note 21.1)	219,735		—	(81,340	)	(15,709	)	(97,049	)	—	—	—		(23,776	)	28,152		—	60,816		187,878
Hedging derivatives (Note 23)	3,284		5,474	—		(28,046	)	(22,572	)	—	—	15,601		(133,070	)	27,064		—	1,148		(108,545	)
Non-hedging derivatives (Note 23)	3,162		15,926	—		—		15,926		—	—	(14,065	)	1,920		(22,958	)	—	(206	)	(16,221	)
Loans from related companies (Note 13.1.b)	—		2,686,387	—		—		2,686,387		—	—	—		(86,820	)	52,820		—	—		2,652,387
Other accounts payable	112,086		—	—		—		—		—	—	—		—		21,028		—	—		133,114
Total	5,122,490		7,245,952	(4,332,977	)	(439,552	)	2,473,423		1,393,926	—	1,536		(712,428	)	594,619		28,143	23,385		8,925,094

		Cash flows from financing								Changes that do not represent cash flows
Liabilities from	Balance at 1/1/2017(1)		From	Used (3)		Paid interest		Total		Acquisition of subsidiaries	Sale of subsidiaries	Changes in fair value		Exchange differences		Financial costs(2)	New financial leases	Other changes		Balance at 31/12/2017(1)
financing activities	ThUS$		ThUS$	ThUS$		ThUS$		ThUS$		ThUS$	ThUS$	ThUS$		ThUS$		ThUS$	ThUS$	ThUS$		ThUS$
Bank Loans (Note 21.1)	964,845		783,342	(305,915	)	(74,135	)	403,292		55,421	—	(775	)	(11,659	)	94,163	—	(3,564	)	1,501,723
Unsecured obligations with public (Note 21.1)	3,154,734		580,365	(573,994	)	(237,702	)	(231,331	)	—	—	—		11,920		230,212	—	12,473		3,178,008
Financial lease (Note 21.1)	125,190		—	(46,975	)	(5,984	)	(52,959	)	—	—	—		(175	)	5,882	17,605	8,949		104,492
Other liabilities (Note 21.1)	63,001		125,345	(221,232	)	(25,941	)	(121,828	)	271,607	—	(8,667	)	(13,346	)	28,874	—	94		219,735
Hedging derivatives (Note 23)	21,069		230	(15,958	)	—		(15,728	)	—	—	(10,688	)	(3,371	)	8,874	—	3,128		3,284
Non-hedging derivatives (Note 23)	—		174	(12,878	)	—		(12,704	)	—	—	13,235		105		2,526	—	—		3,162
Loans from related companies	—		257,453	(257,956	)	(229	)	(732	)	—	—	—		503		229	—	—		—
Other accounts payable	118,969		13,995	(26,751	)	—		(12,756	)	—	—	—		(21,925	)	27,798	—	—		112,086
Total	4,447,808		1,760,904	(1,461,659	)	(343,991	)	(44,746	)	327,028	—	(6,895	)	(37,948	)	398,558	17,605	21,080		5,122,490

(1)Corresponding to current and non-current portions.

(2)This is accrual of interest.

(3)The amount of the Repayment of loans in 2018 and 2017 for ThUS$4,301,358 and ThUS$1,127,892, respectively, to Financing Cash Flows Used in bank Loans, unsecured public bonds, finance leases and other Accounts payable of this reconciliation

(4)

10.   OTHER FINANCIAL ASSETS

The detail of other financial assets as of December 31, 2018 and 2017 is as follows:

	Balance as of
	Current		Non-Current
Other Financial Assets (*)	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$
Available-for-sale financial investments — unquoted equity securities or with limited liquidity	—	—	—
Available-for-sale financial investments IFRIC 12 (3)	12,655	14,286	354,344	413,435
Financial assets at fair value with changes in results IFRIC 12 (2)			2,371,635	1,312,871
Financial assets at fair value with change in other comprehensive income			753
Financial assets held to maturity (1)	24,358	43,737	—	27
Hedging derivatives	44,424	2,168	69,729	19,932
Financial assets at fair value through profit or loss (1)	105,372	49,757	14	1,104
Non-hedging derivatives	23,584	404	—	4,898
Total	210,393	110,352	2,796,475	1,752,267

(1)The amounts included in financial assets measured at fair value 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 4.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. and Enel Distribución Sao Paulo S.A. (with balances as at December 31, 2018 of

F-100

ThUS$871,657, ThUS$487,241, ThUS$33,507 and ThUS$979,230, respectively). The legislation in effect, among other aspects, establishes that in its capacity of grantor the Government 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 4.d.1.

(3)Corresponding to the concession agreement in Enel Green Power Project I (Volta Grande); see Note 4.d.1.

F-101

11.  OTHER NON-FINANCIAL ASSETS AND LIABILITIES

a)The detail of other non-financial assets as of December 31, 2018 and 2017, is as follows:

	Balance as of
	Current		Non-Current
	12/31/2018	12/31/2017	12/31/2018	12/31/2017
Other non-financial assets	ThUS$	ThUS$	ThUS$	ThUS$
VAT Tax Credit and Other Taxes	41,606	88,115	113,441	97,520
Contributions fund to Enel Distribución Goiás (*)	43,619	57,654	328,714	280,678
Ongoing services provided by third parties	61,725	41,882	—	—
Ongoing I & D and Energy Efficiency service	32,840	13,055	—	—
Judicial Deposits	—	—	278,261	149,545
Assets under construction IFRIC 12 (**)	—	—	385,171	—
Prepaid expenses	32,255	15,453	—	—
Other	95,687	67,473	35,121	32,683
Total	307,732	283,632	1,140,708	560,426

(*) Through Law 17,555 as 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 sale of equity control to Eletrobrás, according to the terms of the agreement between the shareholders and the management, as well as to FUNAC’s cooperation terms. The resources of the aforementioned fund depend on the contributions to be made by the government of the Goiás state and the credits received for lawsuits won by Enel Distribución Goiás, which are transferred to the fund; see Note 41.

(**) Corresponds to assets in construction referring to concessions by subsidiaries Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Goiás S.A. and Enel Distribución Sao Paulo S.A.

b)The detail of other non-financial liabilities as of December 31, 2018 and 2017, is as follows:

	Balance as of
	Current		Non-Current
	12/31/2018	12/31/2017	12/31/2018	12/31/2017
Other non-financial liabilities	ThUS$	ThUS$	ThUS$	ThUS$
VAT Tax Payable and Other Taxes	256,581	219,019	67,966	81,769
Other	13,539	34,065	37,257	41,748
Total	270,120	253,084	105,223	123,517

F-102

12.  TRADE AND OTHER RECEIVABLES

a)The detail of trade and other receivables as of December 31, 2018 and 2017, is as follows:

	Balance as of
	Current		Non-Current
Trade and Other Receivables, Gross	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$
Trade and other receivables, gross	4,350,373	2,932,551	907,022	616,793
Trade receivables, gross	3,017,469	2,342,813	171,513	96,367
Other receivables, gross (1)	1,332,904	589,738	735,509	520,426

	Balance as of
	Current		Non-Current
Trade and Other Receivables, Net	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$
Trade and other receivables, net	3,551,022	2,377,789	906,508	616,793
Trade receivables, net	2,264,869	1,791,262	171,513	96,367
Other receivables, net (1)	1,286,153	586,527	734,995	520,426

(1)Includes as of December 31, 2018, mainly accounts receivable related to loans and advances to employees for ThUS22,906 (ThUS$22,330 as of December 31, 2017). Accounts receivable at our Brazilian subsidiaries Enel Distribución Río S.A. and Enel Distribución Ceará S.A., following the signing in 2014 of the addendum to the concession contracts where the outstanding assets are recoverable and/or can be offset in subsequent tariff periods for ThUS$1,241,355 (ThUS$365,086 as of December 31, 2017), which are guaranteed by the Brazilian government; a receivable to “low income” consumers for ThUS$216,699 (ThUS$243,022 as of December 31, 2017) to which a social discount is applied determining a “low income” final tariff, where 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 state subsidy; and receivables related to the VOSA project in Argentina for ThUS$371,222 (ThUS$353,738 as of December 31, 2017).

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, 2018 and 2017.

Refer to Note 13.1 for detailed information on amounts, terms and conditions associated with accounts receivable from related companies.

b)As of December 31, 2018 and 2017, the balance of past due but not impaired trade receivables is as follows:

	Balance as of
Trade Receivables Past Due But Not Impaired (*)	12-31-2018 ThUS$	12-31-2017 ThUS$
Less than three months	452,556	410,907
Between three and six months	133,316	93,335
Between six and twelve months	68,973	48,104
More than twelve months	93,200	52,305
Total	748,045	604,651

(*)These balances correspond to non-impaired past due accounts and the portion does not affect the provision of other accounts due receivable.

F-103

c)   The reconciliation of changes in the allowance for impairment of trade receivables is as follows:

	Current and
Trade Receivables Past Due and Impaired	Non-Current ThUS$
Balance as of January 1, 2017	288,380
Increases (decreases) for the year (*)	124,120
Amounts written off	(81,995	)
Foreign currency translation differences	(18,406	)
Other movements	242,663
Balance as of December 31, 2017	554,762
Initial balance adjustment for IFRS 9	10,286
Increases (decreases) for the year (*)	114,671
Amounts written off	(47,959	)
Foreign currency translation differences	(106,837	)
Other movements	274,942
Balance as of December 31, 2018	799,865

(*)See Note 29.31 Impairment losses on financial assets.

The increase in the allowance for impairment of trade receivables was ThUS$114,671 and ThUS$124,120 for the years ended December 31, 2018 and 2017, respectively (see Note 31).

Write-offs for bad debt

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, 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 4.f.3 and 22.5).

d)    Additional information:

·Additional statistical information required under Official Bulletin 715 of the CMF, of February 3, 2012 (XBRL Taxonomy). See Appendix 2.

·Supplementary information on Trade Receivables, see Appendix 2.1.

13.  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.

F-104

13.1  Balances and transactions with related parties

The balances of accounts receivable and payable as of December 31, 2018 and 2017 are as follows:

a)    Receivables from related companies

							Balance as of
							Current		Non-Current
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of Transaction	Term of Transaction	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$
Foreign	Endesa Spain	Spain	Common Immediate Parent	Euros	Other services	More than 90 days	18	18	—	—
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	US$	Other services	Less than 90 days	—	1	—	—
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	79	35	—	—
Foreign	Endesa Operaciones y Servicios Comerciales	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	72	—	—	—
Foreign	Endesa Operaciones y Servicios Comerciales	Spain	Common Immediate Parent	CP$	Other services	Less than 90 days	—	75	—	—
Foreign	SACME	Argentina	Associate	AR$	Other services	Less than 90 days	21	41	108	255
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	CP$	Other services	Less than 90 days	—	32	—	—
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Euros	Other services	Less than 90 days	—	1,289	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	753	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	—	10	—	—
91.081.000-6	Enel Generacion Chile S.A	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	3	—	—	—
91.081.000-6	Enel Generacion Chile S.A	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	—	2	—	—
91.081.000-6	Enel Generacion Chile S.A	Chile	Common Immediate Parent	AR$	Other services	Less than 90 days	22	22	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	1,354	4	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	7	1,489	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	CP$	Other services	Less than 90 days	24	16	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	AR$	Other services	Less than 90 days	97	94	—	—
Foreign	Enel S.p.A.	Italy	Parent	CH$	Other services	Less than 90 days	—	120	—	—
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	373	—	—	—
Foreign	Enel S.p.A.	Italy	Parent	CP$	Other services	Less than 90 days	879	918	—	—
Foreign	Enel S.p.A.	Italy	Parent	R$	Other services	Less than 90 days	267	—	—	—
Foreign	Enel Green Power S.p.a	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	72	—	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	US$	Other services	Less than 90 days	—	17	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	CP$	Other services	Less than 90 days	—	29	—	—
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	PS$	Other services	Less than 90 days	36	37	—	—
Foreign	Enel Green Power Colombia	Colombia	Common Immediate Parent	CP$	Other services	Less than 90 days	—	237	—	—
Foreign	Enel Green Power Participações Ltda	Brazil	Common Immediate Parent	R$	Energy sales	Less than 90 days	3,059	1,670	1,544	2,590
Foreign	Enel Green Power Participações Ltda	Brazil	Common Immediate Parent	R$	Other services	Less than 90 days	1,312	260	—	—
Foreign	Enel Green Power Participações Ltda	Brazil	Common Immediate Parent	R$	Tolls	Less than 90 days	19	25	—	—
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	AR$	Other services	Less than 90 days	6	12	—	—
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	CP$	Other services	Less than 90 days	33	31	—	—
Foreign	Enel Energia	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	83	87	—	—
Foreign	Enel Green Power Argentina	Argentina	Common Immediate Parent	AR$	Other services	Less than 90 days	330	594	—	—
Foreign	Enel Green Power North América Inc.	United States	Common Immediate Parent	US$	Other services	Less than 90 days	29	6	—	—
78.932.860-9	Gas Atacama Chile	Chile	Common Immediate Parent	R$	Current mercantile account	Less than 90 days	108	126	—	—
Foreign	Enel Green Power Colombia SAS	Colombia	Common Immediate Parent	CP$	Other services	Less than 90 days	155	106	—	—
Foreign	Enel Iberia Srl	Colombia	Common Immediate Parent	CP$	Other services	Less than 90 days	29	—	—	—
Foreign	Enel Iberia Srl	Colombia	Common Immediate Parent	Euros	Other services	Less than 90 days	1,288	—	—	—
Foreign	Energética Monzon S.A.C	Perú	Common Immediate Parent	US$	Other services	Less than 90 days	191	—	—	—
Foreign	Energética Monzon S.A.C	Perú	Common Immediate Parent	PS$	Other services	Less than 90 days	254	—	—	—
Foreign	Proyectos Y Soluciones Renovables S.A.C	Perú	Common Immediate Parent	US$	Other services	Less than 90 days	194	—	—	—
Foreign	Proyectos Y Soluciones Renovables S.A.C	Perú	Common Immediate Parent	PS$	Other services	Less than 90 days	230	—	—	—
Foreign	Enel Green Power Perú (USD)	Perú	Common Immediate Parent	US$	Other services	Less than 90 days	1,091	—	—	—
Foreign	Enel Green Power Perú (USD)	Perú	Common Immediate Parent	PS$	Other services	Less than 90 days	1,700	—	—	—
Foreign	Enel X S.R.L	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	149	—	—	—
		Total					14,337	7,403	1,652	2,845

F-105

b)    Accounts payable to related companies

							Balance as of
							Current		Non-Current
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of Transaction	Term of Transaction	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$
Foreign	Enel Latinoamérica S.A.	Spain	Common Immediate Parent	AR$	Dividends	Less than 90 days	29	57	—	—
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	CP$	Other services	Less than 90 days	—	81	—	—
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Euros	Other services	Less than 90 days	—	237	—	—
Foreign	SACME	Argentina	Associate	AR$	Other services	Less than 90 days	237	258	—	—
78.932.860-9	Gas Atacama Chile	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	153	81	—	—
Foreign	Endesa Generación	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	202	—	—	—
Foreign	Endesa Generación	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	—	170	—	—
Foreign	Endesa Generación	Spain	Common Immediate Parent	US$	Other services	Less than 90 days	11	—	—	—
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	2,439	1,731	—	—
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	Euros	Purchase of materials	Less than 90 days	—	897	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	US$	Other services	Less than 90 days	—	136	—	—
Foreign	Enel Produzione	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	9,850	7,865	—	—
Foreign	Endesa Spain	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	1,637	1,302	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	153	261	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	CP$	Other services	Less than 90 days	—	60	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	209	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	AR$	Other services	Less than 90 days	17	16	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	2,329	1,809	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	185	270	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	CP$	Other services	Less than 90 days	116	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	Common Immediate Parent	Euros	Other services	Less than 90 days	46	3,198	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	6,422	2,961	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	664	2,386	—	—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	CP$	Other services	Less than 90 days	616	—	—	—
Foreign	Enel Map	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	16,089	—	—	—
Foreign	Yacylec S.A.	Argentina	Common Immediate Parent	AR$	Other services	Less than 90 days	12	60	—	—
Foreign	Enel Trade S.p.A.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	3,268	1,857	—	—
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	45,886	41,175	—	—
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	—	5,546	—	—
Foreign	Enel S.p.A.	Italy	Parent	US$	Dividends	Less than 90 days	186,697	110,188	—	—
Foreign	Enel S.p.A.	Italy	Parent	CP$	Other services	Less than 90 days	127	232	—	—
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	—	121	—	—
Foreign	Enel S.p.A.	Italy	Parent	AR$	Other services	Less than 90 days	—	57	—	—
Foreign	Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	R$	Energy purchases	Less than 90 days	11,644	15,972	—	—
Foreign	Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	R$	Other services	Less than 90 days	812	603	—	—
Foreign	Enel Italia Servizi SRL	Italy	Common Immediate Parent	CP$	Other services	Less than 90 days	—	586	—	—
Foreign	Enel Italia Servizi SRL	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	38,825	24,302	—	—
Foreign	Enel Italia Servizi SRL	Italy	Common Immediate Parent	PS$	Other services	Less than 90 days	—	274	—	—
76.250.019-1	Enel Green Power Chile Ltda.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	63	63	—	—
Foreign	Enel Fortuna S.A.	Panama	Common Immediate Parent	US$	Other services	Less than 90 days	53	58	—	—
Foreign	Enel Green Power SPA	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	3,074	80	—	—
Foreign	Enel Green Power Italy	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	—	77	—	—
Extranjera	Enel Iberia SRL	Italy	Common Immediate Parent	CP$	Other services	Less than 90 days	155	—	—	—
Extranjera	Enel Iberia SRL	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	1,315	—	—	—
Extranjera	Enel Sole	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	999	—	—	—
Extranjera	Enel Global Thermal Generation SRL	Italy	Common Immediate Parent	AR$	Other services	Less than 90 days	2,913	—	—	—
Extranjera	Enel Global Thermal Generation SRL	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	1,467	—	—	—
Extranjera	Enel Global Thermal Generation SRL	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	1,110	—	—	—
Extranjera	Proyectos Y Soluciones Renovables S.A.C.	Perú	Common Immediate Parent	PS$	Other services	Less than 90 days	371	—	—	—
Extranjera	Enel Green Power Peru (USD)	Perú	Common Immediate Parent	PS$	Other services	Less than 90 days	101	—	—	—
Extranjera	Enel Green Power Peru (USD)	Perú	Common Immediate Parent	PS$	Energy purchases	Less than 90 days	513	—	—	—
Extranjera	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	2,171	—	—	—
Extranjera	Cesi S.p.A.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	343	—	—	—
Extranjera	Endesa Distribución Eléctrica	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	273	—	—	—
Extranjera	Enel Green Power Colombia S.A.S	Colombia	Common Immediate Parent	CP$	Other services	Less than 90 days	162	—	—	—
Extranjera	ENEL X S.R.L.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	523	—	—	—
Extranjera	Enel Finance International NV (*)	Holanda	Common Immediate Parent	R$	Loans payable (*)	more than 90 days	2,466,231	—	—	—
Extranjera	Enel Finance International NV (*)	Holanda	Common Immediate Parent	R$	Loans payable (*)	more than 90 days	77,566	—	—	—
Extranjera	Enel Finance International NV (*)	Holanda	Common Immediate Parent	R$	Loans payable (*)	more than 90 days	108,590	—	—	—
		Total					2,996,668	225,027	—	—

(*) See Note d) below

F-106

c)    Significant transactions and effects on income/expenses:

Transactions with related companies that are not consolidated and their effects on profit or loss are as follows:

					For the years ended,
Taxpayer ID N°	Company	Country	Relationship	Description of Transaction	12-31-2018 ThUS$		12-31-2018 ThUS$		12-31-2016 ThUS$
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	Other operating income	—		90		—
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	Other services rendered	103		—		—
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	Other operating income	—		—		65
Foreign	Enel Latinoamérica S.A	Spain	Common Immediate Parent	Other fixed operating expenses	—		—		(127	)
Foreign	Endesa Generación	Spain	Common Immediate Parent	Fuel consumption	—		—		(16,975	)
Foreign	Endesa Generación	Spain	Common Immediate Parent	Other fixed operating expenses	(53	)	(160	)	(39	)
76.418.940-k	GNL Chile S.A. (*)	Chile	Associate	Gas consumption	—		—		(20,267	)
76.418.940-k	GNL Chile S.A. (*)	Chile	Associate	Gas transportation	—		—		(13,197	)
76.418.940-k	GNL Chile S.A. (*)	Chile	Associate	Other financial income	—		—		2
76.788.080-4	GNL Quintero S.A. (*)	Chile	Associate	Energy purchases	—		—		657
76.788.080-4	GNL Quintero S.A. (*)	Chile	Associate	Tolls	—		—		(223	)
76.788.080-4	GNL Quintero S.A. (*)	Chile	Associate	Other fixed operating expenses	—		—		(55	)
Foreign	SACME	Argentina	Associate	Outsourced services	—		—		(2,438	)
Foreign	SACME	Argentina	Associate	Other services rendered	(1,739	)	(2,761	)	—
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Energy purchases	—		—		(2,195	)
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Tolls	—		—		(63	)
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Other services rendered	—		—		88
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Energy purchases	—		—		194
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Other fixed operating expenses	—		(234	)	(1,214	)
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Other operating income	—		10		4
96.806.130-5	Electrogas S.A. (*)	Chile	Associate	Tolls	—		—		(1,309	)
96.806.130-5	Electrogas S.A. (*)	Chile	Associate	Fuel consumption	—		—		259
Foreign	Endesa Operaciones y Servicios	Spain	Common Immediate Parent	Other services rendered	231		259		—
Foreign	Endesa Operaciones y Servicios	Spain	Common Immediate Parent	Other operating income	—		—		231
Foreign	PH Chucas Costa Rica	Costa Rica	Common Immediate Parent	Other services rendered	—		—		—
Foreign	Enel Ingegneria e Ricerca	Italy	Common Immediate Parent	Other services rendered	—		—		9
Foreign	Enel Ingegneria e Ricerca	Italy	Common Immediate Parent	Other fixed operating expenses	—		—		(2,487	)
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Energy purchases	—		—		9,101
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Other operating income	—		—		25
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Other services rendered	—		—		3,280
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Other fixed operating expenses	—		—		(7	)
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Tolls	—		—		(1,926	)
77.017.930-0	Transmisora Eléctrica de Quillota Ltda. (*)	Chile	Joint Venture	Tolls	—		—		(364	)
Foreign	Endesa España	Spain	Common Immediate Parent	Other fixed operating expenses	(149	)	(150	)	(170	)
Foreign	Enel Trade S.p.A	Italy	Common Immediate Parent	Other operating income	—		—		71
Foreign	Enel Trade S.p.A	Italy	Common Immediate Parent	Other fixed operating expenses	(2,055	)	(1,249	)	(821	)
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Energy purchases	—		—		(1,208	)
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Tolls	—		—		(60	)
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Other services rendered	—		—		53
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Energy purchases	—		—		51
76.052.206-6	Parque Eolico Valle de los Vientos S.A. (*)	Chile	Common Immediate Parent	Energy purchases	—		—		(4,155	)
76.052.206-6	Parque Eolico Valle de los Vientos S.A. (*)	Chile	Common Immediate Parent	Energy purchases	—		—		206
Foreign	Enel S.p.A.	Italy	Parent	Other fixed operating expenses	(1,016	)	(12,758	)	(18,284	)
Foreign	Enel S.p.A.	Italy	Parent	Other fixed operating expenses	(2,144	)	(1,686	)	—
Foreign	Enel S.p.A.	Italy	Parent	Other operating income	608		593		153
Foreign	Enel Italia Servizi SRL	Italy	Common Immediate Parent	Other fixed operating expenses	(16,630	)	(16,805	)	—
Foreign	Enel Italia	Italy	Common Immediate Parent	Other fixed operating expenses	(1,505	)	—		(6,120	)
76.179.024-2	Parque Eolico Tal Tal S.A. (*)	Chile	Common Immediate Parent	Energy purchases	—		—		(6,480	)
76.179.024-2	Parque Eolico Tal Tal S.A. (*)	Chile	Common Immediate Parent	Energy purchases	—		—		38
Foreign	Enel Produzione	Italy	Common Immediate Parent	Other fixed operating expenses	(641	)	(532	)	(487	)
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	Other services rendered	—		54		19
Foreign	Enel Green Power Italia	Italy	Common Immediate Parent	Other fixed operating expenses	—		(93	)	(192	)
96.800.570-7	Enel Distribución Chile S.A. (Ex Chilectra S.A.)	Chile	Common Immediate Parent	Sale of Materials	—		—		5,204
96.800.570-7	Enel Distribución Chile S.A. (Ex Chilectra S.A.)	Chile	Common Immediate Parent	Other fixed operating expenses	(55	)	(169	)	(262	)
96.800.570-7	Enel Distribución Chile S.A. (Ex Chilectra S.A.)	Chile	Common Immediate Parent	Other financial income	—		—		49
96.800.570-7	Enel Distribución Chile S.A. (Ex Chilectra S.A.)	Chile	Common Immediate Parent	Other services rendered	—		—		(19	)
91.081.000-6	Enel Generación Chile S.A. (Ex Endesa S.A.)	Chile	Common Immediate Parent	Other financial income	—		—		1,543
91.081.000-6	Enel Generación Chile S.A. (Ex Endesa S.A.)	Chile	Common Immediate Parent	Other services rendered	—		—		77
91.081.000-6	Enel Generación Chile S.A. (Ex Endesa S.A.)	Chile	Common Immediate Parent	Other fixed operating expenses	(73	)	(264	)	(4,244	)
96.770.940-9	Celta	Chile	Common Immediate Parent	Other fixed operating expenses	—		—		(599	)
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Other operating income	—		—		79
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Other services rendered	—		—		128
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Other fixed operating expenses	—		(3,328	)	(3,381	)
76.788.080-4	Gas Atacama Chile	Chile	Common Immediate Parent	Other fixed operating expenses	(443	)	(465	)	—
76.536.353-5	Enel Chile S.A. (Ex Enersis Chile)	Chile	Common Immediate Parent	Other financial expenses	—		—		(490	)
76.536.353-5	Enel Chile S.A. (Ex Enersis Chile)	Chile	Common Immediate Parent	Other services rendered	(8,128	)	—		4,244
76.536.353-5	Enel Chile S.A. (Ex Enersis Chile)	Chile	Common Immediate Parent	Other fixed operating expenses	—		(3,931	)	(8,055	)
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	Other financial income	—		431		—
76.536.353-5	Enel Chile S.A.	Chile	Common Immediate Parent	Other operating income	—		16		—
Foreign	Yacylec	Argentina	Associate	Other services rendered	8		14		15
Foreign	Yacylec	Argentina	Associate	Other services rendered	—		—		(150	)
Foreign	Yacylec	Argentina	Associate	Other fixed operating expenses	(101	)	(162	)	—
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	Other fixed operating expenses	(619	)	(143	)	(94	)
76.126.507-5	Parque Eolico Talinay Oriente SA (*)	Chile	Common Immediate Parent	Energy purchases	—		—		59
76.126.507-5	Parque Eolico Talinay Oriente SA (*)	Chile	Common Immediate Parent	Energy purchases	—		—		(150	)
Foreign	Enel Energía	Italy	Common Immediate Parent	Other operating income	3		88		—
Foreign	Enel Green Power Colombia	Colombia	Common Immediate Parent	Other services rendered	314		263		—
Foreign	Enel Green Power Argentina	Argentina	Common Immediate Parent	Other services rendered	—		589		—
Foreign	Enel Green Power North America Inc.	United States	Common Immediate Parent	Other services rendered	24		6		—
Foreign	Enel Fortuna S.A.	Panama	Common Immediate Parent	Other fixed operating expenses	(122	)	(58	)	—
Foreign	Enel Green Power SPA	Italy	Common Immediate Parent	Other fixed operating expenses	(3,307	)	(81	)	—
Foreign	Grupo Enel Green Power Brasil Participações Ltda	Brazil	Common Immediate Parent	Energy purchases	24,333		31,250		5,411
Foreign	Grupo Enel Green Power Brasil Participações Ltda	Brazil	Common Immediate Parent	Energy sales	(126,627	)	(108,947	)	(36,486	)
Foreign	Grupo Enel Green Power Brasil Participações Ltda	Brazil	Common Immediate Parent	Tolls	196		160		—
Foreign	Grupo Enel Green Power Brasil Participações Ltda	Brazil	Common Immediate Parent	Other fixed operating expenses	—		12		280
Foreign	Enel Iberia SRL	Spain	Common Immediate Parent	Other fixed operating expenses	(283	)	—		—
Foreign	Enel Global Thermal Generation SRL	Italy	Common Immediate Parent	Other fixed operating expenses	(5,561	)	—		—
Foreign	Enel Green Power Peru (USD)	Perú	Common Immediate Parent	Tolls	(2,089	)	—		—
Foreign	Enel Green Power Peru (USD)	Perú	Common Immediate Parent	Energy purchases	(2,802	)	—		—
Foreign	Enel Green Power Peru (USD)	Perú	Common Immediate Parent	Other services rendered	2,371		—		—
Foreign	Proyectos Y Soluciones Renovables S.A.C.	Perú	Common Immediate Parent	Other services rendered	3		—		—
Foreign	Enel Map	Italy	Common Immediate Parent	Other fixed operating expenses	(15,986	)	—		—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	Other fixed operating expenses	(2,238	)	—		—
Foreign	Energética Monzon S.A.C.	Perú	Common Immediate Parent	Other services rendered	380		—		—
Foreign	Endesa Distribución Eléctrica	Spain	Common Immediate Parent	Other fixed operating expenses	(282	)	—		—
Foreign	ENEL X S.R.L.	Italy	Common Immediate Parent	Other fixed operating expenses	(327	)	—		—
Foreign	Enel Finance International NV	Holland	Common Immediate Parent	Other financial expenses	(43,873	)	—		—
				Total	(210,274	)	(120,141	)	(123,198	)

Transfers of short-term funds between related companies are treated as current accounts changes, with variable interest rates based on market conditions used for the monthly balance. The resulting amounts receivable or payable are usually at 30 days term, with automatic rollover for the same periods and amortization in line with cash flows.

d)    Significant transactions Enel Américas:

·      In May 2017, Enel Américas S.A. granted short-term loans to Enel Chile S.A. for ThCh$150,000,000 (ThUS$224,075), which were fully amortized on May 25, 2017. These c + 0.05% per month. As at December 31, 2018, there was no outstanding debt between Enel Américas S.A. and Enel Chile S.A.

·      On September 26, 2018, Enel Finance International NV executed with Enel Brasil a credit agreement in Reals for the amount of R$ 9,400 million (about US$2,500 million), which was actually disbursed on October 5, 2018 as a fixed rate of 7.676% and maturity on July 2, 2019. The funds were used for the prepayment of promissory notes held by Enel Brasil and Enel Sudeste issued for the purchase of Eletropaulo, currently Enel Distribución Sao Paulo.

F-107

13.2   Board of directors and key management personnel

The Company is managed by a Board of Directors which consists of seven members. Each director serves for a three-year term after which they can be reelected.

The Board of Directors as of December 31, 2018 was elected at the Ordinary Shareholders Meeting held on April 28, 2017, and is composed of the following members:

Mr. Francisco de Borja Acha Besga

Mr. José Antonio Vargas Lleras

Mr. Livio Gallo

Mr. Enrico Viale

Mr. Hernán Somerville Senn

Mr. Patricio Gómez Sabaini

Mr. Domingo Cruzat Amunátegui

At the Board of Directors’ meeting held on April 29, 2016, Mr. Francisco de Borja Acha Besga was appointed as Chairman of the Board, Mr. José Antonio Vargas Lleras was appointed as Vice Chairman of the Board and Mr. Domingo Cruzat Amunátegui was appointed as Secretary of the Board.

Likewise, at the same Board of Directors Meeting, the Directors’ Committee was elected under the requirements of Law No. 18,046 on Corporations and the Sarbanes-Oxley Act. The Directors’ Committee is composed of the following independent directors: Mr. Hernán Sommerville Senn (as Chairman), Mr. Patricio Gómez Sabaini and Mr. Domingo Cruzat Amunátegui (as Secretary).

The Board of Directors determined that Mr. Hernan Sommerville Senn is a financial expert for the Directors’ Committee of the Company.

a)   Accounts receivable and payable and other transactions

·Accounts receivable and payable

There are no outstanding amounts receivable or payable between the Company and the members of the Board of Directors and key management personnel.

·Other transactions

No transactions other than the payment of compensations have taken place between the Company and the members of the Board of Directors and key management personnel and other than transactions in the normal course of business-electricity supply.

b)   Compensation for directors

In accordance with Article 33 of Law No. 18,046 governing stock corporations, the compensation of Directors is established each year at the Ordinary Shareholders Meeting of the Company.

The compensation consists of paying a variable annual compensation equal to one one-thousandth of the profit for the year (attributable to shareholders of Enel Américas). Also, each member of the Board of Directors will be paid a monthly compensation, one part 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 per diem for each Board meeting attended with a maximum of 16 sessions in total.

F-108

According to the provisions of the bylaws, the remuneration of the Board of Director Chairman 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 affiliated, or acts as director or consultant for other domestic or foreign companies or legal entities in which Enel Américas S.A. has direct or indirect interest, he/she may receive remuneration only in one of said Board 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 in any of the domestic or foreign Enel Américas S.A.’s 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 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 a monthly compensation, one part in a fixed monthly fee and another part dependent on meetings attended.

This compensation is broken down as follows:

·    UF 72.00 as a fixed monthly fee, in any event, and

·    UF 26.40 as per diem for each Board meeting attended.

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, 2018, 2017 and 2016:

			December 31, 2018
Taxpayer ID				Enel Américas Board	Board of Subsidiaries	Directors’ Committee
No.	Name	Position	Period in position	ThUS$	ThUS$	ThUS$
Foreigner	Francisco de Borja Acha Besga (1)	Chairman	January - December 2018	—	—	—
Foreigner	José Antonio Vargas Lleras (2)	Vice Chairman	January - December 2018	—	—	—
Foreigner	Enrico Viale (4)	Director	January - December 2018	—	—	—
Foreigner	Livio Gallo (3)	Director	January - December 2018	—	—	—
4.132.185-7	Hernán Somerville Senn	Director	January - December 2018	166	—	50
Foreigner	Patricio Gómez Sabaini (5)	Director	January - December 2018	163	—	50
6.989.304-K	Domingo Cruzat Amunátegui (6)	Director	January - December 2018	166	—	50
	TOTAL			495	—	150

			December 31, 2017
Taxpayer ID				Enel Américas Board	Board of Subsidiaries	Directors’ Committee
No.	Name	Position	Period in position	ThUS$	ThUS$	ThUS$
Foreigner	Francisco de Borja Acha Besga (1)	Chairman	January - December 2017	—	—	—
Foreigner	José Antonio Vargas Lleras (2)	Vice Chairman	January - December 2017	—	—	—
Foreigner	Enrico Viale (4)	Director	January - December 2017	—	—	—
Foreigner	Livio Gallo (3)	Director	January - December 2017	—	—	—
4.132.185-7	Hernán Somerville Senn	Director	January - December 2017	121	—	40
Foreigner	Patricio Gómez Sabaini (5)	Director	January - December 2017	121	—	39
6.989.304-K	Domingo Cruzat Amunátegui (6)	Director	January - December 2017	119	—	39
	TOTAL			361	—	118

F-109

			December 31, 2016
Taxpayer ID				Enel Américas Board	Board of Subsidiaries	Directors’ Committee
No.	Name	Position	Period in position	ThUS$	ThUS$	ThUS$
5.710.967-K	Pablo Yrarrazaval Valdés	Chairman	January - October 2014	—	—	—
Foreigner	Francisco de Borja Acha Besga	Chairman	January -June 2016	—	—	—
Foreigner	José Antonio Vargas Lleras	Vice Chairman	May - June 2016	—	—	—
Foreigner	Franceso Starace	Vice Chairman	January - April 2016	—	—	—
4.975.992-4	Hernan Chadwick Piñera	Director	January -June 2016	37	—	12
Foreigner	Enrico Viale	Director	May - June 2016	—	—	—
Foreigner	Livio Gallo	Director	May - June 2016	—	—	—
6.429.250-1	Rafael Fernández Morandé	Director	January - April 2016	37	—	12
4.132.185-7	Hernán Somerville Senn	Director	January - December 2016	105	—	35
Foreigner	Patricio Gómez Sabaini	Director	May - December 2016	74	—	25
6.989.304-K	Domingo Cruzat Amunátegui	Director	May - December 2016	74	—	25
5.719.922-9	Leonidas Vial Echeverria	Director	January -June 2016	—	—	—
Foreigner	Alberto de Paoli	Director	January - April 2016	—	—	—
Foreigner	Francesca Di Carlo	Director	January - April 2016	—	—	—
	TOTAL			327	—	109

(1)On September 30, 2015, Mr. Francisco Borja Ascha Besga was appointed as Chairman, and he was again appointed as Chairman on April 29, 2016. He is not compensated.

(2)Mr. José Antonio Vargas Lleras was appointed as Vice Chairman on April 29, 2016. He is not compensated.

(3)Mr. Livio Gallo was designated as Director of the Board on April 28, 2016. He is not compensated.

(4)Mr. Enrico Viale was appointed as Director of the Board on April 28, 2016. He is not compensated.

(5)Mr. Patricio Gómez Sabaini was appointed as Director of the Board on April 28, 2016.

(6)Mr. Domingo Cruzat Amunátegui was appointed as Director of the Board on April 28, 2016.

c)   Guarantees given by the Company in favor of the directors

No guarantees have been given to the directors.

13.3   Compensation for key management personnel

a)   Remunerations received by key management personnel

Key Management Personnel
Taxpayer ID No.	Name	Position
Foreigner	Maurizio Bezzeccheri (1)	Chief Executive Officer
Foreigner	Aurelio Ricardo Bustilho de Oliveira (2)	Administration, Finance and Control Officer
Foreigner	Bruno Stella (3)	Planning and Control Officer
Foreigner	Raffaele Cutrignelli (4)	Internal Audit Officer
15.307.846-7	José Miranda Montecinos (5)	Communications Officer
6.973.465-0	Domingo Valdés Prieto	General Counsel and Secretary to the Board

Mr. José Miranda Montecinos and Mr. Domingo Valdés Prieto, are personnel of Enel Américas, exclusively compensated by Enel Chile S.A. who is the employer, but render executive services to the Company pursuant to an intercompany agreement between both entities.

(1)Mr. Maurizio Bezzeccheri was appointed on August 1, 2018 as General Manager replacing Mr. Luca D’Agnese who resigned voluntarily, rendering services until July 31, 2018.

(2)Mr. Paolo Pallotti resigned voluntarily, rendering services until September 30, 2018. As replacement, Mr. Aurelio Ricardo Bustilho de Oliveira was appointed as from October 1, 2018.

(3)Mr. Bruno Stella was appointed on July 1, 2018 as Planning and Control Manager replacing Mr. Emanuele Brandolini.

(4)Mr. Raffaele Cutrignelli was appointed on October 1, 2016 as Internal Audit Manager.

(5)Mr. José Miranda Montecinos was appointed on December 1, 2014 as Manager of Communications.

F-110

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,
	2018	2017	2016
	ThUS$	ThUS$	ThUS$
Cash compensation	2,586	4,046	4,917
Short-term benefits for employees	21	119	245
Other long-term benefits	—	—	86
Total	2,607	4,165	5,248

b)   Guarantees established by the Company in favor of key management personnel

No guarantees have been given to key management personnel.

13.4    Compensation plans linked to share price

There are no payment plans granted to the Directors or key management personnel based on the share price of the Company.

14.  INVENTORIES

The detail of inventories as of December 31, 2018 and 2017 is as follows:

	Balance as of
	12-31-2018	12-31-2017
Classes of Inventories	ThUS$	ThUS$
Supplies for Production	29,959	25,989
Oil	23,128	16,232
Coal	6,831	9,757
Spare parts	27,828	23,102
Electrical materials	281,611	196,998
Total	339,398	246,089

There are no inventories pledged as security for liabilities.

For the years ended December 31, 2018, 2017 and 2016, raw materials and inputs recognized as fuel cost amount to ThUS$226,843, ThUS$229,308 and ThUS$362,156 respectively (see Note 29).

For the years ended December 31, 2018 and 2017 there have been no impairments recognized in inventories.

F-111

15.  CURRENT TAX ASSETS AND LIABILITIES

a) The detail of current tax receivables as of December 31, 2018 and 2017 is as follows:

	Balance as of
	12-31-2018	12-31-2017
Tax Receivables	ThUS$	ThUS$
Monthly provisional tax payments	44,798	43,235
Other	6,196	4,158
Total	50,994	47,393

b)  The detail of current tax payables as of December 31, 2018 and 2017, is as follows:

	Balance as of
	12-31-2018	12-31-2017
Tax Payables	ThUS$	ThUS$
Income tax	192,924	172,638
Total	192,924	172,638

F-112

16.  INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD

16.1.   Investments accounted for using the equity method

a.    The following tables present the changes in shareholders’ equity of the Group’s equity method investments during the years ended December 31, 2018 and 2017:

															Other		Argentine
					Ownership		Balance as of		Share of		Dividends		Foreign Currency		Comprehensive	Other	hyperinflationary	Balance as of	Negative	Balance as of
Taxpayer ID				Functional	Interest		1/1/2018	Additions	Profit (Loss)		Declared		Translation		Income	Increase (Decrease)	economy	12/31/2018	equity provision	12/31/2018
No,	Associates and Joint Ventures	Relationship	Country	Currency	%		ThUS$	ThUS$	ThUS$		ThUS$		ThUS$		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreigner	Yacylec S.A.	Associate	Argentina	Argentine peso	22.22	%	1,221	—	441		(1,145	)	39		—	—	—	556	—	556
Foreigner	Sacme S.A.	Associate	Argentina	Argentine peso	50.00	%	14	—	(160	)	—		(258	)	—	—	640	236	—	236
Foreigner	Central Termica Manuel Belgrano	Associate	Argentina	Argentine peso	25.60	%	830	—	1,027		(453	)	(536	)	—	—	—	868	—	868
Foreigner	Central Termica San Martin	Associate	Argentina	Argentine peso	25.60	%	671	—	1,144		(422	)	(462	)	—	—	—	931	—	931
Foreigner	Central Vuelta Obligado S.A.	Associate	Argentina	Argentine peso	40.90	%	11	—	—		—		(6	)	—	—	—	5	—	5
					TOTAL		2,747	—	2,452		(2,020	)	(1,223	)	—	—	640	2,596	—	2,596

														Other		Argentine
					Ownership		Balance as of		Share of	Dividends		Foreign Currency		Comprehensive	Other	hyperinflationary	Balance as of	Negative		Balance as of
Taxpayer ID				Functional	Interest		1/1/2017	Additions	Profit (Loss)	Declared		Translation		Income	Increase (Decrease)	economy	12/31/2017	equity provision		12/31/2017
No,	Associates and Joint Ventures	Relationship	Country	Currency	%		ThUS$	ThUS$	ThUS$	ThUS$		ThUS$		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$
Foreigner	Yacylec S.A.	Associate	Argentina	Argentine peso	22.22	%	—	—	1,606	—		(177	)	—	—	—	1,429	(208	)	1,221
Foreigner	Sacme S.A.	Associate	Argentina	Argentine peso	50.00	%	17	—	—	—		(3	)	—	—	—	14	—		14
Foreigner	Central Termica Manuel Belgrano	Associate	Argentina	Argentine peso	25.60	%	971	—	1,101	(1,076	)	(166	)	—	—	—	830	—		830
Foreigner	Central Termica San Martin	Associate	Argentina	Argentine peso	25.60	%	769	—	603	(565	)	(136	)	—	—	—	671	—		671
Foreigner	Central Vuelta Obligado S.A.	Associate	Argentina	Argentine peso	40.90	%	13	—	—	—		(2	)	—	—	—	11	—		11
					TOTAL		1,770	—	3,310	(1,641	)	(484	)	—	—	—	2,955	(208	)	2,747

b.Additional financial information on investments in associates:

·Investments with significant influence

The following tables set forth financial information as of December 31, 2018 and 2017, from the Financial Statements of the investments in associates where the Group has significant influence:

December 31, 2018

Ownership Interest 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.

22.22

%

2,914

732

1,032

110

2,984

(1,282

)

1,702

179

1,881

December 31, 2017

Ownership Interest 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.

22.22

%

9,491

811

4,559

249

13,923

(6,666

)

7,257

(799

)

6,458

None of our associates have published price quotations.

There are no significant commitments and contingencies, or restrictions to the availability of funds in associated companies and joint ventures.

F-113

17.  INTANGIBLE ASSETS OTHER THAN GOODWILL

The following table presents intangible assets other than Goodwill as of December 31, 2018 and 2017:

Intangible Assets, Gross	12-31-2018 ThUS$	12-31-2017 ThUS$
Intangible Assets, Gross	10,257,585	6,423,636
Easements and water rights	61,445	58,147
Concessions	9,917,051	6,156,560
Development costs	13,928	15,180
Patents, registered trademarks and other rights	28,947	39,411
Computer software	234,419	146,509
Other identifiable intangible assets	1,795	7,829

Intangible Assets, Amortization and Impairment	12-31-2018 ThUS$		12-31-2017 ThUS$
Accumulated Amortization and Impairment, Total	(4,430,296	)	(2,741,157	)
Identifiable Intangible Assets	(4,430,296	)	(2,741,157	)
Easements and water rights	(18,210	)	(15,665	)
Concessions	(4,279,664	)	(2,622,625	)
Development costs	(9,673	)	(13,124	)
Patents, registered trademarks and other rights	(14,829	)	(14,158	)
Computer software	(106,201	)	(73,210	)
Other identifiable intangible assets	(1,719	)	(2,375	)

Intangible Assets, Net	12-31-2018 ThUS$	12-31-2017 ThUS$
Intangible Assets, Net	5,827,289	3,682,479
Easements and water rights	43,235	42,482
Concessions, Net(1) (*)	5,637,387	3,533,935
Development costs	4,255	2,056
Patents, registered trademarks and other rights	14,118	25,253
Computer software	128,218	73,299
Other identifiable intangible assets	76	5,454

The detail of concessions is the following:

Concession Holder	12-31-2018 ThUS$	12-31-2017 ThUS$
Enel Distribución Río S.A. (ex Ampla)	716,210	1,006,398
Enel Distribución Ceará S.A. (ex Coelce)	586,767	705,638
CELG Distribución S.A.	1,500,934	1,821,899
Enel Distribución Sao Paulo S.A.	2,833,476	—
TOTAL	5,637,387	3,533,935

(*)See Note 4d.1.

F-114

The reconciliations of the carrying amounts of intangible assets during the years ended December 31, 2018 and 2017 are as follows:

Changes in Intangible Assets	Development Costs ThUS$		Easements ThUS$		Concessions ThUS$		Patents, Registered Trademarks and Other Rights ThUS$		Computer Software ThUS$		Other Identifiable Intangible Assets ThUS$		Intangible Assets, Net ThUS$
Opening balance as of January 1, 2018	2,056		42,482		3,533,935		25,253		73,299		5,454		3,682,479
Changes in identifiable intangible assets:													—
Increases other than from business combinations	(23	)	6,828		523,510		6,236		56,825				593,376
Acquisitions made through business combinations	—		—		2,914,866		—		—		—		2,914,866
Increase (decrease) from foreign currency translation differences, net	(275	)	(5,172	)	(840,315	)	(1,132	)	(20,753	)	(7	)	(867,654	)
Amortization	(524	)	(1,653	)	(349,932	)	(1,995	)	(12,865	)	(28	)	(366,997	)
Increases (decreases) from transfers and other changes	—		1,647		(1,506	)	40		5,162		(5,343	)	—
Increases (decreases) from transfers			1,647		(1,506	)	40		5,162		(5,343	)	—
Disposals and removal from service	—		—		(34,273	)	—		—		—		(34,273	)
Removals from service	—		—		(34,273	)							(34,273	)
Argentine hyperinflationary economy									12,155				12,155
Other increases (decreases)	3,021		(897	)	(108,898	)	(14,284	)	14,395				(106,663	)
Total changes in identifiable intangible assets	2,199		753		2,103,452		(11,135	)	54,919		(5,378	)	2,144,810
Closing balance as of December 31, 2018	4,255		43,235		5,637,387		14,118		128,218		76		5,827,289

							Patents, Registered
	Development						Trademarks and		Computer		Other Identifiable		Intangible Assets,
	Costs		Easements		Concessions		Other Rights		Software		Intangible Assets		Net
Changes in Intangible Assets	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Opening balance as of January 1, 2017	11,560		40,956		1,683,978		18,849		49,334		5,481		1,810,158
Changes in identifiable intangible assets:													—
Increases other than from business combinations	611		2,453		825,256		8,184		34,569		—		871,073
Acquisitions made through business combinations					1,824,275								1,824,275
Increase (decrease) from foreign currency translation differences, net	272		656		(80,562	)	69		(2,483	)	1		(82,047	)
Amortization	(505	)	(1,776	)	(226,046	)	(1,808	)	(10,416	)	(28	)	(240,579	)
Increases (decreases) from transfers and other changes	12		40		(133	)	19		62		—		—
Increases (decreases) from transfers	12		40		(133	)	19		62		—		—
Increases (decreases) from other changes	—		—		—		—		—		—		—
Disposals and removal from service	(9,894	)	—		(7,087	)	(60	)	(259	)	—		(17,300	)
Disposals	—		—		—		—		—		—		—
Removals from service	(9,894	)	—		(7,087	)	(60	)	(259	)	—		(17,300	)
Other increases (decreases)	—		153		(485,746	)	—		2,492		—		(483,101	)
Total changes in identifiable intangible assets	(9,504	)	1,526		1,849,957		6,404		23,965		(27	)	1,872,321
Closing balance as of December 31, 2017	2,056		42,482		3,533,935		25,253		73,299		5,454		3,682,479

For the year ended December 31, 2018, the main additions to intangible assets for concessions for ThUS$523,510 mainly come from Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Sao Paulo S.A. and Enel Distribución Goias for investments in networks and extensions in order to optimize their operation, so that to improve the efficiency and quality of the service level recoded under the item of concessions according to CINIIF 12 (see Note 4.d.1). For 2017, the main additions to intangible assets for a total of ThUS$825,256 mainly come from Enel Distribución Rio S.A., Enel Distribución Ceará S.A. and Enel Distribución Goias.

Additions of intangible assets for the years ended December 31, 2018 and 2017 amounted to ThUS$593,376 and ThUS$871,073, respectively.

The amortization of intangible assets amounted to ThUS$351,114 and ThUS$240,579 for the years ended December 31, 2018 and 2017, respectively, which are presented net of PIS and COFINS taxes in the Brazilian subsidiaries.

During the years ended December 31, 2018, 2017 and 2016 the expenses for personnel directly related to constructions in progress were activated for the item of concessions for the amount of ThUS$82,662, ThUS$68,186 and ThUS$24,407 respectively.

F-115

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, 2018 and 2017 (See Note 4.e).

As of December 31, 2018 and 2017, the Company has no intangible assets of indefinite useful life that can represent significant amounts.

18.   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, 2018 and 2017:

		Opening	Foreign		Closing				Argentine	Closing
		balance	Currency		balance	Business	Foreign Currency		hyperinflationary	balance
		1/1/2017	Translation		12/31/2017	combination	Translation		economy	12/31/2018
Company	Cash Generating Unit	ThUS$	ThUS$		ThUS$	ThUS$	ThUS$		ThUS$	ThUS$
Enel Distribución Río S.A. (formerly Ampla)	Enel Distribución Río S.A.	260,989	(4,331	)	256,658	—	(37,278	)	—	219,380
Compañía Distribuidora y Comercializadora de Energía S.A.	Compañía Distribuidora y Comercializadora de Energía S.A.	14,395	119		14,514	—	(1,171	)	—	13,343
Enel Generación El Chocón S.A.	Enel Generación El Chocón S.A.	6,679	(1,123	)	5,556	—	(17,227	)	37,926	26,255
Enel Distribución Perú S.A.	Enel Distribución Perú	68,704	2,594		71,298	—	(2,951	)	—	68,347
EGP Cachoeira Dourada S.A.	EGP Cachoeira Dourada S.A.	95,698	(1,584	)	94,114	—	(13,673	)	—	80,441
Enel Generación Perú S.A.	Enel Generación Perú	129,315	4,882		134,197	—	(5,554	)	—	128,643
Emgesa S.A. E.S.P.	Emgesa S.A. E.S.P.	6,368	53		6,421	—	(519	)	—	5,902
Generalima S.A.	Enel Distribución Perú	20	1		21	—	(1	)	—	20
Enel Brasil S.A.	Enel Brasil S.A.	1,215	(20	)	1,195	—	(174	)	—	1,021
Enel Distribución Ceará S.A. (formerly Coelce)	Enel Distribución Ceará S.A.	131,375	(2,174	)	129,201	—	(18,772	)	—	110,429
Enel Distribucion Sao Paulo	Enel Distribucion Sao Paulo	—	—		—	563,858	(12,069	)	—	551,789
Total		714,758	(1,583	)	713,175	563,858	(109,389	)	37,926	1,205,570

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, 2018 (see Note 4.e).

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 Ampla Energía) 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. Enel Distribución Ceará S.A. (formerly Compañía Energética Do Ceará S.A.)

Between 1998 and 1999, the Company and our 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.

3. Compañía Distribuidora y Comercializadora de Energía S.A. (Codensa)

On October 23, 1997, Enel Américas S.A. and our 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.

F-116

4. 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.

5. Enel Distribución Perú S.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.

6. EGP Cachoeira Dourada S.A.

On September 5, 1997, our former subsidiary Enel Generación Chile S.A. acquired 79% of EGP Cachoeira Dourada S.A. in the state of Goias in a public bidding process held by the Brazilian government.

7. Enel Generación Perú S.A. (formerly Edegel S.A.A.)

On October 9, 2009, in a transaction on the Lima Stock Exchange in Peru, our former subsidiary Enel Generación Chile S.A. acquired an additional 29.3974% equity interest in Enel Generación Perú S.A.

8. Emgesa S.A. E.S.P.

On October 23, 1997, our 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.

9. Enel Distribución Sao Paulo S.A.

On June 7, 2018, our subsidiary Enel Brasil acquired majority stock ownership in Enel Distribución Sao Paulo S.A. (see Note 7.2).

F-117

19.   PROPERTY, PLANT AND EQUIPMENT

The following table sets forth the property, plant and equipment as of December 31, 2018 and 2017:

	12-31-2018	12-31-2017
Classes of Property, Plants and Equipment, Gross	ThUS$	ThUS$
Property, Plants and Equipment, Gross	15,700,505	12,994,643
Construction in progress	1,059,070	829,559
Land	163,660	155,485
Buildings	284,496	215,100
Plant and equipment	7,318,697	6,513,960
Network Infrastructure	6,210,147	4,758,475
Fixtures and fittings	413,689	293,738
Other property, plant and equipment under finance lease	250,746	228,326

	12-31-2018		12-31-2017
Classes of Accumulated Depreciation and Impairment in Property, Plants and Equipment	ThUS$		ThUS$
Total Accumulated Depreciation and Impairment in Property, Plants and Equipment	(7,013,678	)	(4,902,176	)
Buildings	(147,041	)	(87,543	)
Plant and equipment	(3,596,514	)	(2,562,137	)
Network Infrastructure	(2,984,132	)	(2,026,878	)
Fixtures and fittings	(218,600	)	(180,655	)
Other property, plant and equipment under finance lease	(67,391	)	(44,963	)

	12-31-2018	12-31-2017
Classes of Property, Plants and Equipment, Net	ThUS$	ThUS$
Property, Plants and Equipment, Net	8,686,827	8,092,467
Construction in progress	1,059,070	829,559
Land	163,660	155,485
Buildings	137,455	127,557
Plant and equipment	3,722,183	3,951,823
Network Infrastructure	3,226,015	2,731,597
Fixtures and fittings	195,089	113,083
Other property, plant and equipment under finance lease	183,355	183,363

F-118

The detail and changes in property, plant, and equipment during the years ended December 31, 2018 and 2017 are as follows:

	Construction in Progress		Land		Buildings		Plant and Equipment		Network Infrastructure		Fixtures and Fittings		Other Property, Plant and Equipment under Finance Lease		Property, Plant and Equipment, Net
Changes in 2018	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Opening balance as of January 1, 2018	829,559		155,485		127,557		3,951,823		2,731,597		113,083		183,363		8,092,467
Increases other than from business combinations	795,114		2,781		—		10,505		—		11,325		3,342		823,067
Acquisitions through business combinations	—		—		—		—		—		—		18,036		18,036
Increases (decreases) from foreign currency translation differences, net	(248,533	)	(21,014	)	(28,793	)	(443,320	)	(850,680	)	(26,004	)	(8,610	)	(1,626,954	)
Depreciation	—		—		(6,969	)	(275,444	)	(194,488	)	(23,311	)	(11,220	)	(511,432	)
Impairment (losses) reversals recognized in profit or loss	—		—		—		66,988		—		—		—		66,988
Increases (decreases) from transfers and other changes	(555,758	)	5,203		7,625		174,583		274,079		97,063		(2,795	)	—
Increases (decreases) from transfers from construction in progress	(555,758	)	5,203		7,625		174,583		274,079		97,063		(2,795	)	—
Disposals and removal from service	(354	)	(836	)	(5	)	(11,016	)	(6,323	)	(551	)	(251	)	(19,336	)
Disposals	—		(820	)	(5	)	—		—		(59	)	—		(884	)
Removals	(354	)	(16	)	—		(11,016	)	(6,323	)	(492	)	(251	)	(18,452	)
Decreases to be classified as maintained to distribute to owners	—		—		—		(5,825	)	—		—		—		(5,825	)
Argentine hyperinflationary economy	221,193		22,045		37,959		260,229		1,246,868		8,194		—		1,796,488
Other increases (decreases)	17,849		(4	)	81		(6,340	)	24,962		15,290		1,490		53,328
Total changes	229,511		8,175		9,898		(229,640	)	494,418		82,006		(8	)	594,360
Closing balance as of December 31, 2018	1,059,070		163,660		137,455		3,722,183		3,226,015		195,089		183,355		8,686,827

	Construction in Progress		Land		Buildings		Plant and Equipment		Network Infrastructure		Fixtures and Fittings		Other Property, Plant and Equipment under Finance Lease		Property, Plant and Equipment, Net
Changes in 2017	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Opening balance as of January 1, 2017	848,636		151,430		106,212		4,013,530		2,349,651		93,653		130,044		7,693,156
Increases other than from business combinations	815,269		3		13		6,338		—		3,454		326		825,403
Acquisitions through business combinations	—		—		—		—		—		13,212		—		13,212
Increases (decreases) from foreign currency translation differences, net	(37,686	)	1,646		(1,362	)	18,836		(66,040	)	(3,930	)	4,936		(83,600	)
Depreciation	—		—		(4,729	)	(216,852	)	(151,856	)	(21,403	)	(12,695	)	(407,535	)
Impairment (losses) reversals recognized in profit or loss	—		—		—		(10,242	)	54,819		—		—		44,577
Increases (decreases) from transfers and other changes	(796,707	)	2,631		23,609		141,901		547,973		17,961		62,632		—
Increases (decreases) from transfers from construction in progress	(796,707	)	2,631		23,609		141,901		547,973		17,961		62,632		—
Disposals and removals from service	(111	)	(169	)	(267	)	(488	)	(3,007	)	(2,975	)	(73	)	(7,090	)
Disposals	5		(169	)	(244	)	—		—		(3	)	—		(411	)
Removals	(116	)	—		(23	)	(488	)	(3,007	)	(2,972	)	(73	)	(6,679	)
Other increases (decreases)	158		(56	)	4,081		(1,200	)	57		13,111		(1,807	)	14,344
Total changes	(19,077	)	4,055		21,345		(61,707	)	381,946		19,430		53,319		399,311
Closing balance as of December 31, 2017	829,559		155,485		127,557		3,951,823		2,731,597		113,083		183,363		8,092,467

Additional information on property, plants and equipment, net

a)Main investments

The main additions to property, plant and equipment correspond to investments in operating plants and new projects for ThUS$823,067 and ThUS$825,403 for the years ended December 31, 2018 and 2017, respectively.

In the generation business, investments in combined cycle power and hydroelectric power stations in the subsidiaries Enel Generación Perú S.A., Emgesa and Enel Generación Costanera, should be mentioned comprising additions for the year ended December 31, 2018 for ThUS$283,241 (for the year ended December 31, 2017 investments in combined cycle and hydroelectric power stations in the subsidiaries Enel Generación Perú S.A., Emgesa and Enel Generación Costanera for ThUS$174,259 should be mentioned), while in the distribution business, the biggest investments carried out correspond to extensions and networks to optimize their operation in order to improve the efficiency and quality of the service level, for ThUS$538,025 for the year ended December 31, 2018 (ThUS$570,574 for the year ended December 31, 2017).

The depreciation of property, plant and equipment amounted ThUS$511,326 and ThUS$407,535 for the years ended December 31, 2018 and 2017, respectively which are presented net of PIS and COFINS taxes in the Brazilian subsidiaries.

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b)Capitalized cost

b.1)    Capitalized financial expenses

The capitalized cost for financial expenses for the years ended December 31, 2018, 2017 and 2016 amounted to ThUS$19,329, ThUS$8,054 and ThUS$30,939, respectively (see Note 33). The average funding rate mainly depends on the geographic area and amounted to 8.52% as of December 31, 2018 (9.44% and 18.06% as of December 31, 2017 and 2016, respectively.

b.2)    Capitalized personnel expenses

The capitalized cost for personnel expenses directly related to constructions in progress for the years ended December 31, 2018, 2017 and 2016 amounted to ThUS$95,335, ThUS$105,000 and ThUS$75,042, respectively.

c)Finance leases

As of December 31, 2018, property, plants and equipment includes ThUS$183,355 in leased assets classified as finance leases (ThUS$183,363 as of December 31, 2017).

The present value of future lease payments derived from these finance leases is as follows:

	12-31-2018			12-31-2017
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Less than one year	39,300	3,633	35,667	26,991	344	26,647
From one to five years	97,362	11,056	86,306	83,287	5,442	77,845
More than five years	—	—	—	—	—	—
Total	136,662	14,689	121,973	110,278	5,786	104,492

The leasing assets mainly come from Enel Generación Piura essentially corresponding to the following:

·Finance lease contract with Banco de Crédito de Perú for a 9-year term at a fixed rate of 5.8% in US dollars and with quarterly amortizations as from March 31, 2014. This finance lease was undersigned to finance the Unit of “Cold generation reserve”.

·On July 21, 2016 a finance lease contract was signed with the Banco de Crédito de Perú has for a 5-year term at a fixed rate of 3.68% in US dollars and with quarterly amortizations as from the second half of 2018. This finance lease was signed to finance a compressor and a natural gas station for the Unit of “Cold generation reserve” of the Malacas thermal power plant (TG5).

·Finance lease contract entered into on December 16, 2015 with Scotiabank for a 6 and a half-year term at a fixed rate of 3.75% in US dollars and with quarterly amortizations as from September 2017. This finance lease was signed to finance the new TG-6 turbine for the Malacas thermal power plant (TG6).

d)Operating leases

The consolidated statements of income for the years ended December 31, 2018, 2017 and 2016, include ThUS$27,885, ThUS$26,448 and ThUS$17,271, respectively; related to the accrual during these periods of operating lease contracts for material assets in operation.

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As of December 31, 2018 and 2017, the total future lease payments under those contracts are as follows:

	12-31-2018	12-31-2017
	ThUS$	ThUS$
Less than one year	16,700	15,889
From one to five years	44,728	27,689
More than five years	13,294	13,344
Total	74,722	56,922

e)Other information

i)As of December 31, 2018, the Group had contractual commitments for the acquisition of property, plants and equipment amounting to ThUS$440,385 (ThUS$596,957 as of December 31, 2017).

ii)As of December 31, 2018, the Group had property, plants and equipment pledged as security for liabilities for ThUS$7,692 (ThUS$26,156 as of December 31, 2017 (see Note 36.1).

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$1,450,550) limit in the case of generating companies and a €50 million (ThUS$57,278) limit for distribution companies, including business interruption coverage. Additionally, the Company has Civil Liability insurance to meet claims from third parties with a €500 million (ThUS$572,775) limit. The premiums associated with these policies are presented proportionally for each company under the line item “Prepaid expenses”.

iv)The Argentine subsidiary, Empresa Distribuidora Sur S.A., has its financial equilibrium seriously affected by the delay in the compliance with certain points of the Acta de Acuerdo agreement signed with the Argentine Government, particularly the twice-yearly rate adjustments recognized through the cost-monitoring mechanism (MMC) and the establishment of a Comprehensive Rate Review (RTI in its Spanish acronym) as provided for in this agreement.

At the end of 2011, the Group recognized an impairment loss in property, plants and equipment from Empresa Distribuidora Sur S.A. As of December 31, 2017, the amount was completely reversed for ThUS$54,819 (see Note 4.e).

v)In November 2010, the subsidiary Emgesa signed the Contract CEQ-21 Main Civil Works El Quimbo Hydroelectric Project (“CEQ-21”) with Consortium Impregilo-Obrascon Huarte Lain (“OHL”) for construction of the principal public works of the El Quimbo hydroelectric project.

During 2015 the Consortium Impregilo-OHL presented to the Company a series of claims and notifications of change orders for economic damages for the works executed in the CEQ-21 contract.

On October 19, 2016, at the Board of Directors Meeting No.436, a technical and legal analysis of the contract was made, and in order to avoid a future arbitration process, negotiations were settled with the Consortium Impregilo-OHL, as a result of the negotiations previously held from September 2015 and March 2016. The company decided to close the negotiation with the contractor in August 2016. The initial amount requested by the contractor was CP$204,351 million (ThUS$62,926) considering claims and notifications of changes orders (NOC in its Spanish acronym) and it agreed to pay the value of CP$57,459 million (ThUS$17,693) plus a value of CP$2,800 million (ThUS$862) by contract closing minutes for a total of CP$60,259 million (ThUS$18,556); these values were authorized by the company to be included in the CEQ-021 contract.

In October 2016, as part of the analysis of the activities included in the provision made to guarantee fulfillment of its obligations stemming from the construction of the power plant, the company made some adjustments to some activities that were considered unnecessary, including the adjustments to the contract prices agreed to by

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the Board of Directors and formalized in addendum 17 and whose payment for a total of CP$74,800 million (Th$23,033) was made in February 2017

vi)In Enel Costanera Generation, product of the application of IAS 29 - Financial Information in Hyperinflationary Economies, the book value of property, plant and equipment as of January 1, 2018 exceeded its recoverable value, which resulted in a deterioration of ThUS $162,274 (equivalent to thAR $3,102,739 at the exchange rate of that date). At the end of fiscal year 2018, the Generación Costanera recorded a partial reversal of the aforementioned impairment of ThUS $70,513 (equivalent to ThAr $2,656,082 at the exchange rate at the end of 2018), which was recognized in the results for the year, mainly as a result of the positive impact that the depreciation of the Argentine peso had on the company’s income (revenues are denominated in dollars).

20.   INCOME TAX AND DEFERRED TAXES

a)    Income taxes

The following table presents the components of the income tax expense/(benefit) recognized in the consolidated statement of comprehensive income for the years ended December 31, 2018, 2017 and 2016:

	For the years ended December 31,
Current Income Tax and Adjustments	2018		2017		2016
to Current Income Tax for Previous Periods	ThUS$		ThUS$		ThUS$
Current income tax	(698,216	)	(647,937	)	(533,042	)
Tax benefit from tax losses, tax credits or temporary differences not previously recognized for the current period (current tax credits and/or benefits)	20,104		30,041		28,471
Adjustments to current tax from the previous period	7,692		24,030		(1,666	)
Other current tax benefit / (expense)	(267	)	485		(316	)
Current tax expense, net	(670,687	)	(593,381	)	(506,553	)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences	228,505		28,259		7,260
Benefit / (expense) from deferred taxes due to changes in tax rates or the introduction of new taxes	4,662		54,967		(32,835	)
Adjustments to deferred taxes from the previous period	(412	)	(8,979	)	667
Total deferred tax benefit / (expense)	232,755		74,247		(24,908	)
Income tax expense, continuing operations	(437,932	)	(519,134	)	(531,461	)

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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, 2018, 2017 and 2016:

	2018				2017				2016
Reconciliation of Tax Expense	Tax Rate		ThUS$		Tax Rate		ThUS$		Tax Rate		ThUS$
ACCOUNTING INCOME BEFORE TAX			2,104,990				1,645,648				1,376,069
Total tax income (expense) using statutory rate	(27.00	)%	(568,345	)	(25.50	)%	(419,637	)	(24.00	)%	(330,256	)
Tax effect of rates applied in other countries	(6.64	)%	(139,772	)	(10.93	)%	(179,788	)	(12.04	)%	(165,722	)
Tax effect of non-taxable operations and benefits from tax losses and tax credits	19.16	%	403,399		8.39	%	138,031		5.54	%	76,231
Tax effect of non-tax-deductible expenses	(6.90	)%	(145,156	)	(7.76	)%	(127,758	)	(18.01	)%	(247,867	)
Tax effect of changes in income tax rates	0.22	%	4,662		3.3	%	54,967		(2.39	)%	(32,835	)
Tax effect of adjustments to taxes in previous periods	0.37	%	7,692		1.5	%	24,030		(0.12	)%	(1,666	)
Adjustments for prior periods deferred taxes	(0.02	)%	(412	)	(0.546	)%	(8,979	)	0.05	%	667
Price level restatement for tax purposes (investments in subsidiaries, associates and joint ventures and equity)	0	%	—		(—	)%	—		12.35	%	169,987
Total adjustments to tax expense using statutory rate	6	%	130,413		(6.05	)%	(99,497	)	(14.62	)%	(201,205	)
Income tax benefit (expense), continuing operations	(20.80	)%	(437,932	)	(31.55	)%	(519,134	)	(38.62	)%	(531,461	)

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, 2018 and 2017:

	December 31, 2018				December 31, 2017
	Assets		Liabilities		Assets		Liabilities
Assets/(Liabilities) for Deferred Taxes	ThUS$		ThUS$		ThUS$		ThUS$
Depreciations	12,514		(362,295	)	77,084		(409,305	)
Amortizations	7,206		(24,400	)	8,617		(29,383	)
Obligations for post-employment benefits	374,105		(154	)	83,968		(199	)
Revaluations of financial instruments	3,290		(8,364	)	10,785		(7,507	)
Tax loss	258,589		—		—		—
Provisions	803,708		(210,459	)	313,092		(168,774	)
Provision for Civil Contingencies	256,544		—		46,147		—
Provision Contingencies Workers	32,360		—		33,669		—
Provision uncontainable accounts	235,875		—		99,420		—
Provision of Human Resources accounts	14,730		—		4,782		—
Financial assets IFRIC 12	—		(196,683	)	—		(119,729	)
Other Provisions	264,199		(13,776	)	129,074		(49,045	)
Other Deferred Taxes	271,041		(1,237,814	)	65,327		(198,645	)
Amortization PPA - CELG	—		(682,399	)	—		(134,830	)
Monetary Correction - Argentina	—		(265,047	)	—		—
Other Deferred Taxes	271,041		(290,368	)	65,327		(63,815	)
Deferred taxes Assets/(Liabilities) before compensation	1,730,453		(1,843,486	)	558,873		(813,813	)
Compensation deferred taxes Assets/Liabilities	(1,297,416	)	1,297,416		(358,502	)	358,502
Deferred taxes Assets/(Liabilities) after compensation	433,037		(546,070	)	200,371		(455,311	)

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The origin and changes in deferred tax assets and liabilities as of December 31, 2018 and 2017 are as follows:

	Net balance as of		Effects first
	January 1, 2018		application		Net balance as of		Movements
	before the		IFRS 9 and		January 1, 2018				Recognized in	Acquisitions		Foreign currency
	application of		IFRS 15 and		after application		Recognized in		comprehensive	Through Business		translation		Other increases		Net balance as of
	IFRS 9		IAS 29		of IFRS 9		profit or loss		income	Combinations		difference		(decreases)		December 31, 2018
Deferred Taxes Assets/(Liabilities)	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$	ThUS$		ThUS$		ThUS$		ThUS$
Depreciations	(332,221	)	26		(332,195	)	(25,314	)	—	—		27,654		(19,926	)	(349,781	)
Amortizations	(20,766	)	—		(20,766	)	145		—	—		2,937		490		(17,194	)
Obligations for post-employment benefits	83,769		—		83,769		1,362		59,036	262,299		(31,463	)	(1,052	)	373,951
Revaluations of financial instruments	3,278		—		3,278		(8,149	)	1,103	—		(85	)	(1,221	)	(5,074	)
Tax loss	—		—		—		274,706		—	—		(16,117	)	—		258,589
Provisions	144,318		5,626		149,944		120,906		—	340,549		(70,557	)	52,407		593,249
Provision for Civil Contingencies	46,147		—		46,147		7,183		—	218,400		(14,989	)	(197	)	256,544
Provision Contingencies Workers	33,669		—		33,669		(705	)	—	—		(540	)	(64	)	32,360
Provision for doubtful trade accounts	99,420		5,626		105,046		111,533		—	34,765		(15,218	)	(251	)	235,875
Provision of Human Resources accounts	4,782		—		4,782		6,685		—	4,028		(870	)	105		14,730
Financial assets IFRIC 12	(119,729	)	—		(119,729	)	(30,739	)	—	(54,965	)	7,689		1,061		(196,683	)
Other Provisions	80,029		—		80,029		26,949		—	138,321		(46,629	)	51,753		250,423
Other Deferred Taxes	(133,318	)	(302,459	)	(435,777	)	(130,901	)	5	(542,490	)	216,005		(73,615	)	(966,773	)
Amortization PPA - CELG	(134,830	)	—		(134,830	)	12,105		—	(616,685	)	54,726		2,285		(682,399	)
Monetary Correction - Argentina	(2,883	)	(302,459	)	(305,342	)	(111,518	)	—	—		151,813		—		(265,047	)
Other Deferred Taxes	4,395		—		4,395		(31,488	)	5	74,195		9,466		(75,900	)	(19,327	)
Deferred Taxes Assets/(Liabilities)	(254,940	)	(296,807	)	(551,747	)	232,755		60,144	60,358		128,374		(42,917	)	(113,033	)

	Movements
	Net balance as of January 1, 2017		Recognized in profit or loss		Recognized in comprehensive income		Acquisitions		Foreign currency translation difference		Other increases (decreases)		Net balance as of December 31, 2017
Deferred Taxes Assets/(Liabilities)	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Depreciations	(290,192	)	(55,917	)	—		—		(6,885	)	20,773		(332,221	)
Amortizations	(21,066	)	147		—		—		153		—		(20,766	)
Revaluations of financial instruments	80,129		778		4,590		—		(1,258	)	(470	)	83,769
Tax loss	9,386		(888	)	(3,796	)	—		8		(1,432	)	3,278
Provisions	104,105		75,463		—		—		(11,652	)	(23,598	)	144,318
Provision for Civil Contingencies	47,456		444		—		—		(47	)	(1,706	)	46,147
Provision Contingencies Workers	30,366		3,457		—		—		(154	)	—		33,669
Provision for doubtful trade accounts	101,579		(362	)	—		—		(1,797	)	—		99,420
Provision of Human Resources accounts	8,507		(4,579	)	—		—		218		636		4,782
Financial assets IFRIC 12	(107,417	)	(12,312	)	—		—		—		—		(119,729	)
Other Provisions	23,614		88,815		—		—		(9,872	)	(22,528	)	80,029
Other Deferred Taxes	(31,374	)	54,664		27		(162,842	)	7,992		(1,785	)	(133,318	)
Amortization PPA - CELG	—		4,528		—		(139,358	)	—		—		(134,830	)
Other Deferred Taxes	(31,374	)	50,136		27		(23,484	)	7,992		(1,785	)	1,512
Deferred Taxes Assets/(Liabilities)	(149,012	)	74,247		821		(162,842	)	(11,642	)	(6,512	)	(254,940	)

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, 2018, the Group has not recognized deferred tax assets related to tax losses carry forward for ThUS$26,244 (ThUS$358,487 as of December 31, 2017) (see Note 4.p).

The Group has not recognized deferred tax liabilities for taxable temporary differences relating to investment in subsidiaries and joint ventures, as it is able to control the timing of the reversal of the temporary differences and considers that it is probable that such temporary differences will not reverse in the foreseeable future. As of December 31, 2018, the aggregate amount of taxable temporary differences relating to investments in subsidiaries and joint ventures for which deferred tax liabilities have not been recognized were ThUS$2,553,012 (ThUS$1,424,219 as of December 31, 2017). On the other hand, the total amount of deductible temporary differences relating to investments in subsidiaries and joint ventures for which as of December 31, 2018, it is probable that will not reverse in the foreseeable future or there will be not sufficient taxable profits in the future to recover such temporary differences were, ThUS$2,487,133 (ThUS$3,124,740 as of December 31, 2017).

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

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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
Chile	2015-2017
Argentina	2013-2017
Brazil	2013-2017
Colombia	2015-2017
Peru	2011-2017

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, 2018, 2017 and 2016, are as follows:

	December 31, 2018					December 31, 2017						December 31, 2016
Effects of Deferred Tax on the Components of Other	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
Comprehensive Income	ThUS$		ThUS$	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Available-for-sale financial assets	(458	)	—	(458	)	(829	)	—		(829	)	976		—		976
Cash flow hedges	(2,727	)	1,354	(1,373	)	12,735		(5,088	)	7,647		28,731		(6,816	)	21,915
Share of other comprehensive income in associates and joint ventures accounted for using the equity method	—		—	—		—		—		—		(20,832	)	—		(20,832	)
Foreign currency translation	(1,575,134	)	—	(1,575,134	)	(95,501	)	—		(95,501	)	214,887		—		214,887
Actuarial gains (losses) from defined benefit pension plans	(177,527	)	59,684	(117,843	)	(4,941	)	3,694		(1,247	)	(29,399	)	9,592		(19,807	)
Components of other comprehensive income	(1,755,846	)	61,038	(1,694,808	)	(88,536	)	(1,394	)	(89,930	)	194,363		2,776		197,139

The movements in deferred taxes for the components of other comprehensive income for the years ended December 31, 2018, 2017 and 2016, are as follows:

	For the years ended December 31,
	2018	2017		2016
Reconciliation of changes in deferred taxes of components of other comprehensive income	ThUS$	ThUS$		ThUS$
Total increases (decreases) for deferred taxes of other comprehensive income from continuing operations	60,144	821		10,100
Income tax of changes in cash flow hedge transactions	894	(1,292	)	(21	)
Deferred tax of actuarial gains (losses) from defined benefit plans	—	(896	)	(710	)
Total increases (decreases) for deferred taxes of other comprehensive income from discontinued operations	—	—		(6,593	)
Other increases (decreases) for deferred taxes	—	(27	)	—
Total income tax relating to components of other comprehensive income	61,038	(1,394	)	2,776

d)     In Colombia, the law 1943 of 2018 modified the income tax rate from the taxable year of 2019 defining the following rates: year 2019 33%, year 2020 32%, year 2021 31%, year 2022 and following 30%. This affects the taxable income obtained during each year. The effect of temporary differences involving the payment of a lower or higher income tax in the current year is accounted as deferred tax credit or debit, respectively, at the tax rates when differences are reversed (33% for 2019, 32% for 2020, 31% for 2021 and 30% as from 2022), provided that there are reasonable

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expectations that such differences will be reversed in the future and also for the assets, which at that time should be generating sufficient taxable income.

As a result of this increase in rates, the Colombian subsidiaries recognized as of December 31, 2018 variations in their deferred tax assets and liabilities. The net charge to results amounted to ThUS$ 4,662.

21.  OTHER FINANCIAL LIABILITIES

The balance of other financial liabilities as of December 31, 2018 and 2017, is as follows

	December 31, 2018		December 31, 2017
	Current	Non-Current	Current	Non-Current
Other Financial Liabilities	ThUS$	ThUS$	ThUS$	ThUS$
Interest-bearing borrowings	1,642,504	4,621,855	670,916	4,333,042
Hedging derivatives (*)	5,595	13	17,582	7,802
Non-hedging derivatives (**)	—	—	1,270	8,671
Total	1,648,099	4,621,868	689,768	4,349,515

(*)See Note 23.2.a.

(**)See Note 23.2.b.

21.1   Interest-bearing borrowings

The detail of current and non-current interest-bearing borrowings as of December 31, 2018 and 2017 is as follows:

	December 31, 2018		December 31, 2017
	Current	Non-Current	Current	Non-Current
Classes of Interest-Bearing Borrowings	ThUS$	ThUS$	ThUS$	ThUS$
Bank loans	1,041,653	854,256	336,937	1,164,786
Unsecured obligations	441,946	2,626,127	271,173	2,726,159
Secured obligations	67,805	922,721	492	180,184
Financial leases	35,667	86,306	26,647	77,845
Other obligations	55,433	132,445	35,667	184,068
Total	1,642,504	4,621,855	670,916	4,333,042

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Bank loans by currency and contractual maturity as of December 31, 2018 and 2017 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 12/31/2018	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12/31/2018
Country	Currency	Rate		Rate		Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	4.99	%	3.36	%	Unsecured	—	352,387	352,387	—	—	—	—	—	—
Chile	Ch$	6.00	%	6.00	%	Unsecured	1	—	1	—	—	—	—	—	—
Peru	US$	3.52	%	3.40	%	Unsecured	424	—	424	—	—	—	—	—	—
Peru	PS$	3.78	%	3.75	%	Unsecured	35	25,857	25,892	—	22,192	—	—	—	22,192
Colombia	CP$	6.28	%	6.12	%	Unsecured	66,549	40,037	106,586	33,223	10,967	9,238	9,238	4,619	67,285
Brazil	US$	4.54	%	4.53	%	Unsecured	83,974	303,104	387,078	271,452	203,283	—	—	2,776	477,511
Brazil	R$	6.22	%	6.07	%	Unsecured	76,231	93,054	169,285	91,260	86,152	52,845	19,310	37,701	287,268
		Total					227,214	814,439	1,041,653	395,935	322,594	62,083	28,548	45,096	854,256

							Current			Non-Current
							Maturity			Maturity
		Effective Interest		Nominal Interest		Secured /	One to three months	Three to twelve months	Total Current 12/31/2017	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12/31/2017
Country	Currency	Rate		Rate		Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Peru	US$	3.34	%	3.23	%	Unsecured	8,859	1,265	10,124	422	—	—	—	—	422
Peru	PS$	5.43	%	5.32	%	Unsecured	22,268	27,471	49,739	—	—	—	—	—	—
Colombia	US$	1.90	%	1.88	%	Unsecured	35,414	—	35,414	—	—	—	—	—	—
Colombia	CP$	7.28	%	7.10	%	Unsecured	13,030	17,085	30,115	88,625	64,963	15,459	13,623	20,434	203,104
Brazil	US$	3.80	%	3.83	%	Unsecured	7,595	37,076	44,671	407,459	293,720	53,532	30,856	5,762	791,329
Brazil	R$	11.86	%	10.84	%	Unsecured	56,245	110,629	166,874	61,436	17,302	87,643	2,086	1,464	169,931
		Total					143,411	193,526	336,937	557,942	375,985	156,634	46,565	27,660	1,164,786

· Fair value measurement and hierarchy

The fair value of current and non-current bank borrowings as of December 31, 2018 was ThUS$1,856,032 (ThUS$1,470,194 as of December 31, 2017). The borrowings have been classified as Level 2 fair value measurement based on the entry data used in the valuation techniques (see Note 4.h).

F-127

· Identification of bank borrowings by company

													December 31, 2018
													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		Amortization	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	Citibank	Brazil	US$		1.91	%	1.90	%	At Maturity	31	37,119	37,150	—	—	—	—	—	—
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	Banco Santander	Brazil	US$		5.03	%	5.02	%	At Maturity	76,126	—	76,126	—	—	—	—	—	—
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	Bndes	Brazil	R$	9.17		%	9.04	%	Monthly	9,166	26,812	35,978	29,483	21,773	3,322	2,079	—	56,657
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	Banco Itau	Brazil	US$	4.81		%	4.80	%	At Maturity	1,583	—	1,583	—	75,601	—	—	—	75,601
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	Bndes	Brazil	R$	12.11		%	12.06	%	Monthly	10,445	29,043	39,488	32,740	32,740	27,811	—	—	93,291
Foreign	Enel Distribución Río S.A.	Brazil	Foreign	Citibank	Brazil	US$	3.77		%	3.76	%	At Maturity	31	—	31	—	97,220	—	—	—	97,220
Foreign	Codensa	Colombia	Foreign	Bank of Tokyo	Colombia	CP$	8.49		%	8.32	%	At Maturity	63,094	—	63,094	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bank of Tokyo	Colombia	CP$	9.01		%	8.82	%	At Maturity	244	24,943	25,187	24,942	—	—	—	—	24,942
Foreign	Codensa	Colombia	Foreign	Banco de Bogota S.A.	Colombia	CP$	6.90		%	6.69	%	Quarterly	753	—	753	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Banco AV Villas	Colombia	CP$	6.49		%	6.30	%	Quarterly	384	—	384	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Banco Popular	Colombia	CP$	6.55		%	6.36	%	Quarterly	200	385	585	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Banco Popular	Colombia	CP$	6.60		%	6.40	%	Quarterly	386	1,132	1,518	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.15		%	5.03	%	Quarterly	79	225	304	67	—	—	—	—	67
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.24		%	5.12	%	Quarterly	66	193	259	57	—	—	—	—	57
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.28		%	5.16	%	Quarterly	35	105	140	31	—	—	—	—	31
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.15		%	5.03	%	Quarterly	134	379	513	220	—	—	—	—	220
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.24		%	5.12	%	Quarterly	85	248	333	144	—	—	—	—	144
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.32		%	5.20	%	Quarterly	80	237	317	138	—	—	—	—	138
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.98		%	5.82	%	Quarterly	206	605	811	655	164	—	—	—	819
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.81		%	5.66	%	Quarterly	108	293	401	310	155	—	—	—	465
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.90		%	5.75	%	Quarterly	158	449	607	476	238	—	—	—	714
Foreign	Codensa	Colombia	Foreign	Banco Agrario	Colombia	CP$	6.30		%	6.13	%	Quarterly	537	1,509	2,046	1,564	1,172	—	—	—	2,736
Foreign	Chinango S.A.C.	Perú	Foreign	Bank Of Nova Scotia	Perú	US$	3.52		%	3.40	%	Quarterly	424	—	424	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Itau CCB	Brazil	R$	10.01		%	10.00	%	Annually	13,146	—	13,146	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Banco do Brasil	Brazil	R$	7.00		%	6.93	%	Annually	173	19,351	19,524	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	R$	10.01		%	10.00	%	Monthly	1,374	—	1,374	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Bndes	Brazil	R$	9.28		%	9.15	%	Monthly	4,803	14,060	18,863	15,282	11,753	1,620	1,089	—	29,744
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Banco do Brasil	Brazil	US$	5.70		%	5.69	%	At Maturity	30	—	30	—	—	—	—	2,776	2,776
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	US$	6.34		%	6.33	%	Monthly	255	559	814	5,610	8,415	8,415	8,415	36,462	67,317
Foreign	Enel Distribución Ceará S.A.	Brazil	Foreign	Nota Promissoria	Brazil	US$	6.80		%	6.79	%	At Maturity	2,041		2,041
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco de Credito del Perú	Perú	PS$	4.16		%	4.10	%	At Maturity	35	—	35	—	22,192	—	—	—	22,192
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA Colombia	Colombia	CP$	6.37		%	6.27	%	Bi-Annually	—	9,334	9,334	4,619	9,238	9,238	9,238	4,619	36,952
Foreign	Enel Green Power Volta Grande	Brazil	Foreign	BNP PARIBAS	Brazil	US$	3.63		%	3.63	%	At Maturity	1,249	265,985	267,234	—	—	—	—	—	—
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	Itau 4131 CELG - CE 0720L401	Brazil	US$	4.63		%	4.62	%	Bi-Annually	1,522	—	1,522	75,601	—	—	—	—	75,601
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	Itau 4131 CELG - CE 0820L401	Brazil	US$	4.60		%	4.59	%	Bi-Annually	1,391	—	1,391	95,108	—	—	—	—	95,108
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	Itau 4131 CELG - CE 0221L401	Brazil	US$	5.46		%	5.45	%	Bi-Annually	542	—	542	—	30,462	—	—	—	30,462
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	Itau 4131 CELG - CE 0718L401	Brazil	US$	5.77		%	5.76	%	Bi-Annually	909	—	909	40,345	—	—	—	—	40,345
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	BNDES - FINAME CAPITAL DE GIRO	Brazil	R$	10.06		%	9.61	%	Quarterly	167	—	167	4,965	8,368	8,368	4,183	—	25,884
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	CCB ALFA	Brazil	R$	7.41		%	7.40	%	At Maturity	33,561	—	33,561	—	—	—	—	—	—
Foreign	Enel Generacion Fortaleza	Brazil	Foreign	Banco Citibank	Brazil	US$	4.66		%	4.65	%	At Maturity	560	—	560	60,398	—	—	—	—	60,398
Foreign	Enel Perú S.A	Perú	Foreign	Banco Scotiabank	Perú	PS$	3.40		%	3.40	%	At Maturity	—	25,857	25,857	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	Foreign	BNP Paribas NY	E.E.U.U	US$	4.99		%	3.36	%	At Maturity	—	105,000	105,000	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	Foreign	Citibank N.A	E.E.U.U	US$	4.99		%	3.36	%	At Maturity	—	35,000	35,000	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	Foreign	Credit Agricole CIB	E.E.U.U	US$	4.99		%	3.36	%	At Maturity	—	37,387	37,387	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	Foreign	JP Morgan Chase Bank	E.E.U.U	US$	4.99		%	3.36	%	At Maturity	—	35,000	35,000	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	Foreign	Sumitomo Mitsui Banking	E.E.U.U	US$	4.99		%	3.36	%	At Maturity	—	70,000	70,000	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	Foreign	Societe Generale	E.E.U.U	US$	4.99		%	3.36	%	At Maturity	—	35,000	35,000	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	Foreign	BBVA New York Branch	E.E.U.U	US$	4.99		%	3.36	%	At Maturity	—	35,000	35,000	—	—	—	—	—	—
94.271.00-3	Enel Américas S.A	Chile	97.036.000-k	Linea sobregiro (Banco Santander)	Chile	Ch$	6.00		%	6.00	%	At Maturity	1	—	1	—	—	—	—	—	—
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	FINEP - 1° Protocolo	Brazil	R$	4.00		%	4.00	%	Monthly	397	1,180	1,577	262	—	—	—	—	262
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	FINEP - 2° Protocolo	Brazil	R$	11.98		%	11.80	%	Monthly	703	2,049	2,752	2,918	3,103	3,309	3,544	1,239	14,113
Total													227,214	814,439	1,041,653	395,935	322,594	62,083	28,548	45,096	854,256

F-128

												December 31, 2017
												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		Amortization	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Distribución Río S.A. ( ex Ampla Energía  S.A.)	Brazil	Foreign	Citibank	Brazil	US$	4.13	%	4.12	%	At Maturity	778	37,076	37,854	—	—	—	—	—	—
Foreign	Enel Distribución Río S.A. ( ex Ampla Energía  S.A.)	Brazil	Foreign	Banco Santander	Brazil	US$	3.37	%	3.36	%	At Maturity	708	—	708	75,938	—	—	—	—	75,938
Foreign	Enel Distribución Río S.A. ( ex Ampla Energía  S.A.)	Brazil	Foreign	Bndes	Brazil	R$	10.57	%	10.51	%	Monthly	20,080	32,334	52,414	39,121	31,839	22,490	4,410	2,989	100,849
Foreign	Enel Distribución Río S.A. ( ex Ampla Energía  S.A.)	Brazil	Foreign	Banco Itau	Brazil	US$	4.29	%	4.28	%	At Maturity	1,594	—	1,594	—	—	75,512	—	—	75,512
Foreign	Enel Distribución Río S.A. ( ex Ampla Energía  S.A.)	Brazil	Foreign	Bndes	Brazil	R$	10.83	%	9.86	%	Monthly	966	6,894	7,860	31,042	31,042	31,042	26,446	—	119,572
Foreign	Codensa	Colombia	Foreign	Bank of Tokyo	Colombia	CP$	8.49	%	8.32	%	At Maturity	1,626	—	1,626	66,996	—	—	—	—	66,996
Foreign	Codensa	Colombia	Foreign	Bank of Tokyo	Colombia	CP$	9.01	%	8.82	%	At Maturity	—	279	279	—	54,266	—	—	—	54,266
Foreign	Codensa	Colombia	Foreign	Banco de Bogota S.A.	Colombia	CP$	7.72	%	7.46	%	Quarterly	836	2,462	3,298	722	—	—	—	—	722
Foreign	Codensa	Colombia	Foreign	Banco AV Villas	Colombia	CP$	7.50	%	7.26	%	Quarterly	424	1,256	1,680	368	—	—	—	—	368
Foreign	Codensa	Colombia	Foreign	Banco Popular	Colombia	CP$	7.45	%	7.25	%	Quarterly	277	628	905	556	—	—	—	—	556
Foreign	Codensa	Colombia	Foreign	Banco Popular	Colombia	CP$	7.44	%	7.24	%	Quarterly	536	1,256	1,792	1,452	—	—	—	—	1,452
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.21	%	6.07	%	Quarterly	112	245	357	282	71	—	—	—	353
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.10	%	5.97	%	Quarterly	91	212	303	242	61	—	—	—	303
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	5.96	%	5.83	%	Quarterly	46	117	163	132	33	—	—	—	165
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.21	%	6.07	%	Quarterly	197	407	604	466	233	—	—	—	699
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.07	%	5.94	%	Quarterly	121	268	389	304	152	—	—	—	456
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.03	%	5.90	%	Quarterly	109	259	368	291	145	—	—	—	436
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.72	%	6.56	%	Quarterly	322	628	950	695	695	174	—	—	1,564
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.86	%	6.69	%	Quarterly	180	294	474	330	330	165	—	—	825
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP$	6.75	%	6.59	%	Quarterly	259	456	715	505	505	253	—	—	1,263
Foreign	Codensa	Colombia	Foreign	Banco Agrario	Colombia	CP$	7.15	%	6.97	%	Quarterly	899	1,507	2,406	1,661	1,661	1,246	—	—	4,568
Foreign	Chinango S.A.C.	Perú	Foreign	Banco de Credito del Perú	Perú	US$	3.15	%	3.05	%	Quarterly	8,422	—	8,422	—	—	—	—	—	—
Foreign	Chinango S.A.C.	Perú	Foreign	Bank Of Nova Scotia	Perú	US$	3.52	%	3.40	%	Quarterly	437	1,265	1,702	422	—	—	—	—	422
Foreign	Enel Cien S.A. (EX Cien S.A.)	Brazil	Foreign	Bndes	Brazil	R$	9.35	%	8.84	%	Monthly	419	1,216	1,635	1,621	811	—	—		2,432
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Banco Itaú Brasil	Brazil	R$	12.17	%	11.28	%	Annually	15,766	—	15,766	15,094	—	—	—	—	15,094
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Banco do Brasil	Brazil	R$	10.29	%	10.14	%	Annually	795	45,280	46,075	22,640	—	—	—	—	22,640
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Banco do Nordeste	Brazil	R$	7.85	%	7.70	%	Monthly	1,630	4,808	6,438	1,603	—	—	—	—	1,603
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Bndes	Brazil	R$	10.79	%	10.66	%	Monthly	8,891	15,359	24,250	20,478	16,491	12,131	2,086	1,464	52,650
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Banco do Brasil	Brazil	US$	4.67	%	4.66	%	At Maturity	27	—	27	—	—	—	—	2,773	2,773
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco de Interbank	Perú	PS$	5.83	%	5.71	%	At Maturity	6,624	—	6,624	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Continental	Perú	PS$	5.10	%	5.01	%	At Maturity	29	4,630	4,659	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Continental	Perú	PS$	5.10	%	5.01	%	At Maturity	47	7,717	7,764	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Continental	Perú	PS$	5.10	%	5.01	%	At Maturity	35	7,407	7,442	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Continental	Perú	PS$	5.10	%	5.01	%	At Maturity	33	7,717	7,750	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Santander	Perú	PS$	6.35	%	6.20	%	At Maturity	15,500	—	15,500	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA Colombia	Colombia	CP$	9.43	%	9.21	%	At Maturity	5,160	5,024	10,184	10,050	5,024	10,048	10,050	15,074	50,246
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Bogota	Colombia	CP$	9.85	%	9.62	%	At Maturity	1,835	1,787	3,622	3,573	1,787	3,573	3,573	5,360	17,866
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Crédito del perú	Colombia	US$	1.90	%	1.88	%	At Maturity	35,414	—	35,413	—	—	—	—	—	—
Foreign	Enel Green Power Volta Grande	Brazil	Foreign	BNP PARIBAS	Brazil	US$	3.24	%	3.22	%	At Maturity	1,158	—	1,158	261,358	—	—	—	—	261,358
Foreign	CELG Distribuição S.A.	Brazil	Foreign	Banco Daycoval (75272/2014)	Brazil	R$	14.99	%	13.59	%	Monthly	653	650	1,303	—	—	—	—	—	—
Foreign	CELG Distribuição S.A.	Brazil	Foreign	BCV - Banco de Crédito e Varejo (1310/2015)	Brazil	R$	15.86	%	12.91	%	Monthly	1,782	587	2,369	—	—	—	—	—	—
Foreign	CELG Distribuição S.A.	Brazil	Foreign	BCV - Banco de Crédito e Varejo (1360/2015)	Brazil	R$	15.86	%	12.91	%	Monthly	5,263	3,501	8,764	—	—	—	—	—	—
Foreign	CELG Distribuição S.A.	Brazil	Foreign	ITAÚ 4131 CELG	Brazil	US$	4.02	%	4.05	%	Bi-Annually	1,533	—	1,533	—	75,513	—	—	—	75,513
Foreign	CELG Distribuição S.A.	Brazil	Foreign	ITAÚ 4131 CELG	Brazil	US$	3.67	%	4.02	%	Bi-Annually	1,398	—	1,398	—	94,998	—	—	—	94,998
Foreign	CGTF Endesa Fortaleza	Brazil	Foreign	Banco Citibank	Brazil	US$	2.98	%	2.96	%	At Maturity	399	—	399	—	60,328	—	—	—	60,328
Total												143,411	193,526	336,936	557,942	375,985	156,634	46,565	27,660	1,164,786

F-129

21.2   Unsecured liabilities

The detail of Unsecured Liabilities by currency and maturity as of December 31, 2018 and 2017 is as follows:

- Summary of unsecured liabilities by currency and maturity

					Current			Non-Current
					Maturity			Maturity
Country	Currency	Nominal Interest Rate		Secured / Unsecured	One to three months ThUS$	Three to twelve months ThUS$	Total Current 12/31/2018 ThUS$	One to two years ThUS$	Two to three years ThUS$	Three to four years ThUS$	Four to five years ThUS$	More than five years ThUS$	Total Non- Current 12/31/2018 ThUS$
Chile	US$	5.30	%	Unsecured	—	4,471	4,471	—	—	—	—	584,411	584,411
Chile	U.F.	5.75	%	Unsecured	—	6,197	6,197	6,493	6,866	3,242	—	—	16,601
Peru	US$	6.64	%	Unsecured	8,865	—	8,865	9,998	—	—	—	9,998	19,996
Peru	PS$	6.34	%	Unsecured	11,201	58,856	70,057	38,466	29,589	34,028	47,343	194,670	344,096
Brazil	R$	7.91	%	Unsecured	39,767	45,425	85,192	45,523	91,691	45,152	31,142	87,900	301,408
Colombia	CP$	7.44	%	Unsecured	204,979	62,185	267,164	101,922	310,944	267,761	149,309	529,679	1,359,615
Total					264,812	177,134	441,946	202,402	439,090	350,183	227,794	1,406,658	2,626,127

					Current			Non-Current
					Maturity			Maturity
Country	Currency	Nominal Interest Rate		Secured / Unsecured	One to three months ThUS$	Three to twelve months ThUS$	Total Current 12/31/2017 ThUS$	One to two years ThUS$	Two to three years ThUS$	Three to four years ThUS$	Four to five years ThUS$	More than five years ThUS$	Total Non- Current 12/31/2017 ThUS$
Chile	US$	5.30	%	Unsecured	—	4,405	4,405	—	—	—	—	582,676	582,676
Chile	U.F.	5.75	%	Unsecured	—	6,458	6,458	6,746	7,134	7,544	3,412	—	24,836
Peru	US$	6.59	%	Unsecured	10,991	—	10,991	8,179	10,016	—	—	10,016	28,211
Peru	PS$	6.29	%	Unsecured	3,648	2,615	6,263	66,364	40,127	30,867	35,497	221,594	394,449
Brazil	R$	7.35	%	Unsecured	944	43,467	44,411	—	—	52,152	52,602	44,909	149,663
Colombia	CP$	8.69	%	Unsecured	37,900	160,745	198,645	253,473	110,856	337,987	190,818	653,190	1,546,324
Total					53,483	217,690	271,173	334,762	168,133	428,550	282,329	1,512,385	2,726,159

21.3   Secured liabilities

As of December 31, 2018 and 2017, there are no secured liabilities.

- Summary of secured liabilities by currency and maturity

					Current			Non-Current
					Maturity			Maturity
Country	Currency	Nominal Interest Rate		Secured / Unsecured	One to three months ThUS$	Three to twelve months ThUS$	Total current 12-31-2018 ThUS$	One to two years ThUS$	Two to three years ThUS$	Three to four years ThUS$	Four to five years ThUS$	More than five years ThUS$	Total Non- Current 12-31-2018 ThUS$
Brazil	R$	7.31	%	Secured	16,266	51,539	67,805	154,273	180,705	178,330	255,098	154,315	922,721
Total					16,266	51,539	67,805	154,273	180,705	178,330	255,098	154,315	922,721

					Current			Non-Current
					Maturity			Maturity
Country	Currency	Nominal Interest Rate		Secured / Unsecured	One to three months ThUS$	Three to twelve months ThUS$	Total current 12-31-2017 ThUS$	One to two  years ThUS$	Two to three  years ThUS$	Three to four years ThUS$	Four to five years ThUS$	More than five years ThUS$	Total  Non- Current 12-31-2017 ThUS$
Brazil	R$	6.18	%	Secured	492	—	492	—	180,184	—	—	—	180,184
Total					492	—	492	—	180,184	—	—	—	180,184

- Fair value measurement and hierarchy

The fair value of current and non-current secured and unsecured liabilities as of December 31, 2018 totaled ThUS$4,151,256 (ThUS$3,506,974 as of December 31, 2017). These liabilities have been classified as Level 2 fair

F-130

value measurement based on the entry data used in the valuation techniques used (see Note 4.h). It is important to note that these financial liabilities are measured at amortized cost (see Note 4 g.4).

F-131

· Unsecured liabilities by company

												December 31, 2018
												Current			Non-Current
Taxpayer			Taxpayer	Financial			Effective Interest		Nominal Interest		Secured /	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.	Institution	Country	Currency	Rate		Rate		Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Codensa	Colombia	Foreign	Bonds B12-13	Colombia	CP$	8.23	%	7.99	%	No	613	—	613	—	—	—	—	59,535	59,535
Foreign	Codensa	Colombia	Foreign	Bonds B7-14	Colombia	CP$	6.92	%	6.74	%	No	74	—	74	—	56,967	—	—	—	56,967
Foreign	Codensa	Colombia	Foreign	Bonds E4-16	Colombia	CP$	7.70	%	7.49	%	No	97	—	97	27,714	—	—	—	—	27,714
Foreign	Codensa	Colombia	Foreign	Bonds E2-17	Colombia	CP$	7.04	%	6.86	%	No	49,481	—	49,481	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bonds E5-17	Colombia	CP$	7.39	%	7.39	%	No	5,016	—	5,016	—	—	83,141	—	—	83,141
Foreign	Codensa	Colombia	Foreign	Bonds E7-17	Colombia	CP$	6.46	%	6.31	%	No	256	—	256	—	—	—	—	61,586	61,586
Foreign	Codensa	Colombia	Foreign	Bonds E7-18	Colombia	CP$	6.74	%	6.58	%	No	910	—	910	—	—	—	—	61,586	61,586
Foreign	Codensa	Colombia	Foreign	Bonds B12-18	Colombia	CP$	6.98	%	6.80	%	No	753	—	753	—	—	—	—	49,269	49,269
Foreign	Codensa	Colombia	Foreign	Interest Bonds B5- 18	Colombia	CP$	6.18	%	6.04	%	No	696	—	696	—	—	—	60,046	—	60,046
Foreign	Enel Distribución Ceará S.A.	Brasil	Foreign	Debentures CEAR15	Brazil	R$	7.34	%	7.33	%	No	226	—	226	—	45,152	45,152	—	—	90,304
Foreign	Enel Distribución Ceará S.A.	Brasil	Foreign	Debentures CEAR25	Brazil	R$	10.31	%	10.30	%	No	36	—	36	—	—	—	20,821	18,375	39,196
Foreign	Enel Distribución Ceará S.A.	Brasil	Foreign	Nota Promissoria	Brazil	R$	6.80	%	6.79	%	No	38,702	—	38,702	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A.	Brasil	Foreign	Debentures CEAR16	Brazil	R$	7.50	%	7.49	%	No	26	—	26	—	—	—	10,321	—	10,321
Foreign	Enel Distribución Ceará S.A.	Brasil	Foreign	Debentures CEAR26	Brazil	R$	11.10	%	10.51	%	No	166	—	166	—	—	—	—	69,525	69,525
Foreign	Enel Generación Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.41	%	6.31	%	No	—	12	12	—	—	7,397	—	—	7,397
Foreign	Enel Generación Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.38	%	6.28	%	No	228	7,397	7,625	—	—	—	—	—	—
Foreign	Enel Generación Perú S.A.	Perú	Foreign	Banco Continental	Perú	US$	6.44	%	6.34	%	No	273	—	273	—	—	—	—	9,998	9,998
Foreign	Enel Generación Perú S.A.	Perú	Foreign	Banco Continental	Perú	US$	7.93	%	7.78	%	No	8,447	—	8,447	—	—	—	—	—	—
Foreign	Enel Generación Perú S.A.	Perú	Foreign	Banco Scotiabank	Perú	US$	5.87	%	5.78	%	No	145	—	145	9,998	—	—	—	—	9,998
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.86	%	6.75	%	No	352	—	352	14,795	—	—	—	—	14,795
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	5.80	%	5.72	%	No	221	—	221	—	—	—	—	29,589	29,589
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Microfondo	Perú	PS$	7.15	%	7.03	%	No	6,110	—	6,110	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.61	%	6.50	%	No	107	—	107	14,795	—	—	—	—	14,795
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.15	%	6.06	%	No	—	125	125					14,795	14,795
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Microfondo	Perú	PS$	5.64	%	5.56	%	No	290	—	290	—	—	14,795			14,795
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	5.06	%	5.00	%	No	87	—	87	—	—	—	—	11,836	11,836
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	5.19	%	5.13	%	No	326	—	326	—	—	—	—	14,795	14,795
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Interseguro	Perú	PS$	6.38	%	6.28	%	No	—	159	159	—	—	11,836	—	—	11,836
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	7.41	%	7.28	%	No	270	—	270	—	—	—	—	10,504	10,504
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Prima AFP	Perú	PS$	7.58	%	7.44	%	No	264	—	264	8,876	—	—	—	—	8,876
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	7.51	%	7.38	%	No	145	—	145	—	—	—	—	17,754	17,754
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.90	%	6.78	%	No	—	440	440	—	29,589	—	—	—	29,589
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.44	%	6.34	%	No	—	56	56	—	—	—	17,754	—	17,754
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	5.93	%	5.84	%	No	—	29,675	29,675	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.44	%	6.34	%	No	425	—	425	—	—	—	—	23,671	23,671
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.22	%	6.12	%	No	579	20,713	21,292	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	5.45	%	5.38	%	No	444	—	444	—	—	—	—	29,589	29,589
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	8.29	%	8.12	%	No	481	—	481	—	—	—	—	20,713	20,713
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.19	%	6.09	%	No	872	—	872	—	—	—	29,589	—	29,589
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	6.09	%	6.00	%	No	—	279	279	—	—	—	—	21,424	21,424
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B10-09	Colombia	CP$	9.24	%	8.94	%	No	49,902	—	49,902	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B12-09	Colombia	CP$	9.57	%	9.24	%	No	636	—	636	—	27,584	—	—	—	27,584
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B15-09	Colombia	CP$	9.56	%	9.24	%	No	221	—	221	—	—	—	—	17,090	17,090
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B6-13	Colombia	CP$	7.66	%	7.45	%	No	65	15,222	15,287	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B6-14	Colombia	CP$	6.80	%	6.64	%	No	283	—	283	33,862	—	—	—	—	33,862
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds exterior	Colombia	CP$	9.11	%	8.75	%	No	2,360	—	2,360	—	27,714	—	—	—	27,714
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo	Colombia	CP$	9.11	%	8.75	%	No	16,958	—	16,958	—	198,679	—	—	—	198,679
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B10	Colombia	CP$	6.91	%	6.73	%	No	324	—	324	—	—	92,330	—	—	92,330
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B10-14	Colombia	CP$	7.23	%	7.04	%	No	509	—	509	—	—	—	—	57,362	57,362
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B12-13	Colombia	CP$	8.43	%	8.18	%	No	526	—	526	—	—	—	—	111,716	111,716
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B15	Colombia	CP$	7.03	%	6.85	%	No	220	—	220	—	—	—	—	61,538	61,538
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B16-14	Colombia	CP$	7.56	%	7.35	%	No	464	—	464	—	—	—	—	49,997	49,997
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B6-13	Colombia	CP$	7.66	%	7.45	%	No	201	46,963	47,164	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B6-14	Colombia	CP$	6.80	%	6.64	%	No	338	—	338	40,346	—	—	—	—	40,346
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B3-16	Colombia	CP$	6.87	%	6.70	%	No	72,999	—	72,999	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B7-16	Colombia	CP$	8.11	%	7.88	%	No	984	—	984	—	—	—	89,263	—	89,263
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds E6-16	Colombia	CP$	7.59	%	7.38	%	No	93	—	93	—	—	92,290	—	—	92,290
94.271.00-3	Enel Américas S.A.	Chile	97.036.000-k	Bonds UF 269	Chile	U.F	7.02	%	5.75	%	No	—	6,197	6,197	6,493	6,866	3,242	—	—	16,601
94.271.00-3	Enel Américas S.A.	Chile	Foreign	Yankee bonds Serie Única U.S. $ 600 millones	E.E.U.U.	US$	4.21	%	4.00	%	No	—	4,466	4,466	—	—	—	—	583,553	583,553
94.271.00-3	Enel Américas S.A.	Chile	Foreign	Yankee bonds 2026	E.E.U.U.	US$	7.76	%	6.60	%	No	—	5	5	—	—	—	—	858	858
Foreign	Enel Distribución Sao Paulo	Brasil	Foreign	Bradesco DEBENTURES - 14 EMISSAO	Brazil	R$	9.19	%	8.07	%	No	611	45,425	46,036	45,523	46,539	—	—	—	92,062
Total												264,812	177,134	441,946	202,402	439,090	350,183	227,794	1,406,658	2,626,127

F-132

												December 31, 2017
												Current			Non Current
Taxpayer			Taxpayer	Financial			Effective Interest		Nominal Interest		Secured /	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.	Institution	Country	Currency	Rate		Rate		Unsecured	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Codensa	Colombia	Foreign	B103	Colombia	CP$	9.90	%	9.55	%	No	147	26,799	26,946	—		—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bonds B12-13	Colombia	CP$	9.12	%	8.82	%	No	736	—	736	—	—	—	—	64,765	64,765
Foreign	Codensa	Colombia	Foreign	Bonds B5-13	Colombia	CP$	8.20	%	7.96	%	No	624	60,853	61,477	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Bonds B7-14	Colombia	CP$	7.80	%	7.58	%	No	90	—	90	—	—	61,972	—	—	61,972
Foreign	Codensa	Colombia	Foreign	Bonds E4-16	Colombia	CP$	7.70	%	7.49	%	No	105	—	105	—	30,148	—	—	—	30,148
Foreign	Codensa	Colombia	Foreign	Bonds E2-17	Colombia	CP$	7.04	%	6.86	%	No	232	—	232	53,597	—	—	—	—	53,597
Foreign	Codensa	Colombia	Foreign	Bonds E5-17	Colombia	CP$	7.39	%	7.39	%	No	5,457	—	5,457	—	—	—	90,445	—	90,445
Foreign	Codensa	Colombia	Foreign	Bonds E7-17	Colombia	CP$	6.46	%	6.31	%	No	278	—	278	—	—	—	—	66,996	66,996
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Itaú 2	Brazil	R$	9.46	%	9.40	%	No	568	43,467	44,035	—	—	—	—	—	—
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Itaú 1	Brazil	R$	7.64	%	6.07	%	No	282	—	282	—	—	52,152	52,602	44,909	149,663
Foreign	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Brazil	Foreign	Itaú 2	Brazil	R$	9.33	%	7.75	%	No	94	—	94	—	—	—	—	—	—
Foreign	Enel Generación Perú S.A. (ex Edegel S.A.A.)	Perú	Foreign	Banco Continental	Perú	PS$	6.41	%	6.31	%	No	—	12	12	—	—	—	7,717	—	7,717
Foreign	Enel Generación Perú S.A. (ex Edegel S.A.A.)	Perú	Foreign	Banco Continental	Perú	US$	6.44	%	6.34	%	No	274	—	274	—	—	—	—	10,016	10,016
Foreign	Enel Generación Perú S.A. (ex Edegel S.A.A.)	Perú	Foreign	Banco Continental	Perú	US$	7.93	%	7.78	%	No	283	—	283	8,179	—	—	—	—	8,179
Foreign	Enel Generación Perú S.A. (ex Edegel S.A.A.)	Perú	Foreign	Banco Scotiabank	Perú	US$	5.87	%	5.78	%	No	145	—	145	—	10,016	—	—	—	10,016
Foreign	Enel Generación Perú S.A. (ex Edegel S.A.A.)	Perú	Foreign	Banco Scotiabank	Perú	US$	6.57	%	6.47	%	No	10,290	—	10,290	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	AFP Prima	Perú	PS$	7.44	%	7.30	%	No	275	—	275	—	9,261	—	—	—	9,261
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Interseguro Cia de Seguros	Perú	PS$	6.28	%	6.19	%	No	—	166	166	—	—	—	12,347	—	12,347
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.06	%	5.97	%	No	130	—	130	—	—	—	—	15,433	15,433
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	7.28	%	7.15	%	No	281	—	281	—	—	—	—	10,958	10,958
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.75	%	6.64	%	No	368	—	368	—	15,433	—	—	—	15,433
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	7.38	%	7.24	%	No	—	159	159	—	—	—	—	18,520	18,520
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.78	%	6.67	%	No	—	459	459	—	—	30,867	—	—	30,867
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.34	%	6.25	%	No	—	59	59	—	—	—	—	18,520	18,520
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	5.84	%	5.76	%	No	—	90	90	30,867	—	—	—	—	30,867
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.34	%	6.25	%	No	—	444	444	—	—	—	—	24,693	24,693
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.13	%	6.03	%	No	603	—	603	21,607	—	—	—	—	21,607
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	8.13	%	7.97	%	No	—	502	502	—	—	—	—	21,607	21,607
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.09	%	6.00	%	No	909	—	909	—	—	—	—	30,867	30,867
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Rimac Internacional	Perú	PS$	6.00	%	5.91	%	No	—	291	291	—	—	—	—	22,349	22,349
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B09-09	Colombia	CP$	10.53	%	10.05	%	No	1,802	73,093	74,895	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B10	Colombia	CP$	10.40	%	9.94	%	No	732	—	732	53,617	—	—	—	—	53,617
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B12	Colombia	CP$	11.60	%	11.02	%	No	754	—	754	—	—	30,008	—	—	30,008
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B15	Colombia	CP$	10.73	%	10.23	%	No	262	—	262	—	—	—	—	18,592	18,592
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B6-13	Colombia	CP$	9.65	%	9.25	%	No	79	—	79	16,556	—	—	—	—	16,556
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B6-14	Colombia	CP$	8.78	%	8.44	%	No	347	—	347	—	36,827	—	—	—	36,827
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds exterior	Colombia	CP$	9.11	%	9.11	%	No	2,567	—	2,567	—	—	30,148	—	—	30,148
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds quimbo	Colombia	CP$	9.11	%	9.11	%	No	18,449	—	18,449	—	—	215,859	—	—	215,859
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B10	Colombia	CP$	8.04	%	7.76	%	No	387	—	387	—	—	—	—	100,429	100,429
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B10-14	Colombia	CP$	9.21	%	8.84	%	No	620	—	620	—	—	—	—	62,393	62,393
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B12-13	Colombia	CP$	10.44	%	9.97	%	No	631	—	631	—	—	—	—	121,522	121,522
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B15	Colombia	CP$	8.17	%	7.88	%	No	268	—	268	—	—	—	—	66,939	66,939
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B16-14	Colombia	CP$	9.54	%	9.15	%	No	562	—	562	—	—	—	—	54,471	54,471
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B6-13	Colombia	CP$	9.65	%	9.25	%	No	243	—	243	51,077	—	—	—	—	51,077
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds Quimbo B6-14	Colombia	CP$	8.78	%	8.44	%	No	413	—	413	—	43,881	—	—	—	43,881
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B3-16	Colombia	CP$	8.85	%	8.51	%	No	829	—	829	78,626	—	—	—	—	78,626
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds B7-16	Colombia	CP$	10.11	%	9.67	%	No	1,184	—	1,184	—	—	—	—	97,083	97,083
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonds E7-16	Colombia	CP$	7.38	%	7.38	%	No	102	—	102	—	—	—	100,373	—	100,373
94.271.00-3	Enel Américas S.A.	Chile	97.036.000-k	Bonds UF 269	Chile	U.F.	7.02	%	5.75	%	No	—	6,458	6,458	6,746	7,134	7,544	3,412	—	24,836
94.271.00-3	Enel Américas S.A.	Chile	Foreign	Yankee bonds Serie Única U.S. $ 600 millones	E.E.U.U.	US$	4.21	%	4.00	%	No	—	4,400	4,400	—	—	—	—	581,818	581,818
94.271.00-3	Enel Américas S.A.	Chile	Foreign	Yankee bonds 2026	E.E.U.U.	US$	7.76	%	6.60	%	No	—	5	5	—	—	—	—	858	858
Total												53,484	217,689	271,173	334,762	168,133	428,550	282,329	1,512,385	2,726,159

F-133

· Secured liabilities by company

												December 31, 2018
												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		Amortization	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Enel Distribución Río S.A.	Brasil	Foreign	Bonos 1ª Serie 19	Brazil	R$	7.39	%	7.38	%	Yes	390	—	390	154,273	—	—	—		154,273
Foreign	Enel Distribución Goias S.A.	Brasil	Foreign	ITAU - Nota Promissória 1º Emissão	Brazil	R$	6.97	%	6.96	%	Yes	—	51,539	51,539	—	—	—	—	—	—
Foreign	Enel Distribución Sao Paulo	Brasil	Foreign	DEBÊNTURES - 23ª EMISSÃO 1ª SÉRIE	Brazil	R$	7.11	%	7.01	%	Yes	3,567	—	3,567	—	180,705	—	—	—	180,705
Foreign	Enel Distribución Sao Paulo	Brasil	Foreign	DEBÊNTURES - 23ª EMISSÃO 2ª SÉRIE	Brazil	R$	7.22	%	7.19	%	Yes	7,255	—	7,255	—	—	178,330	179,893	—	358,223
Foreign	Enel Distribución Sao Paulo	Brasil	Foreign	DEBÊNTURES - 23ª EMISSÃO 3ª SÉRIE	Brazil	R$	8.24	%	8.02	%	Yes	5,054	—	5,054	—	—	—	75,205	154,315	229,520
Total												16,266	51,539	67,805	154,273	180,705	178,330	255,098	154,315	922,721

December 31, 2017

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

Amortization

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

ThUS$

Foreign

Enel Distribución Río S.A. ( ex Ampla Energía  S.A.)

Brasil

Foreign

Bonos 1ª Serie 19

Brazil

R$

7.87

%

6.18

%

Yes

492

—

492

—

180,184

—

—

—

180,184

Total

492

—

492

—

180,184

—

—

—

180,184

F-134

· Detail of finance lease obligations

									December 31, 2018
									Current			Non-Current
Taxpayer			Taxpayer	Financial			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.	Institution	Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Codensa	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP$	11.78	%	198	636	834	1,004	—	—	—	—	1,004
Foreign	Codensa	Colombia	Foreign	Equirent S.A.	Colombia	CP$	9.54	%	10	31	41	30	—	—	—	—	30
Foreign	Codensa	Colombia	Foreign	Transportes Especializados JR S.A.S.	Colombia	CP$	9.48	%	2	4	6	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Transportes Especializados Aliados S.A.S.	Colombia	CP$	12.50	%	62	141	203	565	—	—	—	—	565
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Continental	Perú	PS$	4.23	%	—	—	—	2,946	3,073	3,210	1,657	—	10,886
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Interbank	Perú	PS$	5.97	%	734	2,143	2,877	2,991	3,153	1,640	—	—	7,784
Foreign	Enel Distribución Perú S.A.	Perú	Foreign	Banco Interbank	Perú	PS$	5.32	%	94	288	382	403	424	448	—	—	1,275
Foreign	Enel Generación Piura S.A.	Perú	Foreign	Banco de Crédito	Perú	US$	5.68	%	1,980	5,941	7,921	20,290	—	—	—	—	20,290
Foreign	Enel Generación Piura S.A.	Perú	Foreign	Banco de Crédito	Perú	PS$	5.58	%	674	2,023	2,697	6,909	—	—	—	—	6,909
Foreign	Enel Generación Piura S.A.	Perú	Foreign	Banco Scotiabank	Perú	US$	3.70	%	2,451	7,179	9,630	9,571	9,571	2,393	—	—	21,535
Foreign	Enel Generación Piura S.A.	Perú	Foreign	Banco de Crédito	Perú	US$	3.63	%	581	1,774	2,355	2,442	1,252	—	—	—	3,694
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Equirent S.A.	Colombia	CP$	7.70	%	56	176	232	14	—	—	—	—	14
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP$	11.78	%	19	59	78	39	—	—	—	—	39
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Transportes Especializados JR S.A.S.	Colombia	CP$	11.69	%	112	237	349	—	—	—	—	—	—
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	AGAGUS	Brazil	R$	30.85	%	191	584	775	384	223	25	—	—	632
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	JSL 1	Brazil	R$	25.21	%	642	2,126	2,768	1,468	1,052	281	365	1,503	4,669
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	JSL 2	Brazil	R$	28.64	%	225	749	974	701	203	123	166	142	1,335
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	JSL 3	Brazil	R$	17.96	%	31	102	133	79	—	—	—	—	79
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	JSL 4	Brazil	R$	28.41	%	27	86	113	58	66	33	7	57	221
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	MAESTRO	Brazil	R$	19.50	%	162	519	681	450	515	527	—	—	1,492
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	DHL	Brazil	R$	13.39	%	116	370	486	292	331	376	389	—	1,388
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	Arval	Brazil	R$	24.90	%	429	636	1,065	132	12	—	—	—	144
Foreign	Enel Distribucion Sao Paulo	Brazil	Foreign	Vamos	Brazil	R$	8.39	%	259	808	1,067	842	912	567	—	—	2,321
Total									9,055	26,612	35,667	51,610	20,787	9,623	2,584	1,702	86,306

									December 31, 2017
									Current			Non-Current
Taxpayer			Taxpayer	Financial			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.	Institution	Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Foreign	Codensa	Colombia	Foreign	Union Temporal Rentacol	Colombia	CP$	10.80	%	50	—	50	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP$	11.78	%	30	90	120	129	100	—	—	—	229
Foreign	Codensa	Colombia	Foreign	Banco Corpbanca	Colombia	CP$	7.36	%	7	9	16	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Consorcio Empresarial	Colombia	CP$	7.08	%	97	198	295	—	—	—	—	—	—
Foreign	Codensa	Colombia	Foreign	Equirent S.A.	Colombia	CP$	9.54	%	10	31	41	45	32	—	—	—	77
Foreign	Codensa	Colombia	Foreign	Transportes Especializados JR S.A.S.	Colombia	CP$	9.48	%	2	6	8	7	—	—	—	—	7
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Continental	Perú	PS$	5.98	%	—	—	—	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Continental	Perú	PS$	5.60	%	432	435	867	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Santander Perú	Perú	PS$	5.13	%	249	—	249	—	—	—	—	—	—
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Internacional	Perú	PS$	5.94	%	44	366	410	766	812	862	450	—	2,890
Foreign	Enel Distribución Perú S.A. (ex Edelnor S.A.A.)	Perú	Foreign	Banco Internacional	Perú	PS$	5.30	%	—	—	—	60	63	67	70	—	260
Foreign	Enel Generación Piura S.A. (ex EE Piura)	Perú	Foreign	Banco de Crédito	Perú	US$	5.68	%	1,984	5,952	7,936	7,935	20,327	—	—	—	28,262
Foreign	Enel Generación Piura S.A. (ex EE Piura)	Perú	Foreign	Banco de Crédito	Perú	PS$	5.58	%	703	2,110	2,813	2,814	7,208	—	—	—	10,022
Foreign	Enel Generación Piura S.A. (ex EE Piura)	Perú	Foreign	Banco Scotiabank	Perú	US$	3.70	%	2,464	7,192	9,656	9,588	9,588	9,588	2,398	—	31,162
Foreign	Enel Generación Piura S.A. (ex EE Piura)	Perú	Foreign	Banco de Crédito	Perú	US$	3.63	%	1,362	2,045	3,407	2,807	1,440	—	—	—	4,247
Foreign	Enel Generación Perú S.A. (ex Edegel S.A.A.)	Perú	Foreign	Banco Scotiabank	Peru	US$	2.75	%	—	—	—	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco Corpbanca	Colombia	CP$	8.40	%	2	5	7	—	—	—	—	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Equirent S.A.	Colombia	CP$	7.70	%	66	199	265	252	16	—	—	—	268
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP$	11.78	%	13	39	52	52	32	—	—	—	84

Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Transportes Especializados JR S.A.S.	Colombia	CP$	11.69	%	103	337	440	337	—	—	—	—	337
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Consorcio Empresarial	Colombia	CP$	7.08	%	5	10	15	—	—	—	—	—	—
Total									7,623	19,024	26,647	24,792	39,618	10,517	2,918	—	77,845

F-135

· Detail of other obligations

									December 31, 2018
									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	Enel Distribución Ceará (ex Coelce S.A.)	Brazil	Foreign	Eletrobras	Brazil	R$	6.00	%	472	1,363	1,835	1,565	1,145	632	348	—	3,690
Foreign	Enel Generación Costanera S.A.	Argentina	Foreign	Mitsubishi (deuda garantizada)	Argentina	US$	0.25	%	—	14,322	14,322	4,200	6,643	7,142	8,242	14,002	40,229
Foreign	Emgesa S.A E.S.P	Colombia	Foreign	Banco Santander	Spain	CP$	6.15	%	14,679	—	14,679	—	—	—	—	—	—
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	Eletrobras	Brazil	R$	6.00	%	185	554	739	690	690	690	690	345	3,105
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	Mútuo CelgPar 41211376/2014	Brazil	R$	6.80	%	732	2,040	2,772	2,256	2,256	2,466	2,689	12,665	22,332
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	FIDC Série A	Brazil	R$	9.67	%	3,733	6,614	10,347	10,437	10,437	10,437	4,605	—	35,916
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	FIDC Série B	Brazil	R$	14.15	%	2,164	6,046	8,210	7,682	7,682	7,682	4,323	—	27,369
Foreign	Enel Distribucion Goias S.A	Brazil	Foreign	ITAU - Nota Promissoria 1° Emissao	Brazil	R$	6.96	%	2,529	—	2,529	—	—	—	—	—	—
Total									24,494	30,939	55,433	26,830	28,853	29,049	20,897	27,012	132,641

									December 31, 2017
									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	Enel Distribución Ceará (ex Coelce S.A.)	Brazil	Foreign	Eletrobras	Brazil	R$	6.13	%	643	1,702	2,345	2,144	1,828	1,336	736	404	6,448
Foreign	Enel Generación Costanera S.A.	Argentina	Foreign	Mitsubishi (deuda garantizada)	Argentina	US$	0.25	%	762	2,176	2,938	3,000	3,000	3,000	3,000	36,913	48,913
Foreign	CELG Distribuição S.A.	Brazil	Foreign	Centrais Eletricas Brazileiras  Ebras_ECF - 017/2004	Brazil	R$	7.00	%	112	194	306	—	—	—	—	—	—
Foreign	CELG Distribuição S.A.	Brazil	Foreign	Centrais Eletricas Brazileiras  Ebras_ECF - 149/2006	Brazil	R$	7.00	%	447	773	1,220	—	—	—	—	—	—
Foreign	CELG Distribuição S.A.	Brazil	Foreign	Centrais Eletricas Brazileiras  Ebras_ECF - 232/2008	Brazil	R$	7.00	%	318	656	974	842	842	842	842	1,263	4,631
Foreign	CELG Distribuição S.A.	Brazil	Foreign	Mútuo CelgPar 41211376/2014	Brazil	R$	6.80	%	1,480	4,441	5,921	2,967	3,214	2,967	2,967	14,093	26,208
Foreign	CELG Distribuição S.A.	Brazil	Foreign	FIDC Série A	Brazil	R$	10.20	%	3,766	10,250	14,016	13,665	13,665	13,665	13,665	7,971	62,631
Foreign	CELG Distribuição S.A.	Brazil	Foreign	FIDC Série B	Brazil	R$	12.78	%	2,181	5,766	7,947	7,688	7,688	7,688	7,688	4,485	35,237
Total									9,709	25,958	35,667	30,306	30,237	29,498	28,898	65,129	184,068

F-136

21.4   Hedged debt

The debt denominated in U.S. dollars for ThUS$40,867 held by the Group as of December 31, 2018, is related to future cash flow hedges for the Group’s U.S. dollar-linked operating revenues (ThUS$68,868 and ThUS$158,960 as of December 31, 2017 and 2016, respectively) (see Note 4.n).

The following table details changes in “Reserve for cash flow hedges” for the years ended December 31, 2018 and 2017, due to exchange differences from this debt:

	12-31-2018		12-31-2017		12-31-2016
	ThUS$		ThUS$		ThUS$
Balance in hedging reserves (hedging revenues) at the beginning of the year, net	(9,754	)	(11,577	)	(8,571	)
Foreign currency exchange differences recorded in equity, net	(1,181	)	2,311		181
Recognition of foreign currency exchange differences revenue, net	634		(78	)	(225	)
Foreign currency translation differences	419		(410	)	540
Transfer to assets held for distribution to owners	—		—		—
Other	—		—		(3,502	)
Balance in hedging reserves (hedging revenues) at the end of the year, net	(9,882	)	(9,754	)	(11,577	)

21.5   Other information

As of December 31, 2018, the Group has long-term, lines of credit available for use amounting to ThUS$1,000,000 (ThUS$224,766 as of December 31, 2017).

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21.6   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	Maturity					Total Non-Current
		Nominal Interest		One to three months	Three to twelve months	12/31/2018	One to two years	Two to three years	Three to four years	Four to five years	More than five years	12/31/2018
Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	3.36		2,999	351,000	353,999
Perú	US$	3.40	%	422	—	422						—
Perú	Soles	3.75	%	26,165	717	26,882	956	22,674				23,630
Colombia	CP	6.07	%	68,134	44,924	113,058	41,705	12,869	10,420	9,741		74,735
Brazil	US$	4.53	%	82,801	322,745	405,546	284,051	206,196	134	134	2,821	493,336
Brazil	Real	8.59	%	75,422	116,056	191,478	112,716	99,173	58,994	21,879	41,612	334,374
Total				255,943	835,442	1,091,385	439,428	340,912	69,548	31,754	44,433	926,075

				Current			Non-Current
				Maturity		Total Current	Maturity					Total Non-Current
		Nominal Interest		One to three months	Three to twelve months	12/31/2017	One to two years	Two to three years	Three to four years	Four to five years	More than five years	12/31/2017
Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Perú	US$	3.23	%	8,858	1,289	10,147	422	—	—	—	—	422
Perú	Soles	5.32	%	22,534	27,659	50,193	—	—	—	—	—	—
Colombia	US$	1.88	%	34,943	—	34,943	—	—	—	—	—	—
Colombia	CP	7.10	%	8,810	39,169	47,979	127,925	51,070	19,078	15,887	14,596	228,556
Brazil	US$	3.83	%	6,013	55,936	61,949	357,542	237,284	77,649	130	2,949	675,554
Brazil	Real	10.84	%	55,353	143,274	198,627	157,767	94,337	72,602	34,871	4,609	364,186
Total				136,511	267,327	403,838	643,656	382,691	169,329	50,888	22,154	1,268,718

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·Summary of secured and unsecured bonds by currency and maturity

				Current			Non-Current
				Maturity		Total Current	Maturity					Total Non-Current
		Nominal Interest		One to three months	Three to twelve months	12/31/2018	One to two years	Two to three years	Three to four years	Four to five years	More than five years	12/31/2018
Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	5.30	%	6,265	18,794	25,059	25,059	25,059	25,059	25,059	671,868	772,104
Chile	U.F.	5.75	%	571	7,703	8,274	8,011	7,732	3,757	—	—	19,500
Perú	US$	6.64	%	8,513	885	9,398	11,039	617	617	617	12,520	25,410
Perú	Soles	6.34	%	12,238	74,973	87,211	59,512	47,306	50,068	61,039	258,872	476,797
Colombia	CP	7.44	%	199,799	141,016	340,815	200,620	385,414	329,556	191,919	624,854	1,732,363
Brazil	Real	7.91	%	61,663	164,272	225,935	283,858	339,053	274,230	322,022	267,150	1,486,313
Total				289,049	407,643	696,692	588,099	805,181	683,287	600,656	1,835,264	4,512,487

				Current			Non-Current
				Maturity		Total Current	Maturity					Total Non-Current
		Nominal Interest		One to three months	Three to twelve months	12/31/2017	One to two years	Two to three years	Three to four years	Four to five years	More than five years	12/31/2017
Country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Chile	US$	5.30	%	6,265	18,794	25,059	25,059	25,059	25,059	25,059	721,986	822,222
Chile	U.F.	5.75	%	662	8,235	8,897	8,724	8,541	8,347	4,097	—	29,709
Perú	US$	6.59	%	10,517	1,390	11,907	9,435	11,071	636	636	13,233	35,011
Perú	Soles	6.30	%	6,248	18,749	24,997	89,204	60,357	47,647	50,524	291,563	539,295
Colombia	CP	8.69	%	34,835	261,813	296,648	364,584	210,708	414,025	352,720	677,138	2,019,175
Brazil	Real	6.94	%	6,311	61,825	68,136	21,149	202,527	62,841	59,630	50,680	396,827
Total				64,838	370,806	435,644	518,155	518,263	558,555	492,666	1,754,600	3,842,239

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·Summary of finance lease by currency and maturity

				Current			Non-Current
				Maturity			Maturity
		Nominal Interest		One to three months	Three to twelve months	Total Current 12/31/2018	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current 12/31/2018
Segment country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Perú
Perú	US$	4.34	%	5,756	16,939	22,695	33,725	11,180	2,417	—	—	47,322
Colombia	Soles	5.23	%	1,944	5,748	7,692	14,398	7,223	5,492	1,671	—	28,784
Brasil	$ Col	9.60	%	517	1,325	1,842	1,086	98	—	—	—	1,184
	Real	20.35	%	2,599	7,182	9,781	5,443	3,925	2,324	1,197	2,002	14,891
	Total			10,816	31,194	42,010	54,652	22,426	10,233	2,868	2,002	92,181

				Current			Non-Current
				Maturity			Maturity
		Nominal Interest		One to three months	Three to twelve months	Total Current 12/31/2017	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current 12/31/2017
Segment country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Perú	US$	3.96	%	6,751	17,916	24,667	23,097	32,665	9,938	2,419	—	68,119
Perú	Soles	5.65	%	1,632	3,565	5,197	4,325	8,393	998	532	—	14,248
Colombia	$ Col	9.34	%	484	1,087	1,571	920	174	—	—	—	1,094
	Total			8,867	22,568	31,435	28,342	41,232	10,936	2,951	—	83,461

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·Summary of other obligations by currency and maturity

				Current			Non-Current
				Maturity			Maturity					Total Non-
		Nominal Interest		One to three months	Three to twelve months	Total Current 12/31/2018	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Current 12/31/2018
Segment country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Argentina	US$	0.25	%	2,091	12,576	14,667	2,783	10,911	4,115	4,136	20,515	42,460
Brasil	Real	7.68	%	10,293	30,195	40,488	35,824	33,141	29,992	18,085	14,742	131,784
Colombia	$ Col	6.15	%	14,821	—	14,821	—	—	—	—	—	—
Total				27,205	42,771	69,976	38,607	44,052	34,107	22,221	35,257	174,244

				Current			Non-Current
				Maturity			Maturity					Total Non-
		Nominal Interest		One to three months	Three to twelve months	Total Current 12/31/2017	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Current 12/31/2017
Segment country	Currency	Rate		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Argentina	US$	1.39	%	663	3,208	3,871	5,080	2,759	15,553	4,095	24,563	52,050
Brasil	Real	7.86	%	14,406	40,685	55,091	46,646	43,072	38,828	34,777	33,785	197,108
Total				15,069	43,893	58,962	51,726	45,831	54,381	38,872	58,348	249,158

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22.RISK MANAGEMENT POLICY

The Group’s companies are exposed to certain risks that are managed by systems that identify, measure, limit concentration of, and monitor these risks.

The main principles in the Group’s risk management policy include the following:

·Compliance with proper corporate governance standards.

·Strict compliance with all of Group’s internal policies.

·Each business and corporate area determines:

I)The markets in which it can operate based on its knowledge and ability to ensure effective risk management;

II)Criteria regarding counterparts;

III)Authorized operators.

·Business and corporate areas establish their risk tolerance in a manner consistent with the defined strategy for each market in which they operate.

·All of the operations of the businesses and corporate areas are conducted within the limits approved for each case.

·Businesses, corporate areas, lines of business and companies design the risk management controls necessary to ensure that transactions in the markets are conducted in accordance with the Group’s policies, standards, and procedures.

22.1Interest 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 financial debt structure of the Group detailed by the mostly strongly hedged fixed and floating interest rates on total net debt, net of hedging derivative instruments, is as follows:

Gross position:

	12-31-2018		12-31-2017
	%		%
Fixed interest rate debt	59	%	46	%

22.2Exchange 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.

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·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 this 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 pursues to refinance debt in the functional currency of each of the Group’s companies.

22.3Commodities risk

The Enel Américas 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.

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, 2018, there were transactions of purchases of energy futures contracts for 5.28 GWh.

Such purchases cover an energy sales contract in the wholesale market As of December 31, 2018, 10.92 GWh of forward energy sale contracts and 7.2 GWh of forward energy purchase contracts were settled.

As of December 31, 2017, there are transactions of purchases of energy futures contracts for 5.4 GWh for the period January-March 2018. Such purchases cover an energy sales contract in the Colombian wholesale market.

As of December 31, 2017, 24.23 GWh of forward energy sale contracts and 77.45 GWh of forward energy purchase contracts were settled.

22.4Liquidity 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.

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 21 and 23).

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As of December 31, 2018, the Group has cash and cash equivalents for ThUS$1,904,285 and unconditionally available lines of long-term credit for ThUS$1,000,000. As of December 31, 2017, the Group had cash and cash equivalents for ThUS$1,472,763 and unconditionally available lines of long-term credit for ThUS$224,766.

22.5Credit 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.

In our electricity distribution companies, the suspension of energy service to customers in payment default is permitted in all cases, in accordance with current regulations in each country. This facilitates our credit risk management, which is also low in this line of business.

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).

22.6Risk 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 income statement.

The portfolio of positions included for purposes of calculating the present Value at Risk include:

·Financial debt

·Hedge 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, with respect to the Chilean peso, 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.

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The calculation of VaR is based on generating possible future scenarios (at one quarter) of market values (both spot and term) for the risk variables, using Bootstrapping simulations.

The quarter 95%-confidence VaR number is calculated as the 5% percentile most adverse of the quarterly possible fluctuations.

Taking into consideration the assumptions previously described, the quarter VaR of the previously discussed positions was ThUS$630,479.

This value represents the potential increase of the Debt and Derivatives’ Portfolio, thus these Values at Risk are inherently related, among other factors, to the Portfolio’s value at each quarter end.

23.FINANCIAL INSTRUMENTS

23.1Financial instruments, classified by type and category

a)The detail of financial assets, classified by type and category, as of December 31, 2018 and 2017, is as follows:

	December 31, 2018
	Financial assets at fair value with changes in results	Financial assets measured at amortized cost	Financial assets at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThUS$	ThUS$	ThUS$	ThUS$
Trade accounts receivable and other accounts receivable	—	3,565,359	—	—
Derivative instruments	3,311	—	—	41,113
Other financial assets	128,956	37,013	—
Total Current	132,267	3,602,372	—	41,113
Equity instruments	—	—	753	—
Trade accounts receivable and other accounts receivable	—	908,160	—	—
Derivative instruments	13,344	—	—	56,385
Other financial assets	2,371,649	354,344
Total Non-Current	2,384,993	1,262,504	753	56,385
Total	2,517,260	4,864,876	753	97,498

	December 31, 2017
	Financial assets at fair value with changes in results	Financial assets measured at amortized cost	Financial assets at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThUS$	ThUS$	ThUS$	ThUS$
Trade accounts receivable and other accounts receivable	—	2,394,756	—	—
Derivative instruments	404	—	—	2,168
Other financial assets	49,757	14,286	—	—
Total Current	50,161	2,409,042	—	2,168
Equity instruments	1,104	—	—	—
Trade accounts receivable and other accounts receivable	—	619,637	—	—
Derivative instruments	4,898	—	—	19,932
Other financial assets	1,312,871	413,462	—
Total Non-Current	1,318,873	1,033,099	—	19,932
Total	1,369,034	3,442,141	—	22,100

b)The detail of financial liabilities, classified by type and category, as of December 31, 2018 and 2017, is as follows:

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	December 31, 2018
	Financial liabilities held for trading	Loans and payables	Financial derivatives for hedging
	ThUS$	ThUS$	ThUS$
Interest-bearing loans	—	1,642,504	—
Commercial accounts and other accounts payable	—	6,892,192	—
Derivative instruments	—	—	—
Other financial liabilities	380	—	5,215
Total Current	380	8,534,696	5,215
Interest-bearing loans	—	4,621,855	—
Commercial accounts and other accounts payable	—	930,891	—
Derivative instruments	—	—	13
Other financial liabilities	—	—
Total Non-Current	—	5,552,746	13
Total	380	14,087,442	5,228

	December 31, 2017
	Financial liabilities held for trading	Loans and payables	Financial derivatives for hedging
	ThUS$	ThUS$	ThUS$
Interest-bearing loans	—	670,916	—
Commercial accounts and other accounts payable		3,255,603
Derivative instruments	1,270	—	17,582
Other financial liabilities	—	—	—
Total Current	1,270	3,926,519	17,582
Interest-bearing loans	—	4,333,042	—
Commercial accounts and other accounts payable		978,569
Derivative instruments	8,671	—	7,802
Other financial liabilities	—	—	—
Total Non-Current	8,671	5,311,611	7,802
Total	9,941	9,238,130	25,384

23.2Derivative 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.

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·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).

a)            Assets and liabilities for hedge derivative instruments

As of December 31, 2018 and 2017, financial derivative qualifying as hedging instruments resulted in recognition of the following assets and liabilities in the statement of financial position:

	December 31, 2018				December 31, 2017
	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:	442	—	1,599	—	796	850	40	—
Cash flow hedge	442		1,599		796	850	40	—
Exchange rate hedge:	43,982	69,729	3,996	13	1,372	19,082	17,541	7,802
Cash flow hedge	40,671	56,385	3,681	13	1,372	19,082	9,056	—
Fair value hedge	3,311	13,344	315		—	—	8,485	7,802
TOTAL	44,424	69,729	5,595	13	2,168	19,932	17,581	7,802

·General information on hedge 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 12-31-2018 ThUS$		Fair Value of Hedged Item 12-31-2017 ThUS$
SWAP	Interest rate	Bank loans	(567	)	11,214
SWAP	Interest rate	Unsecured obligations (bonds)	(592	)	—
SWAP	Exchange rate	Bank loans	93,210		(16,287	)
SWAP	Exchange rate	Bank loans	16,341		1,607
SWAP	Exchange rate	Operational Income	153		—
FORWARD	Exchange rate	Unsecured obligations (bonds)	—		48
FORWARD	Exchange rate	Operating costs	—		136

As of December 31, 2018 and 2017, 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 during the years ended December 31, 2018 and 2017, is detailed in the following table:

	December 31, 2018		December 31, 2017
	Gains ThUS$	Losses ThUS$	Gains ThUS$	Losses ThUS$
Hedging derivative instrument	—	21,128	5,700	9,396
Underlying hedged item	1,218	—	488	5,695
TOTAL	1,218	21,128	6,188	15,091

b)    Financial derivative instruments assets and liabilities at fair value through profit or loss

As of December 31, 2018 and 2017, 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:

F-147

	December 31, 2018				December 31, 2017
	Assets		Liabilities		Assets		Liabilities
	Current ThUS$	Non-Current ThUS$	Current ThUS$	Non-Current ThUS$	Current ThUS$	Non-Current ThUS$	Current ThUS$	Non-Current ThUS$
Non-hedging derivative instrument (1)	23,584	—	—	—	404	4,898	1,270	8,671

(1)Includes 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. Also, it includes cross currency swaps to cover the interest rate and foreign exchange risks of financial debts which as part of the corporate reorganization were transferred to Enel Chile, thus, discontinuing the hedge accounting.

b)    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, 2018 and 2017:

	December 31, 2018
			Notional amount
	Fair value		Less than 1 year	1 - 2 years	2 - 3 years	3 - 4 years	4 - 5 years	Total
Financial Derivatives	ThUS$		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Interest rate hedge:	(1,157	)	697,840	—	—	—	—	697,840
Cash flow hedge	(1,157	)	697,840	—				697,840
Exchange rate hedge:	109,702		441,328	229,689	172,912	—	—	843,929
Cash flow hedge	93,362		369,655	229,689	90,327			689,671
Fair value hedge	16,340		71,673	—	82,585			154,258
Derivatives not designated for hedge accounting	23,584		577,390	—	—			577,390
TOTAL	132,129		1,716,558	229,689	172,912	—	—	2,119,159

	December 31, 2017
			Notional Amount
	Fair value		Less than 1 year	1 - 2 years	2 - 3 years	3 - 4 years	4 - 5 years	Total
Financial Derivatives	ThUS$		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Interest rate hedge:	1,607		46,120	162,043	—	—	—	208,163
Cash flow hedge	1,607		46,120	162,043	—	—	—	208,163
Exchange rate hedge:	(4,890	)	97,144	343,929	223,700	75,574	—	740,347
Cash flow hedge	11,397		46,436	259,976	223,700	75,574	—	605,686
Fair value hedge	(16,287	)	50,708	83,953	—	—	—	134,661
Derivatives not designated for hedge accounting	(4,639	)	58,247	433,797	—	—	—	492,044
TOTAL	(7,922	)	201,511	939,769	223,700	75,574	—	1,440,554

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 up based on undiscounted contractual cash inflows and outflows for their settlement.

23.3Fair value hierarchies

Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the hierarchies described in Note 4.g.

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The following table presents financial assets and liabilities measured at fair value as of December 31, 2018 and 2017:

	Fair Value Measured at End of Reporting Period Using:
	12-31-2018	Level 1	Level 2	Level 3
Financial Instruments Measured at Fair Value	ThUS$	ThUS$	ThUS$	ThUS$
Financial Assets
Financial derivatives designated as cash flow hedge	97,498	—	97,498	—
Financial derivatives designated as fair value hedge	16,655	—	16,655	—
Financial assets at fair value through profit or loss	23,584	—	23,584	—
Financial assets at fair value with changes in other comprehensive income	753	—	753	—
Financial assets at fair value through profit or loss	2,477,021	105,386	2,371,635	—
Total	2,615,511	—	2,510,125	—
Financial Liabilities
Financial derivatives designated as cash flow hedge	5,293	—	5,293	—
Financial derivatives designated as fair value hedge	315	—	315	—
Financial derivatives not designated for hedge accounting	—	—	—	—
Total	5,608	—	5,608	—

	Fair Value Measured at End of Reporting Period Using:
	12-31-2017	Level 1	Level 2	Level 3
Financial Instruments Measured at Fair Value	ThUS$	ThUS$	ThUS$	ThUS$
Financial Assets
Financial derivatives designated as cash flow hedge	22,100	—	22,100	—
Financial derivatives not designated for hedge accounting	5,302	—	5,302	—
Financial assets at fair value through profit or loss	49,345	49,345	—	—
Available-for-sale financial assets, long term	1,740,592	—	1,740,592	—
Total	1,817,339	49,345	1,767,994	—
Financial Liabilities
Financial derivatives designated as cash flow hedge	9,096	—	9,096	—
Financial derivatives designated as fair value hedge	16,287	—	16,287	—
Financial derivatives not designated for hedge accounting	9,942	—	9,942	—
Interest-bearing borrowings short term	—	—	—	—
Interest-bearing borrowings long term	—	—	—	—
Total	35,325	—	35,325	—

23.3.1 Financial instruments whose fair value measurement is classified as Level 3:

The Group does not have financial instruments measured at fair value whose fair value measurement is classified as Level 3.

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24.TRADE AND OTHER CURRENT AND NON-CURRENT PAYABLES

The detail of Trade and Other Current Payables as of December 31, 2018 and 2017 is as follows:

	Current		Non-Current
	12-31-2018	12-31-2017	12-31-2018	12-31-2017
Trade and Other Payables	ThUS$	ThUS$	ThUS$	ThUS$
Trade current payables
Energy suppliers	1,069,698	679,097	194,586	263,907
Fuel and gas suppliers	19,296	22,585	—	—
Payables for goods and services	908,269	1,049,507	12,094	34,109
Payables for assets acquisitions	109,457	29,659	15,066	16,872
Subtotal Trade Payables	2,106,720	1,780,848	221,746	314,888
Other payables
Dividends payable to non-controlling interests	218,424	69,597	—	—
Payables to CAMMESA (1)	304,259	388,281	183,843	315,921
Fines and complaints (2)	164,123	238,300	—	—
Research and development	110,996	28,646	99,334	106,341
Taxes payables other than income tax	220,722	437,163	2,165	17,393
Accounts payables to staff	196,351	190,947	103	14,385
Regulatory Liabilities Brazilian Subsidiaries	568,085	162,584	401,029	138,854
Other payables	226,567	27,487	24,836	70,787
Subtotal other current payables	2,009,527	1,543,005	711,310	663,681
Total	4,116,247	3,323,853	933,056	978,569

See Note 22.4 for the description of the liquidity risk management policy.

(1)As of December 31, 2018, the balance includes ThUS$257,715 from our subsidiary Edesur related to the payables for energy purchases from CAMMESA (ThUS$320,238 as of December 31, 2017). In addition, it included a total amount of ThUS$230,387 (ThUS$ 383,964 as of December 31, 2017) related to the loan agreements signed with CAMMESA for (i) financing the functional operational needs of the power generating plant of our subsidiary Enel Generación Costanera, (ii) financing the maintenance needs of the turbosteam generators in our subsidiary Dock Sud, and (iii) financing the Extraordinary Investment Plan our subsidiary Edesur.

(2)Corresponds mainly to fines and complaints that our Argentine subsidiary Edesur S.A. has received during the current and prior years from the regulatory agency due to business service quality, technical product quality, and public safety. These fines have not been paid, as some were suspended under the Agreement Act signed in 2007 with the Argentine government, the amount of these fines and complaints is updated in line with the adjustments to the value added from distribution as part of tariff reviews. As of December 31, 2018 as a result of application of ENRE Resolution No. 1/2016, the financial update of those fines and complaints resulted in an  expense of ThUS$48,555 (ThUS$65,398 as of December 31, 2017)

The detail of trade payables, both up to date and past due as of December 31, 2018 and 2017 are presented in Appendix 3.

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25.          PROVISIONS

a)The detail of provisions as of December 31, 2018 and 2017, is as follows:

	Current		Non-Current
	12-31-2018	12-31-2017	12-31-2018	12-31-2017
Provisions	ThUS$	ThUS$	ThUS$	ThUS$
Provisions for legal proceedings (*)	387,763	232,680	1,303,973	595,810
Decommissioning or restoration (**)	30,245	33,498	57,475	56,780
Provision for environmental issues (***)	1,044	280	721	22
Other provisions	3,811	3,508	1,807	7,693
Total	422,863	269,966	1,363,976	660,305

(*)Includes ThUS$581,807 in a non-current portion due to the acquisition of Enel Distribución Sao Paulo S.A. by Enel Brasil (see Note 7.2).

(**)Includes the provision for restoration of our subsidiary Emgesa related to the El Quimbo Project, regarding the necessary works to mitigate the environmental impact of filling the dam. The works are estimated to take 30 years. The main activities under this obligation, among other things, are forest restoration, border protection, lotic and fishing programs and flora and fauna monitoring programs.

(***)Includes obligations for the environmental license for the El Quimbo Project, such as settlement of contracts for completed works and minor works necessary to operate the power plant at 2016.

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.

b)Changes in provisions for the years ended December 31, 2018 and 2017, are as follows:

	Legal Proceedings		Decommissioning or Restoration		Environmental Issues and Other Provisions		Total
Provisions	ThUS$		ThUS$		ThUS$		ThUS$
Changes in Provisions
Balance as of January 1, 2018	828,490		90,278		11,503		930,271
Increase (decrease) in existing provisions	331,820		14,798		(38,889	)	307,729
Acquisition of Business combination	869,545		—		65,943		935,488
Provision used	(159,421	)	(13,855	)	(31,138	)	(204,414	)
Increase from adjustment to time value of money	143,917		2,997		280		147,194
Foreign currency translation	(232,915	)	(6,498	)	(316	)	(239,729	)
Transfer to P&L	(89,700	)	—		—		(89,700	)
Total Changes in Provisions	863,246		(2,558	)	(4,120	)	856,568
Balance as of December 31, 2018	1,691,736		87,720		7,383		1,786,839

	Legal Proceedings		Decommissioning or Restoration		Environmental Issues and Other Provisions		Total
Provisions	ThUS$		ThUS$		ThUS$		ThUS$
Changes in Provisions
Balance as of January 1, 2017	397,392		15,280		115,048		527,720
Increase (decrease) in existing provisions	345,989		90,656		(104,284	)	332,361
Acquisition of Business combination	229,358		—		—		229,358
Provision used	(214,373	)	(21,393	)	(1,060	)	(236,826	)
Increase from adjustment to time value of money	166,930		6,306		2,595		175,831
Foreign currency translation	(42,372	)	(483	)	1,596		(41,259	)
Transfer to P&L	(54,434	)	(88	)	(2,392	)	(56,914	)
Total Changes in Provisions	431,098		74,998		(103,545	)	402,551
Balance as of December 31, 2017	828,490		90,278		11,503		930,271

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26.EMPLOYEE BENEFIT OBLIGATIONS

26.1 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 4.l.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.

·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, which depending on the company, varies within a range from 5 to 15 years.

b)Other benefits

Five-year benefit: A benefit certain employees receive after 5 years and which begins to accrue from the second year onwards.

Unemployment: A benefit paid regardless of whether the employee is fired or leaves voluntarily. This benefit accrues on a daily basis and is paid at the time of contract termination (although the law allows for partial withdrawals for housing and education).

Seniority bonuses:

There is an agreement to give workers (“subject to the collective 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
5, 10, 15	1 monthly salary
20	1.5 monthly salary
25, 30, 35, 40	2.5 monthly salaries

Health plan: Corresponds to a medical and dental benefit granted to the immediate family of retired employees of Emgesa. The benefit covers the immediate family, and in the event of the death of the beneficiary, the benefit is extended for six months, after which time the benefit is no longer provided.

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.

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26.2Details, 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, 2018 and 2017, are detailed as follows:

General ledger accounts:

	Balance as of
	12-31-2018	12-31-2017
	ThUS$	ThUS$
Post-employment obligations, non-current	1,343,507	388,931
Total Liabilities	1,343,507	388,931
Total Post-Employment Obligations, Net	1,343,507	388,931

Reconciliation with general ledger accounts:

	Balance as of
	12-31-2018		12-31-2017
	ThUS$		ThUS$
Post-employment obligations	4,235,466		1,063,551
(-) Fair value of plan assets (*)	(2,919,501	)	(751,669	)
Total	1,315,965		311,882
Amount not recognized due to limit on Plan Assets Ceiling (**)	21,463		47,918
Minimum funding required (IFRIC 14) (***)	6,079		29,131
Total Post-Employment Obligations, Net	1,343,507		388,931

(*)Plan assets to fund defined benefit plans only in our Brazilian subsidiaries (Enel Distribución Rio S.A. and Enel Distribución Ceará S.A.).

(**)In Enel Distribución Ceará S.A., certain pension plans currently have an actuarial surplus amounting to ThUS$21,463 as of December 31, 2018 (ThUS$47,918 as of December 31, 2017), 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 the Foundation 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. has been recognized in accordance with the provisions of IFRIC 14 - The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction an additional liability as of December 31, 2018 for ThUS$6,079 (ThUS$29,131 as of December 31, 2017). 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.

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b)The following amounts were recognized in the consolidated statement of comprehensive income for the years ended December 31, 2018, 2017 and 2016:

	12-31-2018		12-31-2017		12-31-2016
Expense Recognized in Comprehensive Income	ThUS$		ThUS$		ThUS$
Current service cost for defined benefits plan	6,383		4,074		3,704
Interest cost for defined benefits plan	269,331		112,196		87,079
Interest income from the plan assets	(190,283	)	(79,193	)	(62,649	)
Past service cost	(850	)	5,923		2,601
Interest cost on asset ceiling components	4,373		4,305		5,141
Expenses recognized in Profit or Loss	88,954		47,305		35,876
Losses from remeasurement of defined benefit plans	177,527		4,941		29,399
Total expense recognized in Comprehensive Income	266,481		52,246		65,275

c)The presentation of net actuarial liabilities as of December 31, 2018 and 2017, are as follows

Net Actuarial Liability	ThUS$
Balance as of January 1, 2017	341,353
Net interest cost	37,308
Service cost	4,074
Benefits paid	(18,275	)
Contributions paid	(63,862	)
Actuarial (gains) losses from changes in financial assumptions	43,327
Actuarial (gains) losses from changes in experience adjustments	(3,511	)
Return on plan assets, excluding interest	(52,650	)
Changes in the asset limit	11,317
Minimum finding required (IFRIC 14)	6,458
Past service cost Defined benefit plan obligations	5,923
Defined benefit plan obligations from business combinations	88,003
Transfer of employees	(21	)
Foreign currency translation differences	(10,513	)
Balance as of December 31, 2017	388,931
Net interest cost	83,421
Service cost	6,383
Benefits paid	(15,778	)
Contributions paid	(94,629	)
Actuarial (gains) losses from changes in financial assumptions	272,123
Actuarial (gains) losses from changes in experience adjustments	71,519
Return on plan assets, excluding interest	(121,042	)
Changes in the asset limit	(25,081	)
Minimum finding required (IFRIC 14)	(19,992	)
Past service cost Defined benefit plan obligations	(850	)
Defined benefit plan obligations from business combinations	870,687
Transfer of employees	88
Foreign currency translation differences	(72,273	)
Net actuarial liability as of December 31, 2018	1,343,507

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d)The balance and changes in post-employment defined benefit obligations as of December 31, 2018 and 2017 are as follows:

Actuarial Value of Post-employment Obligations	ThUS$
Balance as of January 1, 2017	859,452
Service cost	4,074
Interest cost	112,196
Contributions from plan participants	687
Actuarial (gains) losses from changes in financial assumptions	43,327
Actuarial (gains) losses from changes in experience adjustments	(3,511	)
Foreign currency translation	(23,743	)
Contributions paid	(116,645	)
Past service cost Defined benefit plan obligations	5,923
Defined benefit plan obligations from business combinations	181,812
Transfer of employees	(21	)
Balance as of December 31, 2017	1,063,551
Service cost	6,383
Interest cost	269,331
Contributions from plan participants	1,781
Actuarial (gains) losses from changes in financial assumptions	272,123
Actuarial (gains) losses from changes in experience adjustments	71,519
Foreign currency translation	(196,015	)
Contributions paid	(275,600	)
Past service cost Defined benefit plan obligations	(850	)
Defined benefit plan obligations from business combinations	3,023,155
Transfer of employees	88
Balance as of December 31, 2018	4,235,466

As of December 31, 2018, the post-employment benefit obligations are allocated as follows: 0.06% is from defined benefit plans in the Chilean holding company (0.27% as of December 31, 2017), 96.56% is from defined benefit plans in Brazilian companies (84.78% as of December 31, 2017), 2.91% is from defined benefit plans in Colombian companies (11.99% as of December 31, 2017), 0.35% is from defined benefit plans in Argentine companies (2.53% as of December 31, 2017), and the remaining 0.12% is from defined benefit plans in Peruvian companies (0.43% as of December 31, 2017).

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Changes in the fair value of the benefit plan assets are as follows:

Fair Value of Plan Assets	ThUS$
Balance as of January 1, 2017	(574,815	)
Interest income	(79,193	)
Return on plan assets, excluding interest	(52,650	)
Foreign currency translation differences	14,977
Employer contributions	(63,862	)
Benefit paid	(687	)
Benefits	98,370
Defined benefit plan obligations from business combinations	(93,809	)
Balance as of December 31, 2017	(751,669	)
Interest income	(190,283	)
Return on plan assets, excluding interest	(121,042	)
Foreign currency translation differences	132,549
Employer contributions	(94,629	)
Benefit paid	259,822
Benefits	(1,781	)
Defined benefit plan obligations from business combinations	(2,152,468	)
Balance as of December 31, 2018	(2,919,501	)

e)The main categories of benefit plan assets are as follows:

	12-31-2018			12-31-2017
Category of Plan Assets	ThUS$	%		ThUS$	%
Equity instruments (variable income)	233,854	8.01	%	64,686	8.61	%
Fixed-income assets	2,418,502	82.84	%	581,306	77.34	%
Real estate investments	145,879	5.00	%	76,748	10.21	%
Other	121,266	4.15	%	28,929	3.85	%
Total	2,919,501	100	%	751,669	100	%

The plans for retirement benefits and pension funds held by our Brazilian subsidiaries, Enel Distribución Rio S.A., Enel Distribución Ceará 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, Faelce (an institution providing pension funds exclusively to employees and retired employees of Enel Distribución Ceará) holds common shares of Enel Distribución Ceará, Brasiletros (a similar institution for employees of Enel Distribución Rio) and Eletra (an institution pension fund exclusively for employees and retired staff Enel Distribución Sao Paulo) holds shares in investment funds with a portfolio traded on Bovespa (the São Paulo Stock Exchange). Finally, with regards 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.

The following table sets forth the assets affected by the plans and invested in shares, leases and real estate owned by the Group:

	12-31-2018	12-31-2017
	ThUS$	ThUS$
Real Estate	30,405	34,487
Total	30,405	34,487

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f)Reconciliation of asset ceiling:

Reconciliation of Asset Ceiling	ThUS$
Balance as of January 1, 2017	33,419
Interest on assets not recognized	4,305
Other changes in assets not recognized due to asset limit	11,317
Foreign currency translation differences	(1,123	)
Balance as of December 31, 2017	47,918
Interest on assets not recognized	4,373
Other changes in assets not recognized due to asset limit	(25,081	)
Foreign currency translation differences	(5,747	)
Total asset ceiling as of December 31, 2018	21,463

26.3Other revelations

·Actuarial assumptions:

As of December 31, 2018 and 2017, the following assumptions were used in the actuarial calculation of defined benefit plans:

	Chile		Brazil		Colombia		Argentina		Peru
	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018	12-31-2017
Discount rates used	4.70%	5.00%	7.90% - 9.15%	8.68% - 9.93%	6.80%	6.82%	34.7% - 34.9%	5.00%	6.17%	6.00%
Expected rate of salary increases	3.80%	4.00%	5.04% - 6.08%	7.38% - 9.69%	5.00%	4.50%	28.3% -28.5%	0.00%	4.00%	3.00%
Mortality tables	CB-H-2014 RV-M-2014	CB-H-2014 RV-M-2014	AT 2000	AT 2000	RV 2008	RV 2008	CB-H-2014 RV-M-2014	CB-H-2014 RV-M-2014	CB-H-2014 RV-M-2014	CB-H-2014 RV-M-2014
Turnover rate	4.75%	4.53%	6.60%	5.3%	0.46%	0.4%	1.40%	1.5%	4.25%	4.14%

·Sensitivity:

As of December 31, 2018, 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$349,448 (ThUS$88,483 as of December 31, 2017) if the rate rises and an increase of ThUS$414,404 (ThUS$105,349 as of December 31, 2017) if the rate falls.

·Defined contribution:

The contributions made to the defined contribution plans are recorded in the item “employee expenses” in the consolidated statement of comprehensive income. The amounts recorded for this concept for the years ended December 31, 2018, 2017 and 2016 were ThUS$11,736, ThUS$10,007 and ThUS$82,230, respectively.

·Future disbursements:

The estimates available indicate that ThUS$146,905 (net effect) will be disbursed for defined benefits in 2019.

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·Length of commitments:

The Group’s obligations have a weighted average length of 9.41 years, and the outflows of benefits for the next 10 years and more is expected to be as follows:

Years	ThUS$
1	366,163
2	354,268
3	345,477
4	338,766
5	333,060
Over 5 to 10	1,537,047

·Multi-employer plans Enel Distribución Sao Paulo:

FUNCESP is the entity in charge of the benefit plans sponsored by Enel Distribucion 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 evenly divided between the Company and the employees according to the rates mentioned above. The rates representing the costs vary between 1.45% and 4.22%, according to the range of wages and they are annually reassessed 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 actual wage contributed), with a contribution of the Company of up to the limit of 5% over the 30% basis of the contribution remuneration.

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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27.EQUITY

27.1Equity attributable to the shareholders of Enel Américas

27.1.1Subscribed and paid capital and number of shares

The issued capital of the Company for the year ended December 31, 2018 and 2017 is US$6,763,204,424 divided into 57,452,641,516 authorized, subscribed and paid-in 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). During the year 2017 and 2016, the Group did not engage in any transaction of any kind with potential dilutive effects leading to diluted earnings per share that could differ from basic earnings per share.

Treasury shares

The treasury shares at January 1, 2017 are US$139,630,480 divided into 872,333,871 shares, and were acquired as part of the merger process as follows:

·129,829,692 shares for a total amount of US$21,517,199 acquired from the minority shareholders of the Company, Endesa Américas and Chilectra Américas, who disagreed with respect to the merger and exercised their withdrawal rights.

·742,504,179 shares for a total amount of US$118,113,281 corresponding to the shares of Endesa Américas acquired in the tender offer.

At the April 27, 2017, Extraordinary Shareholders’ meeting of Enel Américas, approved the cancellation of treasury shares acquired as a result of the merger process and the consequent reduction of the share capital by the same amount.

Changes to the issued capital as a result of the Corporate Reorganization

The Spin-Off Process:

At the Extraordinary Shareholders’ Meeting of Enersis (currently Enel Américas S.A.) held on December 18, 2015, the shareholders approved the spin-off of Enersis into two companies (the “Spin-Off”). As a result of this Spin-Off, Enersis Chile S.A. (currently Enel Chile S.A.), a new publicly held company governed under Chapter XII of D.L. 3,500 was created, and was allocated the shareholdings and other associated assets and liabilities of Enersis in Chile, including the ownership interests in Endesa Chile and Chilectra. All of Enersis’ shareholders participated in Enersis Chile in the same proportion as they had in Enersis’ issued capital, with the number of shares equal to what they had held in Enersis (ratio 1:1). All the businesses outside of Chile were allocated to the continuing company Enersis Américas, including Enersis’ ownership interests in the new entities as a result of the spin-offs of Chilectra and Endesa Chile, and all the assets and liabilities and administrative authorizations in Chile not expressly allocated to Enersis Chile in the Spin-Off.

As part of the Spin-Off, (i) the capital of Enersis was reduced from US$10,680,663,292, divided into 49,092,772,762 registered common shares of a single series and no par value, to the new amount of US$7,649,477,307, divided into 49,092,772,762 registered common shares of a single series and no par value. Additionally, it was agreed to (ii) establish the capital of Enersis Chile at US$3,211,185,985 corresponding to the amount by which the capital of Enersis had been decreased, divided into 49,092,772,762 registered common shares, all of the same series and no par value, and (iii) distribute the former Enersis’ equity interest between Enersis and Enersis Chile, by allocating assets and liabilities as indicated by the aforementioned meeting, to Enersis Chile.

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On March 1, 2016, upon satisfying all conditions precedent, including the capital decrease and modifications to the by-laws, the separation of the Chilean and non-Chilean businesses of Enersis became effective and Enersis’ corporate name was changed to Enersis Américas S.A.

On October 4, 2016, the corporate name changes of Enersis Chile, Endesa Chile and Chilectra to Enel Chile S.A., Enel Generación Chile S.A., and Enel Distribución Chile S.A., respectively, were approved at the respective Extraordinary Shareholders’ Meetings. The corporate name changes became effective on October 18, 2016, through modifications to the by-laws of each of these entities.

The Merger Process:

On September 28, 2016, the respective shareholders of Enersis Américas, Endesa Américas and Chilectra Américas met, voted and approved by more than two-thirds of the outstanding voting shares of each company, the merger of Endesa Américas and Chilectra Américas with and into Enersis Américas, with Enersis Américas continuing as the surviving company under the new name “Enel Américas S.A.” (the “Merger”). Pursuant to the Merger, Enel Américas S.A. (the “Surviving Company”) absorbed Endesa Américas and Chilectra Américas by incorporation, each of which were then dissolved without liquidation, and Enel Américas S.A. substituted for them in all their rights and obligations.

On September 14, 2016, the Company commenced a public cash tender offer (oferta pública de adquisición de valores, in Spanish) for all the outstanding shares and ADSs of Endesa Américas under Chilean law and applicable U.S. securities laws (the “Tender Offer”). The Tender Offer was for all shares (other than those held by the Company), including in the form of ADSs represented by ADRs of Endesa Américas, for a price of Ch$ 300 per share (or the equivalent in U.S. dollars of Ch$ 9,000 per ADS in the case of ADSs).

The Tender Offer was contingent on (i) the approval of the Merger by the relevant shareholders at the Extraordinary Shareholders’ Meetings pursuant to the Chilean Corporations Act on September 28, 2016, (ii) less than 10% of the outstanding shares of the Company, 10% of the outstanding shares of Endesa Américas and 0.91% of the outstanding shares of Chilectra Américas exercising the statutory merger dissenters’ withdrawal rights in connection with the Merger, provided that no shareholder owned more than 65% of the Company after all exercises of statutory merger dissenters’ withdrawal rights, and (iii) the absence of any material adverse effect on Endesa Américas and its subsidiaries. Since the conditions were met, the Tender Offer was successfully completed on October 28, 2016. The Tender Offer resulted in the acquisition of 265,180,064 shares of Endesa Américas for a total amount of ThUS$118,113.

In summary, the Company increased its ownership interest in Endesa Américas by 3.23%, reaching a controlling interest of 63.21% of the shares.

On November 15, 2016, as agreed to at the Extraordinary Shareholders’ Meeting of the Company on September 28, 2016, the Company signed, together with its subsidiaries Endesa Américas and Chilectra Américas, the Deed of Compliance with Merger Conditions (Escritura Declarativa de Cumplimiento de Condiciones de Fusión, in Spanish), which affirmed the satisfaction of the conditions precedent to which the Merger of the Company with the aforementioned companies was subject to, and allowed the Merger to become effective as of the first calendar day of the following month.

On December 1, 2016, the Merger took effect and the Company absorbed Endesa Américas and Chilectra Américas by incorporation. On the same date, the Company changed its corporate name to “Enel Américas S.A.”.

As a consequence of the approval and completion of the Merger, shareholders of the Company, Endesa Américas and Chilectra Américas had the following options:

·shareholders of Endesa Américas that participated in the Merger received 2.8 shares of the Company’s common stock for each Endesa Américas share they owned and 1.68 ADSs of the Company for each Endesa

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Américas ADS they owned, since Endesa Américas ceased to exist as a separate entity upon consummation of the Merger;

·shareholders of Chilectra Américas that participated in the Merger received 4.0 shares of the Company’s common stock for each Chilectra Américas share they owned, since Chilectra Américas ceased to exist as a separate entity upon consummation of the Merger;

·shareholders of the Company, Endesa Américas and Chilectra Américas that dissented with respect to the Merger and exercised their statutory merger dissenters’ withdrawal rights provided under Chilean law received a cash payment equivalent to the weighted average of the closing prices of the Company or Endesa Américas shares, as the case may be, as reported on the Chilean Stock Exchanges during the 60-trading day period preceding the 30th trading day prior to the date the Merger was approved or the book value of the Chilectra Américas shares, as applicable; and

·shareholders of Endesa Américas tendered their Endesa Américas shares and ADSs in the Tender Offer.

The following table sets forth the movements in the number of shares of the Company as a result of the merger:

Number of outstanding shares of the Company prior the Merger 49,092,772,762

	Number of shares		Share exchange ratio	Number of shares
New shares issued (1):
Exchange of shares with minority shareholders of Endesa Américas	3,282,265,786		28.0	9,190,344,201
Exchange of shares with minority shareholders of Chilectra Américas	10,464,606		4	41,858,424
Total new shares issued	3,292,730,392			9,232,202,625
Repurchase of shares (2):
Withdrawal right exercised by the minority shareholders of the Company	(119,185,929	)		(119,185,929	)
Withdrawal right exercised by the minority shareholders of Endesa Américas	(3,706,909	)	2.8	(10,379,345	)
Withdrawal right exercised by the minority shareholders of Chilectra Américas	(65,035	)	4	(260,140	)
Remaining shares for exchange of shares				(4,278	)
Total repurchase of shares	(122,957,873	)		(129,829,692	)
Tender Offer of Endesa Américas (3):
Purchased shares	(265,180,064	)	2.8	(742,504,179	)
Total Tender Offer of Endesa Américas	(265,180,064	)		(742,504,179	)
Number of outstanding shares of the Company after the Merger				57,452,641,516
Total number of shares - Issued Capital				58,324,975,387
Total number of shares - Treasury Shares				(872,333,871	)
Number of outstanding shares of the Company after the Merger				57,452,641,516

(1)On December 29, 2016, a total of 9,232,202,625 new shares of the Company as a result of the Merger were registered with the Chilean Stock Register. The total amount for the issuance of new shares was ThUS$1,553,687.

(2)The total amount paid for the shares repurchased was ThUS$21,517.

(3)The total amount paid for the shares of Endesa Américas purchased in the Tender Offer was ThUS$118,113.

Enel Américas will continue trading its shares publicly on the Stock Exchanges in Chile and its ADSs on the New York Stock Exchange (“NYSE”). As a result of the mergers of Endesa Américas and Chilectra Américas, all shares and ADS of both companies were converted into shares and ADS of Enersis Américas. As a result, Endesa Américas and Chilectra Américas stopped trading on the Stock Exchanges in Chile and on the New York Stock Exchange.

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Subsequent to merger, Enel S.p.A. continues to be the last controlling parent, through its majority stake in the shares of Enel Américas and the previous minority shareholders of Endesa Américas and Chilectra Américas, together with the current minority shareholders of Enel Américas, will own their corresponding non-controlling interests in Enel Américas.

27.1.2Dividends

On November 25, 2014, the Board unanimously agreed to distribute interim dividend No. 90 of US$0.00133 per share on January 30, 2015 against fiscal year 2014 statutory net income. This corresponded to 15% of net income calculated as of September 30, 2014, in accordance with the dividend policy.

The Ordinary Shareholders’ Meeting held on April 28, 2015 approved the distribution of a minimum mandatory dividend (which included interim dividend No. 90 of US$0.00133 per share) and an additional dividend, which in the aggregate amounted to US$490,317,886 or US$0.00998751 per share.

Since interim dividend No. 90 had already been paid, the remainder was distributed and paid in final dividend No. 91, which totaled US$424,712,960 equivalent to US$0.00886 per share.

On November 24, 2015, the Board unanimously agreed to distribute interim dividend No. 92 of US$0.00174 per share on January 29, 2016 against fiscal year 2015 statutory net income. This corresponded to 15% of net income calculated as of September 30, 2015, in accordance with the dividend policy.

The Ordinary Shareholders’ Meeting held on April 28, 2016 approved the distribution of a minimum mandatory dividend (deducting the interim dividend No. 92 paid in January 2016) and an additional dividend, which in the aggregate amounted to US$295,657,660 or US$0.006019495 per share.

Since interim dividend No. 92 had already been paid, the remainder was distributed and paid in final dividend No. 93, which totaled US$241,946,275, equivalent to US$0.00491 per share.

On November 24, 2016, the Board unanimously agreed to distribute interim dividend No. 94 of US$0.00142 per share for a total amount of US$81,873,986 on January 27, 2017 against fiscal year 2016 statutory net income. This corresponded to 15% of net income calculated as of September 30, 2016, in accordance with the dividend policy.

At the April 27, 2017 Ordinary Shareholders´ Meeting of Enel Américas S.A., it was resolved that the minimum dividend (from which the interim dividend paid in January 2017 would be deducted) would be distributed plus an additional dividend, the equivalent of US$0.00501 per share for a total distributed (including the interim dividend) of US$288,326,860. Since interim dividend No. 94 had already been paid, the remainder would be distributed and paid in final dividend No. 95 which totaled US$206,452,874, equivalent to US$0.00359 per share.

On November 29, 2017, the Board of Directors agreed unanimously (those members present), that interim dividend No. 96 of US$0.00100 per share would be charged against 2017 statutory net income to be paid on January 26, 2018. Such amount represents 15% of the net income of Enel Américas calculated as of September 30, 2017 in accordance with the current dividend policy.

The Ordinary Shareholders’ Meeting of Enel Américas S.A. held on April 26, 2018, agreed to distribute a mandatory minimum dividend (from which the interim dividend paid in January 2018 would be deducted) and an additional dividend, amounting to a total of US$ 354,521,675, which is equivalent to US$ 0.00617 per share. Since interim dividend No. 96 had already been paid, the remainder was distributed and paid in final dividend No. 97 which totaled US$ 296,939,208, equivalent to US$ 0.00517 per share.

On November 26, 2018, the Board of Enel Américas SA, unanimously agreed by the unanimity of its members present, the payment of a provisional dividend of US$ 0.00134 per share, charged to the profit or loss for the year 2018, to be

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paid on January 25, 2019. This amount corresponds to 15% of Enel Américas’ net income calculated as of September 30, 2018, in accordance with the dividend policy.

The following table sets forth the dividends paid in the last three years:

Dividend No.	Type of Dividend	Payment Date	Dolar per Share	Charged to
90	Interim	01-30-2015	0.001330	2014
91	Final	05-25-2015	0.008860	2014
92	Interim	01-29-2016	0.001740	2015
93	Final	05-24-2016	0.004910	2015
94	Interim	01-27-2017	0.001420	2016
95	Final	05-26-2017	0.003590	2016
96	Interim	01-26-2018	0.001000	2017
97	Final	05-25-2018	0.005170	2017
98	Interim	01-25-2019	0.001340	2017

27.2Foreign 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, 2018, 2017 and 2016:

	Balance as of December 31,
Reserves for Accumulated Currency Translation Differences	2018 ThUS$		2017 ThUS$		2016 ThUS$
Empresa Distribuidora Sur S.A.	(378,929	)	(128,320	)	(151,019	)
Compañía Distribuidora y Comercializadora de Energía S.A.	115,658		149,973		211,975
Enel Distribución Perú S.A.	38,887		63,180		59,666
Dock Sud	(63,680	)	(21,517	)	(19,800	)
Enel Brasil S.A.	(1,133,980	)	(529,654	)	(646,185	)
Enel Generación Costanera S.A.	(42,260	)	(9,381	)	(9,543	)
Emgesa S.A. E.S.P.	(33,476	)	17,908		22,187
Enel Generación El Chocón S.A.	(239,155	)	(126,421	)	(110,183	)
Enel Peru S.A	191,047		—		—
Enel Generacion Perú S.A	(110,613	)	125,588		115,350
Enel Generación Piura S.A.	4,926		12,984		11,769
Other	(14,534	)	(8,335	)	(4,688	)
Foreign currency translation (1)			—		(2,089,877	)
TOTAL	(1,666,109	)	(453,995	)	(2,610,348	)

27.3Capital 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.

27.4Restrictions on subsidiaries transferring funds to the parent

Certain of the Group’s subsidiaries must comply with financial ratio covenants which require them to have a minimum level of equity or other requirements that restrict the transferring of assets to the Group. The Group’s restricted net assets as of December 31, 2018 from its subsidiaries Enel Distribución Rio, Enel Distribución Ceará, Enel Distribución Perú, Enel Generación Piura and Enel Generación Perú were ThUS$1,278,858, ThUS$111,992, ThUS$313,578, ThUS$79,242,  and ThUS$1,392, respectively.

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27.5Other reserves

Other reserves for the years ended December 31, 2018, 2017 and 2016, are as follows:

	Balance as of January 1, 2018		2018 changes		Balance as of December 31, 2018
	ThUS$		ThUS$		ThUS$
Exchange differences on translation (a)	(453,995	)	(1,212,114	)	(1,666,109	)
Cash flow hedges (b)	(3,472	)	(1,622	)	(5,094	)
Fair value through other comprehensive income	(175	)	(222	)	(397	)
Other miscellaneous reserves (c)	(3,408,922	)	199,639		(3,209,283	)
TOTAL	(3,866,564	)	(1,014,319	)	(4,880,883	)

	Balance as of January 1, 2017		2017 changes		Balance as of December 31, 2017
	ThUS$		ThUS$		ThUS$
Exchange differences on translation (a)	(388,942	)	(65,053	)	(453,995	)
Cash flow hedges (b)	(11,423	)	7,951		(3,472	)
Fair value through other comprehensive income	227		(402	)	(175	)
Other miscellaneous reserves (c)	(3,364,559	)	(44,363	)	(3,408,922	)
TOTAL	(3,764,697	)	(101,867	)	(3,866,564	)

	Balance as of January 1, 2016		2016 changes	Balance as of December 31, 2016
	ThUS$		ThUS$	ThUS$
Exchange differences on translation (a)	(3,165,288	)	554,940	(2,610,348	)
Cash flow hedges (b)	(7,649	)	3,223	(4,426	)
Available-for-sale financial assets	(256	)	473	217
Other comprehensive income from non-current assets held for distribution to owners	(171,638	)	171,638	—
Other miscellaneous reserves (c)	(4,659,748	)	566,486	(4,093,262	)
TOTAL	(8,004,579	)	1,296,760	(6,707,819	)

a)Reserves for exchange differences on translation: These reserves arise primarily from exchange differences relating to: (i) Translation of the financial statements of our subsidiaries with functional currencies other than the US$ dollar (see Note 2.7.3); and (ii) Translation of goodwill arising from the acquisition of companies with functional currencies other than the US$ dollar (see Note 4.c).

b)Cash flow hedge reserves: These reserves represent the cumulative effective portion of gains and losses on cash flow hedges (see Note 4.g.5).

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c)Other miscellaneous reserves.

The main items and their effects are the following:

Other Miscellaneous Reserves	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
Reserve for capital increase in 2013 (1)	(1,345,368	)	(1,345,368	)	(1,908,106	)
Reserve for corporate reorganization (“Spin-off”) (2)	716,712		716,712		691,210
Reserve for subsidiaries transactions (3)	(439,290	)	(439,290	)	(508,682	)
Reserve for transition to IFRS (4)	(1,490,605	)	(1,490,604	)	(1,567,941	)
Reserve for merger of Enel Américas, Endesa Américas and Chilectra Américas (5)	(730,748	)	(730,748	)	(725,018	)
Reserve for Tender Offer of Endesa Américas and withdrawal rights (6)	(57,101	)	(57,100	)	(56,653	)
Other miscellaneous reserves (7)	137,117		(62,524	)	(18,072	)
Total	(3,209,283	)	(3,408,922	)	(4,093,262	)

(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 the Company and the separation of the Chilean business into a new entity, Enel Chile S.A. (see Note 6.1).

(3)Reserve from transactions with our subsidiaries. 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. 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 equity 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. Represents the recognition of the difference between the carrying amount and the price paid for the non-controlling interests acquired in the Tender Offer, which resulted in a charge to other reserves for ThUS$56,578. Also, includes ThUS$523 related to recognition of the difference between the carrying amount and the price paid for the shares of those shareholders who exercised their withdrawal rights.

(7)Other miscellaneous reserves from transactions made in prior years.

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27.6Non-controlling Interests

The detail of non-controlling interests as of and for the years ended December 31, 2018, 2017 and 2016, is as follows:

	Non-controlling interests
			Equity		Profit (Loss)
Companies	12-31-2018 %		12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$		12-31-2016 ThUS$
Enel Distribución Río S.A. (formerly Ampla Energía S.A.)	0.27	%	2,471	3,746	128	(111	)	(228	)
Enel Distribución Ceará S.A. (formerly Coelce S.A.)	26.00	%	204,985	218,722	26,409	35,633		29,509
Enel Distribucion Sao Paulo	4.12	%	68,083	—	907	—		—
Compañía Distribuidora y Comercializadora de Energía S.A.	51.59	%	439,727	457,800	106,363	108,928		86,463
Emgesa S.A. E.S.P.	51.52	%	675,574	667,440	178,045	154,744		127,261
Enel Distribución Peru S.A.A	16.85	%	104,792	98,590	17,601	23,249		22,250
Enel Generación Peru S.A.A	16.40	%	128,863	156,731	25,177	22,647		12,776
Chinango S.A.C.	33.12	%	36,158	22,163	6,836	3,810		5,143
Empresa Distribuidora Sur S.A.	27.91	%	177,338	2,356	25,609	3,135		(8,604	)
Enel Generacion Costanera S.A.	24.38	%	34,353	10,187	22,248	4,792		4,061
Enel Generacion El Chocón S.A.	34.31	%	102,131	72,893	31,031	30,138		15,276
Inversora Dock Sud S.A.	42.86	%	60,390	38,147	12,027	13,984		5,947
Central Dock Sud S.A.	29.76	%	59,687	37,432	11,921	13,826		5,842
Enel Distribución Chile S.A.	0.00	%	—	—		—		405
Chilectra Américas S.A.	0.00	%	—	—		—		123
Enel Generación Chile S.A.	0.00	%	—	—		—		71,544
Endesa Américas S.A. (2)	0.00	%	—	—		—		66,618
Empresa Eléctrica Pehuenche S.A.	0.00	%	—	—		—		1,777
Enel Generacion Piura S.A.	3.50	%	4,924	4,529	613	613		795
Enel Distribucion Goias	0.12	%	1,033	743	313	12		—
Other			7,383	6,557	449	2,071		1,416
TOTAL			2,107,892	1,798,036	465,677	417,471		448,374

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28.REVENUE AND OTHER OPERATING INCOME

The detail of revenue presented in the statement of comprehensive income for the years ended December 31, 2018, 2017 and 2016, is as follows:

	For the years ended December 31,
Revenues	2018 ThUS$	2017 ThUS$	2016 ThUS$
Energy sales (1)	10,929,523	8,559,077	6,350,968
Generation	2,123,166	1,895,791	1,686,495
Regulated customers	650,264	509,051	472,319
Unregulated customers	989,311	1,017,225	706,786
Spot market sales	464,030	348,105	472,921
Other customers	19,561	21,410	34,469
Distribution	8,806,357	6,663,286	4,664,473
Residential	4,485,696	2,945,036	2,091,103
Business	2,238,278	1,669,289	1,313,902
Industrial	914,056	706,385	546,028
Other customers	1,168,327	1,342,576	713,440
Other sales	48,968	44,194	52,312
Gas sales	36,304	33,541	32,310
Sales of goods and services	12,664	10,653	20,002
Revenue from other services	1,140,643	885,995	604,628
Tolls and transmission	861,717	625,993	433,236
Metering equipment leases	130	128	110
Public lighting	4,097	4,427	7,521
Verifications and connections	10,985	18,270	11,108
Engineering and consulting services	683	170	4,817
Rental of public lighting infrastructure	132,736	110,804	55,487
Other services	130,295	126,203	92,349
Total revenues	12,119,134	9,489,266	7,007,908

	For the years ended December 31,
Other Operating Income	2018 ThUS$	2017 ThUS$	2016 ThUS$
Revenue from construction contracts	833,313	753,389	399,408
Other income (2)	231,615	195,348	235,266
Total other operating income	1,064,928	948,737	634,674

(1)In Argentina, on February 1, 2017, the ENRE issued Resolution No. 64/2017, regarding the Comprehensive Tariff Review (RTI), which updates the rate retroactively as of January 2017. The effects recognized by this resolution in the year ended December 31, 2018 were ThUS$1,174,150 (ThUS$ 327,408 for the year ended December 31, 2017).

(2)The other income includes ThUS$0, ThUS$67 and ThUS$87,603 for the years ended December 31, 2018, 2017 and 2016, respectively, related to the availability contracts that our subsidiary Enel Generación Costanera entered into with CAMMESA in December 2012.

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29.RAW MATERIALS AND CONSUMABLES USED

The detail of raw materials and consumables used presented in profit or loss for the years ended December 31, 2018, 2017 and 2016, is as follows:

	For the years ended December 31,
	2018		2017		2016
Raw Materials and Consumables Used	ThUS$		ThUS$		ThUS$
Energy purchases	(5,737,604	)	(3,940,466	)	(2,442,519	)
Fuel consumption	(226,843	)	(229,308	)	(362,156	)
Transportation costs	(1,055,431	)	(634,118	)	(394,097	)
Costs from construction contracts	(833,313	)	(753,389	)	(399,408	)
Other raw materials and consumables	(289,582	)	(325,507	)	(270,038	)
Total	(8,142,773	)	(5,882,788	)	(3,868,218	)

30.EMPLOYEE BENEFITS EXPENSE

The detail of employee expenses for the years ended December 31, 2018, 2017 and 2016, are as follows:

	For the years ended December 31,
	2018		2017		2016
Employee Benefits Expenses	ThUS$		ThUS$		ThUS$
Wages and salaries	(476,809	)	(489,118	)	(400,513	)
Post-employment benefit obligations expense	(17,269	)	(20,003	)	(13,095	)
Social security and other contributions	(266,566	)	(257,185	)	(198,822	)
Other employee expenses	(79,849	)	(71,678	)	(13,672	)
Total	(840,493	)	(837,984	)	(626,102	)

31.DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES

The detail of depreciation, amortization and impairment losses for the years ended December 31, 2018, 2017 and 2016, are as follows:

	For the years ended December 31,
	2018 ThUS$		2017 ThUS$		2016 ThUS$
Depreciation	(511,326	)	(407,535	)	(348,385	)
Amortization	(351,114	)	(240,579	)	(124,853	)
Subtotal	(862,440	)	(648,114	)	(473,238	)
Impairment (losses) reversals (*)	(60,748	)	(79,748	)	(157,078	)
Total	(923,188	)	(727,862	)	(630,316	)

	Generation						Distribution						Other				For the year ended December 31,
(*) Information on Impairment Losses by Reportable Segment	2018 ThUS$		2017 ThUS$		2016 ThUS$		2018 ThUS$		2017 ThUS$		2016 ThUS$		2018 ThUS$	2017 ThUS$	2016 ThUS$		2018 ThUS$		2017 ThUS$		2016 ThUS$
Financial assets (See Note 12)	(4,462	)	(1,296	)	(14,783	)	(110,209	)	(122,824	)	(116,328	)		—	(141	)	(114,671	)	(124,120	)	(131,252	)
Other financial assets	(536	)	304		(19,388	)	(7,295	)	(509	)	—			—	(6,438	)	(7,831	)	(205	)	(25,826	)
Intangible assets other than goodwill (See Note 6)	—		—		—		(5,234	)			—			—	—		(5,234	)	—		—
Property, plants and equipment (See Note 19)	66,988		(10,242	)	—				54,819		—			—	—		66,988		44,577		—
Total	61,990		(11,234	)	(34,171	)	(122,738	)	(68,514	)	(116,328	)	—	—	(6,579	)	(60,748	)	(79,748	)	(157,078	)

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32.  OTHER EXPENSES

Other miscellaneous operating expenses for the years ended December 31, 2018, 2017 and 2016, are as follows:

	For the years ended December 31,
	2018		2017		2016
Other expenses	ThUS$		ThUS$		ThUS$
Other supplies and services	(296,788	)	(282,702	)	(217,835	)
Professional, outsourced and other services	(206,619	)	(145,791	)	(133,595	)
Repairs and maintenance	(203,382	)	(247,137	)	(164,437	)
Indemnities and fines	(11,981	)	(4,316	)	(4,181	)
Taxes and charges	(20,548	)	(26,413	)	(36,822	)
Insurance premiums	(37,793	)	(38,522	)	(42,072	)
Leases and rental costs	(27,885	)	(26,448	)	(17,271	)
Marketing, public relations and advertising	(12,737	)	(5,137	)	(5,216	)
Other supplies	(179,327	)	(131,623	)	(174,723	)
Travel expenses	(21,714	)	(25,032	)	(18,990	)
Environmental expenses (1)	(2,311	)	(10,035	)	(2,233	)
Total	(1,021,085	)	(943,156	)	(817,375	)

(1)It includes research costs recognized as expenses for the years ended December 31, 2018, 2017 and 2016, of ThUS$856, ThUS$137 and ThUS$288, respectively.

33.  OTHER GAINS (LOSSES)

Other gains (losses) for the years ended December 31, 2018, 2017 and 2016, are as follows:

	For the years ended December 31,
	2018	2017	2016
Other Gains (Losses)	ThUS$	ThUS$	ThUS$
Disposals of property, plants and equipment	630	5,160	25,844
Other	51	185	(13,703	)
Total	681	5,345	12,141

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34.  FINANCIAL RESULTS

Financial income and costs for the years ended December 31, 2018, 2017 and 2016, are as follows:

	For the years ended December 31,
	2018	2017	2016
Financial Income	ThUS$	ThUS$	ThUS$
Cash and cash equivalents	133,180	123,139	150,320
Financial income on plan assets (Brazil) (2)	42	78	164
Financial income from concessions IFRIC 12 (Brazil) (1)	73,911	36,648	55,167
Interest collected to customers on energy bills and invoices	58,604	30,389	25,491
Other financial income (2)	92,344	103,589	45,315
Total financial income	358,081	293,843	276,457

	For the years ended December 31,
	2018		2017		2016
Financial costs	ThUS$		ThUS$		ThUS$
Financial costs	(1,071,759	)	(869,535	)	(773,157	)
Bank loans	(162,192	)	(97,495	)	(84,753	)
Unsecured obligations (bonds)	(312,204	)	(215,836	)	(284,842	)
Financial leasing	(8,170	)	(5,882	)	(2,291	)
Valuation of financial derivatives	(14,094	)	(724	)	(16,526	)
Financial provisions (3)	(147,194	)	(175,831	)	(162,558	)
Post-employment benefit obligations (2)	(83,463	)	(37,907	)	(29,735	)
Capitalized borrowing costs	19,329		8,054		30,939
Formalization of debt and other associated expenses	(17,883	)	(8,694	)	(844	)
Other financial costs (4)	(345,888	)	(335,220	)	(222,547	)
Gains (losses) from indexed assets and liabilities (**)	270,380		—		(1,032	)
Foreign currency exchange differences (*)	110,635		(6,714	)	58,934
Total financial costs	(690,744	)	(876,249	)	(715,255	)
Total financial results	(332,663	)	(582,406	)	(438,798	)

(**) See Note 8.

(1)Corresponds to or the financial income updated (recognized for accounting purposes) years ending December 31, 2018, 2017 and 2016 of the unamortized, assets at the new replacement value at the end of the concession in the distributing companies Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Goias S.A. and Enel Distribución Sao Paulo S.A..

(2)See Note 26.2

(3)For the year ended December 31, 2018, including ThUS$61,454 (ThUS$115,826 and ThUS$69,670 for the years ended December 31, 2017 and 2016, respectively) of our subsidiary Edesur, corresponding to the financial cost generated by the update of the penalty for the quality of service due to the application of ENRE Resolution no. 1/2016 (See Note 24). Additionally our Brazilian subsidiaries Enel Distribución Río S.A., Enel Distribución Ceará S.A., Enel Distribución Sao Paulo, Enel Cien S.A. and Enel Distribución Goias, have recognized ThUS$61,187, ThUS$44,440 and ThUS$50,801 during the years ended December 31, 2018, 2017 and 2016, respectively, for accounting update of legal claims.

(4)For the year ended December 31, 2018: interest for debt with Enel Finance International NV is included for ThUS$43,874 (ThUS$0 in 2017), related to the refinancing  for the  purchase of Enel Distribución Sao Paulo (see

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Note 13. d); interest from the debt with CAMMESA for ThUS$111,680 (ThUS$120,898 and ThUS$144,153 for the years ended December 31, 2017 and 2016, respectively); banking expenses  for ThUS$56,188 (ThUS$106,079 and ThUS$46,304 for the years ended December 31, 2017 and 2016, respectively), financial costs for the sale of portfolio for ThUS$23,471 (ThUS$35,246 and ThUS$4,371 for the years ended December 31, 2017 and 2016, respectively); and others for ThUS$110,675 (ThUS$53,186 and ThUS$8,252 for the years ended December 31, 2017 and 2016, respectively).

	For the years ended December 31,
	2018	2017	2016
Gains (losses) from Indexed Assets and Liabilities (*)	ThUS$	ThUS$	ThUS$
Current tax assets and liabilities	—	—	54
Other financial liabilities (financial debt and derivative instruments)	—	—	(1,028	)
Other provisions	—	—	(58	)
Results from Indexed	—	—	(1,032	)
Hyperinflation Result (1)	270,380	—	—
Total	270,380	—	(1,032	)

	For the years ended December 31,
	2018		2017		2016
Foreign Currency Exchange Differences (*)	ThUS$		ThUS$		ThUS$
Cash and cash equivalents	28,248		7,171		15,143
Other financial assets	293,812		117,018		100,338
Other non-financial assets	5,356		4,260		(2,090	)
Trade and other receivables	42,999		10,015		10,806
Current tax assets and liabilities	2,473		266		738
Other financial liabilities (financial debt and derivative instruments)	(144,669	)	(103,890	)	(55,203	)
Trade and other payables	(76,575	)	(30,326	)	1,692
Other non-financial liabilities	(41,009	)	(11,228	)	(12,490	)
Total	110,635		(6,714	)	58,934

(*) The effects on financial results from exchange differences are originated from the following:

1)See Note 8.

35.  INFORMATION BY SEGMENT

35.1  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.

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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 four 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

The Generation and Transmission Business is conducted: in Argentina through Enel Trading Argentina (formerly Cemsa), Central Dock Sud, Enel Generación Costanera, and Enel Generación El Chocón; in Brazil through EGP Cachoeira Dourada, Enel CIEN, Enel Brasil, and Fortaleza; in Colombia through Emgesa; and in Peru through Enel Generación Perú and Enel Generación Piura.

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 four 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.

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: EBITDA, Gross Margin, Total Capex, Total Opex, Net income, 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;

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(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 finalized in the last quarter of 2016, consolidated financial statements. Based on this context and taking into consideration the corporate reorganization as discussed in Note 6.1, the assets and liabilities related to the Chilean operations are presented as held for distribution to owners, and in the case of income statement accounts, as discontinued operations.

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The following tables present details of this information by reportable segment:

35.2    Generation and transmission, distribution and others

	Generation and Transmission		Distribution		Holdings, Eliminations and Others				Total
	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018		12-31-2017		12-31-2018	12-31-2017
Line of business	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$		ThUS$	ThUS$
ASSETS
CURRENT ASSETS	1,637,118	1,428,414	4,219,859	2,927,495	527,009		189,512		6,383,986	4,545,421
Cash and cash equivalents	741,159	598,586	599,445	576,614	563,681		297,563		1,904,285	1,472,763
Other current financial assets	133,524	74,249	42,367	26,175	34,502		9,928		210,393	110,352
Other current non-financial assets	45,867	48,898	221,676	222,545	40,189		12,189		307,732	283,632
Trade and other current receivables	505,920	482,522	3,037,418	1,888,620	7,684		6,647		3,551,022	2,377,789
Current accounts receivable from related parties	141,223	167,243	16,585	9,542	(143,471	)	(169,382	)	14,337	7,403
Inventories	55,723	51,928	283,369	193,708	306		453		339,398	246,089
Current tax assets	13,702	4,988	13,174	10,291	24,118		32,114		50,994	47,393
Non-current assets or disposal groups held for sale or held for distribution to owners	—	—	5,825	—	—		—		5,825	—
NON-CURRENT ASSETS	5,782,238	5,657,524	15,020,507	9,505,117	209,625		460,929		21,012,370	15,623,570
Other non-current financial assets	366,602	421,888	2,429,718	1,325,481	155		4,898		2,796,475	1,752,267
Other non-current non-financial assets	21,552	32,300	1,114,885	525,081	4,271		3,045		1,140,708	560,426
Trade and other non-current receivables	408,367	395,692	498,083	220,946	58		155		906,508	616,793
Non-current accounts receivable from related parties	3,664	2,641	108	255	(2,120	)	(51	)	1,652	2,845
Investments accounted for using the equity method	379,400	143,732	372	24	(377,176	)	(141,009	)	2,596	2,747
Intangible assets other than goodwill	52,076	47,866	5,761,420	3,624,793	13,793		9,820		5,827,289	3,682,479
Goodwill	10,729	7,443	662,218	129,200	532,623		576,532		1,205,570	713,175
Property, plants and equipment	4,513,951	4,574,513	4,167,112	3,511,532	5,764		6,422		8,686,827	8,092,467
Investment properties	—	—	11,708	—	—		—		11,708	—
Deferred tax assets	25,897	31,449	374,883	167,805	32,257		1,117		433,037	200,371
TOTAL ASSETS	7,419,356	7,085,938	19,240,366	12,432,612	736,634		650,441		27,396,356	20,168,991

	Generation and Transmission		Distribution				Holdings, Eliminations and Others				Total
Line of business	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$
LIABILITIES AND EQUITY
CURRENT LIABILITIES	1,682,438	1,213,127	5,064,636		3,809,016		2,903,682		(87,807	)	9,650,756		4,934,336
Other current financial liabilities	557,288	208,407	701,883		469,228		388,928		12,133		1,648,099		689,768
Trade and other current payables	748,149	665,982	3,175,386		2,536,006		192,712		121,865		4,116,247		3,323,853
Current accounts payable to related parties	112,196	76,532	586,817		380,820		2,297,655		(232,325	)	2,996,668		225,027
Other current provisions	74,524	89,943	347,174		178,785		1,165		1,238		422,863		269,966
Current tax liabilities	150,391	129,088	42,357		43,312		176		238		192,924		172,638
Current provisions for employee benefits	—	—	—		—		—		—		—		—
Other current non-financial liabilities	39,890	43,175	207,184		200,865		23,046		9,044		270,120		253,084
Liabilities associated with groups of assets or disposal groups held for sale or distribution to owners	—	—	3,835		—		—		—		3,835		—
NON-CURRENT LIABILITIES	1,671,572	2,331,607	6,625,127		4,074,776		617,001		549,765		8,913,700		6,956,148
Other non-current financial liabilities	1,117,237	1,737,988	2,903,618		1,995,344		601,013		616,183		4,621,868		4,349,515
Trade and other non-current payables	44,893	84,846	877,703		882,795		10,460		10,928		933,056		978,569
Non-current accounts payable to related parties	5,253	43,963	—		54,016		(5,253	)	(97,979	)	—		—
Other long-term provisions	61,377	62,474	1,302,189		597,548		410		283		1,363,976		660,305
Deferred tax liabilities	317,075	258,472	221,237		179,957		7,758		16,882		546,070		455,311
Non-current provisions for employee benefits	32,073	36,427	1,308,821		349,671		2,613		2,833		1,343,507		388,931
Other non-current non-financial liabilities	93,664	107,437	11,559		15,445		—		635		105,223		123,517
EQUITY	4,065,346	3,541,204	7,550,603		4,548,820		(2,784,049	)	188,483		8,831,900		8,278,507
Equity attributable to shareholders of Enel Américas	4,065,346	3,541,204	7,550,603		4,548,820		(2,784,049	)	188,483		8,831,900		8,278,507
Issued capital	1,501,469	705,205	3,599,197		2,395,815		1,662,538		3,662,184		6,763,204		6,763,204
Retained earnings	1,384,478	1,190,570	(507,273	)	(1,003,058	)	3,964,482		3,396,319		4,841,687		3,583,831
Share premium	39,202	38,013	58,677		63,832		(97,879	)	(101,845	)	—		—
Treasury shares	—	—	(12,704	)	—		12,704		—		—		—
Other equity interests	—	—	—		—		—		—		—		—
Other reserves	1,140,197	1,607,416	4,412,706		3,092,231		(8,325,894	)	(6,768,175	)	(2,772,991	)	(4,880,883	)
Non-controlling interests	—	—	—		—		—		—		—		2,107,892
Total Liabilities and Equity	7,419,356	7,085,938	19,240,366		12,432,612		736,634		650,441		27,396,356		20,168,991

The Holding, Eliminations and Others 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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	Generation						Distribution						Holdings, Eliminations and Others						Total
Line of business STATEMENTS OF PROIT (LOSS)	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
REVENUE AND OTHER OPERATING INCOME	3,230,791		3,019,687		2,710,117		10,739,115		8,253,117		5,660,982		(785,844	)	(834,801	)	(728,517	)	13,184,062		10,438,003		7,642,582
Revenues	3,156,268		2,926,508		2,587,360		9,748,895		7,394,378		5,148,413		(786,029	)	(831,620	)	(727,865	)	12,119,134		9,489,266		7,007,908
Energy sales	2,815,079		2,635,813		2,349,739		8,806,468		6,663,893		4,665,249		(692,024	)	(740,629	)	(664,020	)	10,929,523		8,559,077		6,350,968
Other sales	44,810		40,489		39,946		4,158		3,705		3,279		—		—		9,087		48,968		44,194		52,312
Other services rendered	296,379		250,206		197,675		938,269		726,780		479,885		(94,005	)	(90,991	)	(72,932	)	1,140,643		885,995		604,628
Other operating income	74,523		93,179		122,757		990,220		858,739		512,569		185		(3,181	)	(652	)	1,064,928		948,737		634,674
RAW MATERIALS AND CONSUMABLES USED	(1,474,928	)	(1,259,326	)	(1,137,371	)	(7,456,629	)	(5,456,305	)	(3,466,460	)	788,784		832,843		735,613		(8,142,773	)	(5,882,788	)	(3,868,218	)
Energy purchases	(841,160	)	(651,208	)	(456,008	)	(5,637,926	)	(4,081,867	)	(2,691,685	)	741,482		792,609		705,174		(5,737,604	)	(3,940,466	)	(2,442,519	)
Fuel consumption	(226,843	)	(229,308	)	(362,156	)	—		—		—		—		—		—		(226,843	)	(229,308	)	(362,156	)
Transportation expenses	(298,238	)	(256,279	)	(205,494	)	(811,849	)	(427,099	)	(228,321	)	54,656		49,260		39,718		(1,055,431	)	(634,118	)	(394,097	)
Other miscellaneous supplies and services	(108,687	)	(122,531	)	(113,713	)	(1,006,854	)	(947,339	)	(546,454	)	(7,354	)	(9,026	)	(9,279	)	(1,122,895	)	(1,078,896	)	(669,446	)
CONTRIBUTION MARGIN	1,755,863		1,760,361		1,572,746		3,282,486		2,796,812		2,194,522		2,940		(1,958	)	7,096		5,041,289		4,555,215		3,774,364
Other work performed by the entity and capitalized	9,467		8,852		16,140		168,530		164,334		83,202		—		—		107		177,997		173,186		99,449
Employee benefits expense	(122,858	)	(148,095	)	(134,919	)	(694,262	)	(663,005	)	(460,414	)	(23,373	)	(26,884	)	(30,769	)	(840,493	)	(837,984	)	(626,102	)
Other expenses	(140,031	)	(155,034	)	(160,338	)	(816,247	)	(740,660	)	(566,978	)	(64,807	)	(47,462	)	(90,059	)	(1,021,085	)	(943,156	)	(817,375	)
GROSS OPERATING RESULT	1,502,441		1,466,084		1,293,629		1,940,507		1,557,481		1,250,332		(85,240	)	(76,304	)	(113,625	)	3,357,708		2,947,261		2,430,336
Depreciation and amortization expense	(295,719	)	(238,355	)	(208,073	)	(567,471	)	(410,224	)	(265,551	)	750		465		386		(862,440	)	(648,114	)	(473,238	)
Impairment (losses) reversals recognized in profit or loss	61,989		(11,234	)	(34,171	)	(121,938	)	(68,158	)	(116,328	)	(799	)	(356	)	(6,579	)	(60,748	)	(79,748	)	(157,078	)
OPERATING INCOME	1,268,711		1,216,495		1,051,385		1,251,098		1,079,099		868,453		(85,289	)	(76,195	)	(119,818	)	2,434,520		2,219,399		1,800,020
FINANCIAL RESULT	61,405		(94,751	)	(148,574	)	(476,740	)	(507,181	)	(387,234	)	(187,708	)	19,526		98,042		(332,663	)	(582,406	)	(438,798	)
Financial income	116,829		79,906		66,787		223,121		187,234		156,186		18,131		26,703		53,484		358,081		293,843		276,457
Cash and cash equivalents	84,253		63,188		56,649		27,301		31,585		40,476		21,626		28,366		53,195		133,180		123,139		150,320
Other financial income	32,576		16,718		10,138		195,820		155,649		115,710		(3,495	)	(1,663	)	289		224,901		170,704		126,137
Financial costs	(203,183	)	(204,080	)	(249,348	)	(690,462	)	(686,078	)	(548,544	)	(178,114	)	20,623		24,735		(1,071,759	)	(869,535	)	(773,157	)
Bank borrowings	(18,221	)	(13,912	)	(24,236	)	(101,105	)	(83,583	)	(58,090	)	(42,866	)	—		(2,427	)	(162,192	)	(97,495	)	(84,753	)
Secured and unsecured obligations	(98,979	)	(108,597	)	(139,650	)	(135,140	)	(81,263	)	(99,776	)	(78,085	)	(25,976	)	(45,416	)	(312,204	)	(215,836	)	(284,842	)
Other	(85,983	)	(81,571	)	(85,462	)	(454,217	)	(521,232	)	(390,678	)	(57,163	)	46,599		72,578		(597,363	)	(556,204	)	(403,562	)
Gains (losses) from indexed assets and liabilities	8,815		—		—		260,137		—		—		1,428		—		(1,032	)	270,380		—		(1,032	)
Foreign currency exchange differences	147,759		29,423		33,987		(9,399	)	(8,337	)	5,124		(27,725	)	(27,800	)	19,823		110,635		(6,714	)	58,934
Positive	385,805		94,049		128,292		171,169		25,537		41,483		(849	)	73,053		88,242		556,125		192,639		258,017
Negative	(238,046	)	(64,626	)	(94,305	)	(180,568	)	(33,874	)	(36,359	)	(26,876	)	(100,853	)	(68,419	)	(445,490	)	(199,353	)	(199,083	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	2,171		1,705		1,788		(160	)	—		1,443		441		1,605		(525	)	2,452		3,310		2,706
Other gains (losses)	135		2,813		28,347		546		2,532		(16,215	)	—		—		9		681		5,345		12,141
Gain (loss) from other investments	51		113		—		—		72		(13,704	)			—		—		51		185		(13,704	)
Gain (loss) from the sale of property, plants and equipment	84		2,700		28,347		546		2,460		(2,511	)	—		—		9		630		5,160		25,845
Income before tax	1,332,422		1,126,262		932,946		774,744		574,450		466,447		(272,556	)	(55,064	)	(22,292	)	2,104,990		1,645,648		1,376,069
Income tax	(449,235	)	(359,599	)	(368,682	)	(24,007	)	(130,254	)	(190,768	)	35,310		(29,281	)	27,989		(437,932	)	(519,134	)	(531,461	)
Net income from continuing operations	883,187		766,663		564,264		750,737		444,196		275,679		(237,246	)	(84,345	)	5,697		1,667,058		1,126,514		844,608
Income from discontinued operations	—		—				—		—				—		—		170,263		—		—		170,263
NET INCOME	883,187		766,663		564,264		750,737		444,196		275,679		(237,246	)	(84,345	)	175,960		1,667,058		1,126,514		1,014,871
Net income attributable to:	883,187		766,663		564,264		750,737		444,196		275,679		(237,246	)	(84,345	)	175,960		1,667,058		1,126,514		1,014,871
Shareholders of Enel Américas	—		—		—		—		—		—		—		—		—		1,201,381		709,043		566,497
Non-controlling interests	—		—		—		—		—		—		—		—		—		465,677		417,471		448,374

	Generation						Distribution						Eliminations						Total
Line of Business STATEMENT OF CASH FLOWS	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
Net cash flows from (used in) operating activities	1,197,918		1,095,110		1,303,328		771,791		784,223		1,372,654		(125,144	)	(9,284	)	(143,796	)	1,844,565		1,870,049		2,532,186
Net cash flows from (used in) investing activities	(103,167	)	(886,371	)	(197,018	)	(1,022,549	)	(1,122,436	)	(800,639	)	(1,943,473	)	(470,334	)	262,699		(3,069,189	)	(2,479,141	)	(734,958	)
Net cash flows from (used in) financing activities	(865,538	)	(329,243	)	(798,301	)	367,923		361,865		(296,701	)	2,364,681		(621,142	)	1,151		1,867,066		(588,520	)	(1,093,851	)

The Holding, Eliminations and Others column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-175

35.3    Segment information by country

	Holding		Argentina		Brazil		Colombia		Peru		Eliminations				Total
Country ASSETS	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2018 ThUS$	12-31-2017 ThUS$
CURRENT ASSETS	526,410	265,002	644,916	711,201	4,198,462	2,519,658	710,105	725,443	488,825	458,183	(184,732	)	(134,066	)	6,383,986	4,545,421
Cash and cash equivalents	441,045	184,157	182,829	242,072	633,692	470,361	394,484	354,110	252,235	222,063	—		—		1,904,285	1,472,763
Other current financial assets	7,467	127	—	412	178,492	64,924	24,434	44,889	—	—	—		—		210,393	110,352
Other current non-financial assets	5,544	3,530	26,228	23,106	220,719	226,385	8,850	7,751	46,391	22,860	—		—		307,732	283,632
Trade and other current receivables	956	639	389,563	395,614	2,801,407	1,544,654	217,987	268,651	140,653	167,826	456		405		3,551,022	2,377,789
Current accounts receivable from related parties	71,184	68,433	16,513	28,732	106,693	43,040	1,403	1,612	3,732	57	(185,188	)	(134,471	)	14,337	7,403
Inventories	—	—	29,623	20,813	209,125	134,991	57,118	48,424	43,532	41,861	—		—		339,398	246,089
Current tax assets	214	8,116	160	452	48,334	35,303	4	6	2,282	3,516	—		—		50,994	47,393
Non-current assets or disposal groups held-for-sale or held for distribution to owners	—	—	—	—	—	—	5,825	—	—	—	—		—		5,825	—
NON-CURRENT ASSETS	7,491,715	7,410,770	2,585,687	1,516,003	11,585,461	6,861,343	4,200,842	4,372,366	3,828,620	3,908,055	(8,679,955	)	(8,444,967	)	21,012,370	15,623,570
Other non-current financial assets	—	—	14	27	2,795,863	1,751,137	598	1,103	—	—	—		—		2,796,475	1,752,267
Other non-current non-financial assets	3,414	2,403	927	5,825	1,127,643	541,556	8,753	9,017	—	—	(29	)	1,625		1,140,708	560,426
Trade and other non-current receivables	58	124	409,285	400,329	457,162	181,099	40,003	35,241	—	—	—		—		906,508	616,793
Non-current accounts receivable from related parties	375,000	375,000	108	255	7,768	57,512	—	—	—	—	(381,224	)	(429,922	)	1,652	2,845
Investments accounted for using the equity method	7,113,243	7,033,243	292,079	35,641	—	—	137	10	1,428,462	1,527,055	(8,831,325	)	(8,593,202	)	2,596	2,747
Intangible assets other than goodwill	—	—	22,170	17,628	5,653,825	3,546,462	95,095	77,886	56,199	40,503	—		—		5,827,289	3,682,479
Goodwill	—	—	4,827	1,022	662,218	129,200	5,902	6,421	—	—	532,623		576,532		1,205,570	713,175
Property, plant and equipment	—	—	1,856,267	1,004,634	436,248	504,650	4,050,353	4,242,686	2,343,959	2,340,497	—		—		8,686,827	8,092,467
Investment properties	—	—	—	—	11,708	—	—	—	—	—	—		—		11,708	—
Deferred tax assets	—	—	10	50,642	433,026	149,727	1	2	—	—	—		—		433,037	200,371
TOTAL ASSETS	8,018,125	7,675,772	3,230,603	2,227,204	15,783,923	9,381,001	4,910,947	5,097,809	4,317,445	4,366,238	(8,864,687	)	(8,579,033	)	27,396,356	20,168,991

F-176

	Holding				Argentina			Brazil		Colombia		Peru			Eliminations				Total
Country LIABILITIES AND EQUITY	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2018 ThUS$	12-31-2017 ThUS$		12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$
CURRENT LIABILITIES	461,314		85,879		1,094,163	1,211,389		6,524,191	2,157,537	1,116,652	942,968	490,066		487,036	(35,630	)	49,527		9,650,756		4,934,336
Other current financial liabilities	363,057		11,791		14,322	2,938		748,859	305,468	390,762	267,116	131,099		102,455	—		—		1,648,099		689,768
Trade and other current payables	43,723		35,090		716,892	924,655		2,461,540	1,556,408	535,183	483,152	222,164		250,202	136,745		74,346		4,116,247		3,323,853
Current accounts payable to related parties	53,178		37,377		114,938	50,329		2,912,524	90,778	53,265	50,746	35,138		20,616	(172,375	)	(24,819	)	2,996,668		225,027
Other current provisions	1,164		1,239		131,593	150,497		194,942	10,594	35,841	33,779	59,323		73,857	—		—		422,863		269,966
Current tax liabilities	—		54		89,622	51,191		15,965	32,399	73,902	84,650	13,435		4,344	—		—		192,924		172,638
Current provisions for employee benefits	—		—		—	—		—	—	—	—	—		—	—		—		—		—
Other current non-financial liabilities	192		328		26,796	31,779		190,361	161,890	23,864	23,525	28,907		35,562	—		—		270,120		253,084
Liabilities associated with groups of assets or disposal groups held for sale or distribution to owners	—		—		—	—		—	—	3,835	—	—		—	—		—		3,835		—
NON-CURRENT LIABILITIES	612,001		618,499		592,984	610,569		5,554,977	3,399,496	1,630,556	1,971,990	770,023		812,356	(246,841	)	(456,762	)	8,913,700		6,956,148
Other non-current financial liabilities	601,014		607,512		40,229	48,913		2,093,405	1,442,737	1,428,551	1,750,429	458,669		499,924	—		—		4,621,868		4,349,515
Trade and other non-current payables	—		15		195,385	337,338		727,211	630,010	—	—	10,460		11,206	—		—		933,056		978,569
Non-current accounts payable to related parties	—		—		6,230	53,642		240,611	403,120	—	—	—		—	(246,841	)	(456,762	)	—		—
Other long-term provisions	—		—		23,144	21,826		1,279,877	565,565	40,340	64,904	20,615		8,010	—		—		1,363,976		660,305
Deferred tax liabilities	8,374		8,140		244,255	37,724		11,188	130,381	32,622	18,010	249,631		261,056	—		—		546,070		455,311
Non-current provisions for employee benefits	2,613		2,832		14,599	26,960		1,198,014	227,048	123,151	127,565	5,130		4,526	—		—		1,343,507		388,931
Other non-current non-financial liabilities	—		—		69,142	84,166		4,671	635	5,892	11,082	25,518		27,634	—		—		105,223		123,517
EQUITY	—		6,971,394		1,543,456	405,246		3,704,755	3,823,968	2,163,739	2,182,851	3,057,356		3,066,846	(8,582,216	)	(8,171,798	)	8,831,900		8,278,507
Equity attributable to shareholders of Enel Américas	6,944,810		6,971,394		1,543,456	405,246		3,704,755	3,823,968	2,163,739	2,182,851	3,057,356		3,066,846	(8,582,216	)	(8,171,798	)	6,724,008		6,480,471
Issued capital	6,763,204		6,763,204		997,714	234,050		1,730,839	2,048,181	205,915	224,006	2,658,595		1,657,365	(5,593,063	)	(4,163,602	)	6,763,204		6,763,204
Retained earnings	3,423,217		3,449,803		13,202	274,033		532,531	414,775	639,936	484,805	522,144		148,516	(289,343	)	(1,188,101	)	4,841,687		3,583,831
Share premium	—		—		—	—		771,039	902,102	93,552	101,771	6,052		1,874	(870,643	)	(1,005,747	)	—		—
Treasury shares	—		—		—	—		—	—	—	—	—		—	—		—		—		—
Other equity interests	—		—		—	—		—	—	—	—	—		—	—		—		—		—
Other reserves	(3,241,611	)	(3,241,613	)	532,540	(102,837	)	670,346	458,910	1,224,336	1,372,269	(129,435	)	1,259,091	(1,829,167	)	(1,814,348	)	(4,880,883	)	(3,866,564	)
Non-controlling interests	—				—			—		—		—			—				2,107,892		1,798,036
Total Liabilities and Equity	8,018,125		7,675,772		3,230,603	2,227,204		15,783,923	9,381,001	4,910,947	5,097,809	4,317,445		4,366,238	(8,864,687	)	(8,579,033	)	27,396,356		20,168,991

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-177

	Holding						Argentina						Brazil						Colombia						Peru						Eliminations						Total
Country STATEMENTS OF PROIT (LOSS)	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
REVENUE AND OTHER OPERATING INCOME	1,335		4		11,232		1,516,392		1,520,474		1,267,901		7,489,756		5,132,814		2,761,747		2,671,192		2,384,407		2,262,236		1,505,635		1,400,304		1,339,466		(248	)	—		—		13,184,062		10,438,003		7,642,582
Revenues	—		—		9,527		1,488,830		1,482,423		1,137,695		6,520,243		4,285,949		2,281,557		2,642,886		2,366,028		2,244,990		1,467,175		1,354,866		1,334,139		—		—		—		12,119,134		9,489,266		7,007,908
Energy sales	—		—		—		1,443,845		1,426,617		1,076,132		5,865,566		3,841,034		2,058,455		2,388,426		2,128,847		2,038,739		1,231,686		1,162,579		1,177,642		—		—		—		10,929,523		8,559,077		6,350,968
Other sales	—		—		9,087		191		194		206		2,225		1,855		2,107		23,232		20,466		14,839		23,320		21,679		26,073		—		—		—		48,968		44,194		52,312
Other services rendered	—		—		440		44,794		55,612		61,357		652,452		443,060		220,995		231,228		216,715		191,412		212,169		170,608		130,424		—		—		—		1,140,643		885,995		604,628
Other operating income	1,335		4		1,705		27,562		38,051		130,206		969,513		846,865		480,190		28,306		18,379		17,246		38,460		45,438		5,327		(248	)	—		—		1,064,928		948,737		634,674
RAW MATERIALS AND CONSUMABLES USED	—		—		(4,191	)	(769,333	)	(712,345	)	(517,495	)	(5,366,693	)	(3,502,183	)	(1,653,590	)	(1,208,848	)	(950,865	)	(965,018	)	(798,330	)	(717,395	)	(727,924	)	431		—		—		(8,142,773	)	(5,882,788	)	(3,868,218	)
Energy purchases	—		—		—		(656,647	)	(619,314	)	(396,487	)	(3,855,878	)	(2,359,632	)	(1,034,768	)	(721,047	)	(529,504	)	(570,987	)	(505,630	)	(434,666	)	(443,189	)	1,598		2,650		2,912		(5,737,604	)	(3,940,466	)	(2,442,519	)
Fuel consumption	—		—		—		(21,095	)	(4,074	)	(72,647	)	(18,151	)	(70,470	)	(73,718	)	(53,414	)	(30,789	)	(69,912	)	(134,183	)	(123,975	)	(145,879	)	—		—		—		(226,843	)	(229,308	)	(362,156	)
Transportation expenses	—		—		—		(37,414	)	(15,926	)	(4,889	)	(631,737	)	(279,332	)	(112,922	)	(268,498	)	(244,492	)	(201,149	)	(116,615	)	(91,718	)	(72,225	)	(1,167	)	(2,650	)	(2,912	)	(1,055,431	)	(634,118	)	(394,097	)
Other miscellaneous supplies and services	—		—		(4,191	)	(54,177	)	(73,031	)	(43,472	)	(860,927	)	(792,749	)	(432,182	)	(165,889	)	(146,080	)	(122,970	)	(41,902	)	(67,036	)	(66,631	)	—		—		—		(1,122,895	)	(1,078,896	)	(669,446	)
CONTRIBUTION MARGIN	1,335		4		7,041		747,059		808,129		750,406		2,123,063		1,630,631		1,108,157		1,462,344		1,433,542		1,297,218		707,305		682,909		611,542		183		—		—		5,041,289		4,555,215		3,774,364
Other work performed by the entity and capitalized	—		—		—		54,308		75,737		53,810		83,214		69,089		25,607		29,408		19,386		13,097		11,067		8,974		6,935		—		—		—		177,997		173,186		99,449
Employee benefits expense	(6,732	)	(8,070	)	(14,931	)	(265,521	)	(370,729	)	(330,358	)	(402,618	)	(306,267	)	(141,745	)	(99,856	)	(89,244	)	(76,304	)	(65,766	)	(63,674	)	(62,764	)	—		—		—		(840,493	)	(837,984	)	(626,102	)
Other expenses	(27,113	)	(21,316	)	(50,535	)	(139,867	)	(185,752	)	(166,111	)	(603,682	)	(486,694	)	(347,940	)	(161,656	)	(160,646	)	(134,369	)	(88,585	)	(88,768	)	(118,420	)	(182	)	20		—		(1,021,085	)	(943,156	)	(817,375	)
GROSS OPERATING RESULT	(32,510	)	(29,382	)	(58,425	)	395,979		327,385		307,747		1,199,977		906,759		644,079		1,230,240		1,203,038		1,099,642		564,021		539,441		437,293		1		20		—		3,357,708		2,947,261		2,430,336
Depreciation and amortization expense	—		—		(213	)	(173,774	)	(78,353	)	(61,939	)	(375,937	)	(270,611	)	(148,606	)	(193,432	)	(177,419	)	(149,469	)	(119,297	)	(121,731	)	(113,011	)	—		—		—		(862,440	)	(648,114	)	(473,238	)
Impairment (losses) reversals recognized in profit or loss	—		—		(1,580	)	10,333		15,605		(13,688	)	(55,843	)	(76,255	)	(104,225	)	(14,674	)	(2,962	)	(35,530	)	(564	)	(16,136	)	(2,055	)			—		—		(60,748	)	(79,748	)	(157,078	)
OPERATING INCOME	(32,510	)	(29,382	)	(60,218	)	232,538		264,637		232,120		768,197		559,893		391,248		1,022,134		1,022,657		914,643		444,160		401,574		322,227		1		20		—		2,434,520		2,219,399		1,800,020
FINANCIAL RESULT	(19,825	)	(3,438	)	28,745		257,912		(145,441	)	(153,569	)	(430,868	)	(225,126	)	(82,448	)	(159,753	)	(174,979	)	(197,153	)	(18,583	)	(33,422	)	(34,373	)	38,454		—		—		(332,663	)	(582,406	)	(438,798	)
Financial income	47,281		29,595		50,037		107,807		87,760		62,337		215,449		179,316		140,421		19,748		19,371		23,942		8,583		9,138		6,816		(40,787	)	(31,337	)	(7,096	)	358,081		293,843		276,457
Cash and cash equivalents	7,245		8,207		44,463		75,692		61,757		51,545		33,259		32,537		31,030		12,533		13,297		20,015		4,451		7,341		3,267		—		—		—		133,180		123,139		150,320
Other financial income	40,036		21,388		5,574		32,115		26,003		10,792		182,190		146,779		109,391		7,215		6,074		3,927		4,132		1,797		3,549		(40,787	)	(31,337	)	(7,096	)	224,901		170,704		126,137
Financial costs	(61,869	)	(38,662	)	(37,471	)	(226,859	)	(265,443	)	(248,774	)	(614,811	)	(361,158	)	(232,179	)	(177,537	)	(193,550	)	(221,529	)	(31,469	)	(42,059	)	(40,086	)	40,786		31,337		6,882		(1,071,759	)	(869,535	)	(773,157	)
Bank borrowings	(8,084	)	—		(1	)	(177	)	(136	)	(2,196	)	(131,557	)	(65,154	)	(49,349	)	(19,659	)	(25,090	)	(24,726	)	(2,715	)	(7,115	)	(8,481	)	—		—		—		(162,192	)	(97,495	)	(84,753	)
Secured and unsecured obligations	(25,736	)	(25,977	)	(23,567	)	—		—		—		(124,722	)	(35,259	)	(58,201	)	(133,916	)	(138,469	)	(176,995	)	(27,830	)	(16,131	)	(26,079	)	—		—		—		(312,204	)	(215,836	)	(284,842	)
Other	(28,049	)	(12,685	)	(13,903	)	(226,682	)	(265,307	)	(246,578	)	(358,532	)	(260,745	)	(124,629	)	(23,962	)	(29,991	)	(19,808	)	(924	)	(18,813	)	(5,526	)	40,786		31,337		6,882		(597,363	)	(556,204	)	(403,562	)
Gains (losses) from indexed assets and liabilities	—		—		(1,032	)	270,380		—		—		—		—		—		—		—		—		—		—		—		—		—		—		270,380		—		(1,032	)
Foreign currency exchange differences	(5,237	)	5,629		17,211		106,584		32,242		32,868		(31,506	)	(43,284	)	9,310		(1,964	)	(800	)	434		4,303		(501	)	(1,103	)	38,455		—		214		110,635		(6,714	)	58,934
Positive	39,694		81,484		79,742		262,165		72,910		81,643		402,562		64,474		70,012		12,950		4,435		6,220		22,096		17,331		37,217		(183,342	)	(47,995	)	(16,817	)	556,125		192,639		258,017
Negative	(44,931	)	(75,855	)	(62,531	)	(155,581	)	(40,668	)	(48,775	)	(434,068	)	(107,758	)	(60,702	)	(14,914	)	(5,235	)	(5,786	)	(17,793	)	(17,832	)	(38,320	)	221,797		47,995		17,031		(445,490	)	(199,353	)	(199,083	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	441		1,605		(525	)	2,011		1,705		1,788		—		—		—		—		—		1,443		—		—		—		—		—				2,452		3,310		2,706
Other gains (losses)	—		—		10		74		230		(43	)	386		954		(1,232	)	190		474		(15,002	)	31		3,687		28,408		—		—		—		681		5,345		12,141
Gain (loss) from other investments	—		—		—		51		168		56		—		—		—		—		—		(13,760	)	—		17		—		—		—		—		51		185		(13,704	)
Gain (loss) from the sale of property, plants and equipment	—		—		10		23		62		(99	)	386		954		(1,232	)	190		474		(1,242	)	31		3,670		28,408		—		—		—		630		5,160		25,845
Income before tax	(51,894	)	(31,215	)	(31,988	)	492,535		121,131		80,296		337,715		335,721		307,568		862,571		848,152		703,931		425,608		371,839		316,262		38,455		20		—		2,104,990		1,645,648		1,376,069
Income tax	(7,137	)	(28,109	)	17,832		(203,661	)	27,183		(44,673	)	217,748		(66,666	)	(69,565	)	(310,823	)	(336,689	)	(292,755	)	(134,059	)	(114,853	)	(142,300	)	—		—		—		(437,932	)	(519,134	)	(531,461	)
Net income from continuing operations	(59,031	)	(59,324	)	(14,156	)	288,874		148,314		35,623		555,463		269,056		238,003		551,748		511,463		411,176		291,549		256,986		173,962		38,455		20		—		1,667,058		1,126,514		844,608
Income from discontinued operations	—		—		170,263		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		170,263
NET INCOME	(59,031	)	(59,324	)	156,107		288,874		148,314		35,623		555,463		269,056		238,003		551,748		511,463		411,176		291,549		256,986		173,962		38,455		20		—		1,667,058		1,126,514		1,014,871
Net income attributable to:	(59,031	)	(59,324	)	156,107		288,874		148,314		35,623		555,463		269,056		238,003		551,748		511,463		411,176		291,549		256,986		173,962		38,455		20		—		1,667,058		1,126,514		1,014,871
Shareholders of Enel Américas	—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		1,201,381		709,043		566,497
Non-controlling interests	—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		465,677		417,471		448,374

	Holding						Argentina						Brazil						Colombia						Peru						Eliminations						Total
Line of Business STATEMENT OF CASH FLOWS	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
Net cash flows from (used in) operating activities	(34,496	)	23,174		115,344		157,539		209,757		328,608		299,827		371,425		765,662		1,030,940		898,396		874,110		390,044		334,592		446,371		711		32,705		2,091		1,844,565		1,870,049		2,532,186
Net cash flows from (used in) investing activities	348,295		(982,614	)	487,375		(98,752	)	(122,760	)	(157,218	)	(2,434,755	)	(1,809,287	)	(404,148	)	(378,451	)	(390,586	)	(318,358	)	(89,786	)	(1,085,017	)	(78,024	)	(415,740	)	1,911,123		(264,585	)	(3,069,189	)	(2,479,141	)	(734,958	)
Net cash flows from (used in) financing activities	(52,458	)	(319,794	)	(628,712	)	(23,844	)	(17,354	)	12,592		2,389,830		1,608,280		(233,539	)	(601,744	)	(575,395	)	(372,210	)	(259,879	)	659,599		(134,402	)	415,161		(1,943,856	)	262,420		1,867,066		(588,520	)	(1,093,851	)

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-178

35.4   Generation and Transmission, and Distribution by Country

a)       Generation and transmission

	Generation and Transmission
Line of business	Chile		Argentina		Brazil		Colombia		Peru		Eliminations				Total
Country ASSETS	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2018 ThUS$	12-31-2017 ThUS$
CURRENT ASSETS	—	—	334,670	316,209	647,181	437,446	339,038	327,200	412,115	412,379	(95,886	)	(64,820	)	1,637,118	1,428,414
Cash and cash equivalents	—	—	155,473	140,455	165,998	136,694	197,708	179,828	221,980	141,609			—		741,159	598,586
Other current financial assets	—	—		—	109,137	45,592	24,387	28,657		—			—		133,524	74,249
Other current non-financial assets	—	—	18,603	15,674	18,911	15,849	2,104	4,263	6,249	13,112			—		45,867	48,898
Trade and other current receivables	—	—	138,194	127,072	225,977	164,624	52,982	96,775	88,382	94,691	385		(640	)	505,920	482,522
Current accounts receivable from related parties	—	—	17,731	29,225	114,531	72,251	41,668	668	63,564	129,279	(96,271	)	(64,180	)	141,223	167,243
Inventories	—	—	4,509	3,331	405	474	20,185	17,004	30,624	31,119			—		55,723	51,928
Current tax assets	—	—	160	452	12,222	1,961	4	6	1,316	2,569			—		13,702	4,988
Non-current assets or disposal groups held for sale or held for distribution to owners	—	—		—		—		—		—			—		—	—
NON-CURRENT ASSETS	—	—	1,188,893	656,379	833,154	1,024,938	2,515,463	2,703,618	1,245,705	1,305,808	(977	)	(33,220	)	5,782,238	5,657,523
Other non-current financial assets	—	—		—	366,010	420,794	592	1,094		—			—		366,602	421,888
Other non-current non-financial assets	—	—	769	5,513	16,759	20,820	4,053	4,342		—	(29	)	1,625		21,552	32,300
Trade and other non-current receivables	—	—	404,821	390,436	26	1,198	3,520	4,058		—			—		408,367	395,692
Non-current accounts receivable from related parties	—	—		—	2,521	37,486		—	2,091	—	(948	)	(34,845	)	3,664	2,641
Investments accounted for using the equity method	—	—	277,022	6,426	46,834	54,794		—	55,544	82,512			—		379,400	143,732
Intangible assets other than goodwill	—	—	263	26	5,484	5,665	24,570	24,900	21,759	17,275			—		52,076	47,866
Goodwill	—	—	4,827	1,022		—	5,902	6,421		—			—		10,729	7,443
Property, plant and equipment	—	—	501,181	252,934	369,634	452,757	2,476,825	2,662,801	1,166,311	1,206,021			—		4,513,951	4,574,513
Investment properties	—	—		—		—		—		—			—		—	—
Deferred tax assets	—	—	10	23	25,886	31,424	1	2		—			—		25,897	31,449
TOTAL ASSETS	—	—	1,523,563	972,588	1,480,335	1,462,384	2,854,501	3,030,818	1,657,820	1,718,187	(96,863	)	(98,040	)	7,419,356	7,085,937

F-179

	Generation and Transmission
Line of business	Chile		Argentina			Brazil		Colombia		Peru			Eliminations				Total
Country LIABILITIES AND EQUITY	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$		12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2018 ThUS$	12-31-2017 ThUS$
CURRENT LIABILITIES	—	—	385,283	293,504		642,003	308,085	511,097	399,796	224,273		247,092	(80,218	)	(35,350	)	1,682,438	1,213,127
Other current financial liabilities	—	—	14,322	2,938		268,907	5,336	234,532	154,957	39,527		45,176	—		—		557,288	208,407
Trade and other current payables	—	—	168,070	185,205		332,055	238,268	157,577	122,971	90,356		119,408	91		130		748,149	665,982
Current accounts payable to related parties	—	—	114,209	48,483		15,935	18,663	33,850	30,053	28,511		14,813	(80,309	)	(35,480	)	112,196	76,532
Other current provisions		—	—	—		—	—	25,516	30,940	49,008		59,003	—		—		74,524	89,943
Current tax liabilities		—	74,814	40,892		14,941	32,399	52,340	54,038	8,296		1,759	—		—		150,391	129,088
Current provisions for employee benefits		—	—	—		—	—	—	—	—		—	—		—		—	—
Other current non-financial liabilities		—	13,868	15,986		10,165	13,419	7,282	6,837	8,575		6,933	—		—		39,890	43,175
Liabilities associated with assets or disposal groups held for sale or distribution to owners	—	—		—			—		—			—			—		—	—
NON-CURRENT LIABILITIES	—	—	245,332	312,457		82,461	385,093	1,032,101	1,335,486	328,323		361,261	(16,645	)	(62,690	)	1,671,572	2,331,607
Other non-current financial liabilities	—	—	40,229	48,913		60,398	324,117	936,776	1,247,200	79,834		117,758			—		1,117,237	1,737,988
Trade and other non-current payables	—	—	44,393	84,225		500	621		—			—			—		44,893	84,846
Non-current accounts payable to related parties	—	—	6,230	53,642		15,668	53,011		—			—	(16,645	)	(62,690	)	5,253	43,963
Other long-term provisions	—	—		—		3,831	6,817	37,412	48,136	20,134		7,521			—		61,377	62,474
Deferred tax liabilities	—	—	83,005	37,724		—	527	30,926	11,428	203,144		208,793			—		317,075	258,472
Non-current provisions for employee benefits	—	—	3,508	6,184		—	—	26,987	28,722	1,578		1,521			—		32,073	36,427
Other non-current non-financial liabilities	—	—	67,967	81,769		2,064	—		—	23,633		25,668			—		93,664	107,437
EQUITY	—	—	892,948	366,628		755,871	769,205	1,311,303	1,295,537	1,105,224		1,109,834	—		—		4,065,346	3,541,204
Equity attributable to shareholders of Enel Américas	—	—	892,948	366,628		755,871	769,205	1,311,303	1,295,537	1,105,224		1,109,834	—		—		4,065,346	3,541,204
Issued capital	—	—	111,092	162,708		275,319	322,118	201,762	219,488	913,296		891			—		1,501,469	705,205
Retained earnings	—	—	258,124	315,019		289,470	322,261	446,982	323,370	389,902		229,920			—		1,384,478	1,190,570
Share premium	—	—		—			—	34,875	37,939	4,327		74	—		—		39,202	38,013
Treasury shares	—	—		—			—		—			—			—		—	—
Other equity interests	—	—		—			—		—			—			—		—	—
Other reserves	—	—	523,732	(111,099	)	191,082	124,826	627,684	714,740	(202,301	)	878,949			—		1,140,197	1,607,416
Non-controlling interests	—	—		—			—		—			—			—		—	—
TOTAL LIABILITIES AND EQUITY	—	—	1,523,563	972,589		1,480,335	1,462,383	2,854,501	3,030,819	1,657,820		1,718,187	(96,863	)	(98,040	)	7,419,356	7,085,938

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-180

	Generation and Transmission
Line of business	Chile				Argentina						Brazil						Colombia						Peru						Eliminations						Total
Country STATEMENTS OF PROIT (LOSS)	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
REVENUE AND OTHER OPERATING INCOME	—	—	—		327,613		299,771		307,022		853,595		829,715		572,463		1,259,471		1,159,788		1,151,866		790,356		730,413		678,766		(244	)	—		—		3,230,791		3,019,687		2,710,117
Revenues	—	—	—		314,689		288,760		217,309		841,722		796,792		550,034		1,242,506		1,151,492		1,142,581		757,351		689,464		677,436		—		—		—		3,156,268		2,926,508		2,587,360
Energy sales	—	—	—		313,502		288,568		217,294		759,653		709,105		473,330		1,220,266		1,132,015		1,127,716		521,658		506,125		531,399		—		—		—		2,815,079		2,635,813		2,349,739
Other sales	—	—	—		21		—		—		—		—		—		22,095		19,300		14,677		22,694		21,189		25,269		—		—		—		44,810		40,489		39,946
Other services rendered	—	—	—		1,166		192		15		82,069		87,687		76,704		145		177		188		212,999		162,150		120,768		—		—		—		296,379		250,206		197,675
Other operating income	—	—	—		12,924		11,011		89,713		11,873		32,923		22,429		16,965		8,296		9,285		33,005		40,949		1,330		(244	)	—		—		74,523		93,179		122,757
RAW MATERIALS AND CONSUMABLES USED	—	—	—		(40,070	)	(25,389	)	(88,050	)	(574,420	)	(490,159	)	(268,643	)	(478,264	)	(396,302	)	(433,625	)	(382,603	)	(347,476	)	(347,053	)	429		—		—		(1,474,928	)	(1,259,326	)	(1,137,371	)
Energy purchases	—	—	—		(1,343	)	(1,374	)	(1,240	)	(525,539	)	(393,265	)	(166,195	)	(191,690	)	(165,039	)	(195,204	)	(124,184	)	(94,180	)	(96,281	)	1,596		2,650		2,912		(841,160	)	(651,208	)	(456,008	)
Fuel consumption	—	—	—		(21,095	)	(4,074	)	(72,647	)	(18,151	)	(70,470	)	(73,718	)	(53,414	)	(30,789	)	(69,912	)	(134,183	)	(123,975	)	(145,879	)			—		—		(226,843	)	(229,308	)	(362,156	)
Transportation expenses	—	—	—		(6,937	)	(7,389	)	(3,687	)	(30,474	)	(26,226	)	(20,268	)	(143,045	)	(128,296	)	(106,375	)	(116,615	)	(91,718	)	(72,252	)	(1,167	)	(2,650	)	(2,912	)	(298,238	)	(256,279	)	(205,494	)
Other miscellaneous supplies and services	—	—	—		(10,695	)	(12,552	)	(10,476	)	(256	)	(198	)	(8,462	)	(90,115	)	(72,178	)	(62,134	)	(7,621	)	(37,603	)	(32,641	)			—		—		(108,687	)	(122,531	)	(113,713	)
CONTRIBUTION MARGIN	—	—	—		287,543		274,382		218,972		279,175		339,556		303,820		781,207		763,486		718,241		407,753		382,937		331,713		185		—		—		1,755,863		1,760,361		1,572,746
Other work performed by the entity and capitalized	—	—	—		5,011		6,300		13,637		553		903		1,135		2,468		910		1,142		1,435		739		226		—		—		—		9,467		8,852		16,140
Employee benefits expense	—	—	—		(45,672	)	(73,209	)	(67,799	)	(16,364	)	(18,426	)	(15,547	)	(30,726	)	(27,270	)	(23,606	)	(30,096	)	(29,190	)	(27,967	)	—		—		—		(122,858	)	(148,095	)	(134,919	)
Other expenses	—	—	—		(28,977	)	(36,680	)	(28,608	)	(19,683	)	(20,404	)	(18,432	)	(45,800	)	(55,117	)	(49,095	)	(45,395	)	(42,833	)	(64,203	)	(176	)	—		—		(140,031	)	(155,034	)	(160,338	)
GROSS OPERATING RESULT	—	—	—		217,905		170,793		136,202		243,681		301,629		270,976		707,149		682,009		646,682		333,697		311,653		239,769		9		—		—		1,502,441		1,466,084		1,293,629
Depreciation and amortization expense	—	—	—		(121,545	)	(55,942	)	(45,224	)	(32,681	)	(38,863	)	(30,753	)	(73,252	)	(71,196	)	(62,886	)	(68,241	)	(72,354	)	(69,210	)	—		—		—		(295,719	)	(238,355	)	(208,073	)
Impairment (losses) reversals recognized in profit or loss	—	—	—		59,316		(28	)	(51	)	(260	)	(725	)	(580	)	(822	)	145		(33,540	)	3,755		(10,626	)	—		—		—		—		61,989		(11,234	)	(34,171	)
OPERATING INCOME	—	—	—		155,676		114,823		90,927		210,740		262,041		239,643		633,075		610,958		550,256		269,211		228,673		170,559		9		—		—		1,268,711		1,216,495		1,051,385
FINANCIAL RESULT	—	—	—		116,452		26,873		7,811		18,757		7,262		(759	)	(101,982	)	(119,198	)	(145,270	)	8,420		(9,688	)	(10,356	)	28,573		—		—		70,220		(94,751	)	(148,574	)
Financial income	—	—	—		69,536		49,282		34,950		32,044		24,201		15,493		8,361		9,160		15,273		6,888		6,143		3,028		—		(8,880	)	(1,957	)	116,829		79,906		66,787
Cash and cash equivalents	—	—	—		65,748		39,533		31,917		7,712		12,022		8,788		7,025		7,361		14,112		3,768		4,272		1,832		—		—		—		84,253		63,188		56,649
Other financial income	—	—	—		3,788		9,749		3,033		24,332		12,179		6,705		1,336		1,799		1,161		3,120		1,871		1,196		—		(8,880	)	(1,957	)	32,576		16,718		10,138
Financial costs	—	—	—		(43,642	)	(51,507	)	(60,727	)	(35,648	)	(19,284	)	(17,230	)	(110,076	)	(128,201	)	(161,273	)	(5,002	)	(13,968	)	(12,075	)	—		8,880		1,957		(194,368	)	(204,080	)	(249,348	)
Bank borrowings	—	—	—		(43	)	(89	)	(2,123	)	(11,321	)	(3,075	)	(577	)	(6,638	)	(9,755	)	(16,467	)	(219	)	(993	)	(5,069	)			—		—		(18,221	)	(13,912	)	(24,236	)
Secured and unsecured obligations	—	—	—				—		—		(201	)	—		—		(95,921	)	(106,116	)	(135,420	)	(2,857	)	(2,481	)	(4,230	)			—		—		(98,979	)	(108,597	)	(139,650	)
Other	—	—	—		(52,414	)	(51,418	)	(58,604	)	(24,126	)	(16,209	)	(16,653	)	(7,517	)	(12,330	)	(9,386	)	(1,926	)	(10,494	)	(2,776	)			8,880		1,957		(85,983	)	(81,571	)	(85,462	)
Gains (losses) from indexed assets and liabilities	—	—	—		8,815		—		—				—		—				—		—				—		—				—		—		8,815		—		—
Foreign currency exchange differences	—	—	—		90,558		29,098		33,588		22,361		2,345		978		(267	)	(157	)	730		6,534		(1,863	)	(1,309	)	28,573		—		—		147,759		29,423		33,987
Positive	—	—	—		237,834		68,622		79,263		149,903		20,108		25,341		7,800		3,320		3,882		18,929		14,109		32,753		(28,661	)	(12,110	)	(12,947	)	385,805		94,049		128,292
Negative	—	—	—		(147,276	)	(39,524	)	(45,675	)	(127,542	)	(17,763	)	(24,363	)	(8,067	)	(3,477	)	(3,152	)	(12,395	)	(15,972	)	(34,062	)	57,234		12,110		12,947		(238,046)		(64,626	)	(94,305	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	—	—	—		2,171		1,705		1,788		—		—		—		—		—		—		—		—		—		—		—		—		2,171		1,705		1,788
Other gains (losses)	—	—	—		74		101		(99	)	—		—		—		24		330		70		37		2,382		28,376		—		—		—		135		2,813		28,347
Gain (loss) from other investments	—	—	—		51		96		—		—		—		—		—		—		—		—		17		—		—		—		—		51		113		—
Gain (loss) from the sale of assets	—	—	—		23		5		(99	)	—		—		—		24		330		70		37		2,365		28,376		—		—		—		84		2,700		28,347
Income before tax	—	—	—		274,373		143,502		100,427		229,497		269,303		238,884		531,117		492,090		405,056		277,668		221,367		188,579		28,582		—		—		1,341,237		1,126,262		932,946
Income tax	—	—	—		(99,141	)	(8,618	)	(34,156	)	(78,870	)	(90,718	)	(83,272	)	(185,554	)	(191,743	)	(158,133	)	(85,670	)	(68,520	)	(93,121	)	—		—		—		(449,235	)	(359,599	)	(368,682	)
Net income from continuing operations	—	—	—		175,232		134,884		66,271		150,627		178,585		155,612		345,563		300,347		246,923		191,998		152,847		95,458		28,582		—		—		892,002		766,663		564,264
Income from discontinued operations	—	—	—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—
NET INCOME	—	—	—		175,232		134,884		66,271		150,627		178,585		155,612		345,563		300,347		246,923		191,998		152,847		95,458		28,582		—		—		892,002		766,663		564,264
	Chile				Argentina						Brazil						Colombia						Peru						Eliminations						Total
Country STATEMENT OF CASH FLOWS	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
Net cash flows from (used in) operating activities	—	—	218,464		110,238		140,035		64,075		206,457		247,841		229,293		626,538		511,544		520,340		254,685		195,690		271,229		—		—		(73	)	1,197,918		1,095,110		1,303,328
Net cash flows from (used in) investing activities	—	—	(67,239	)	(16,483	)	(20,172	)	(34,031	)	(67,384	)	(454,441	)	(26,028	)	(109,801	)	(127,976	)	(110,432	)	90,501		(283,782	)	40,712		—		—		—		(103,167	)	(886,371	)	(197,018	)
Net cash flows from (used in) financing activities	—	—	(225,540	)	(23,726	)	(17,305	)	13,374		(90,783	)	264,451		(160,599	)	(494,832	)	(413,466	)	(301,913	)	(256,197	)	(162,923	)	(123,623	)	—		—		—		(865,538	)	(329,243	)	(798,301	)

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-181

b)      Distribution

	Distribution
	Chile		Argentina		Brazil		Colombia		Peru		Eliminations			Total
Line of business	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018		12-31-2017	12-31-2018	12-31-2017
Country	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$	ThUS$	ThUS$
ASSETS
CURRENT ASSETS	—	—	312,128	396,740	3,379,172	1,958,520	416,279	402,852	112,287	169,383	(7	)	—	4,219,859	2,927,495
Cash and cash equivalents	—	—	27,356	101,615	345,537	220,764	196,776	174,282	29,776	79,953	—		—	599,445	576,614
Other current financial assets	—	—	—	412	42,320	9,531	47	16,232	—	—	—		—	42,367	26,175
Other current non-financial assets	—	—	7,590	7,365	198,877	207,810	6,746	3,488	8,463	3,882	—		—	221,676	222,545
Trade and other current receivables	—	—	251,369	268,542	2,568,773	1,375,070	165,005	171,876	52,271	73,132	—		—	3,037,418	1,888,620
Current accounts receivable from related parties	—	—	699	1,324	2,077	990	4,947	5,554	8,869	1,674	(7	)	—	16,585	9,542
Inventories	—	—	25,114	17,482	208,414	134,064	36,933	31,420	12,908	10,742	—		—	283,369	193,708
Current tax assets	—	—		—	13,174	10,291		—		—	—		—	13,174	10,291
Non-current assets or disposal groups held for sale or held for distribution to owners	—	—		—		—	5,825	—		—	—		—	5,825	—
NON-CURRENT ASSETS	—	—	1,381,972	830,423	10,742,727	5,849,861	1,685,379	1,668,748	1,210,429	1,156,085	—		—	15,020,507	9,505,117
Other non-current financial assets	—	—	14	27	2,429,698	1,325,445	6	9		—	—		—	2,429,718	1,325,481
Other non-current non-financial assets	—	—	158	312	1,110,027	520,094	4,700	4,675		—	—		—	1,114,885	525,081
Trade and other non-current receivables	—	—	4,464	9,894	457,136	179,869	36,483	31,183		—	—		—	498,083	220,946
Non-current accounts receivable from related parties	—	—	108	255		—		—		—	—		—	108	255
Investments accounted for using the equity method	—	—	235	14	—	—	137	10		—	—		—	372	24
Intangible assets other than goodwill	—	—	21,907	17,602	5,637,387	3,533,935	70,525	52,986	31,601	20,270	—		—	5,761,420	3,624,793
Goodwill	—	—		—	662,218	129,200		—		—	—		—	662,218	129,200
Property, plant and equipment	—	—	1,355,086	751,700	59,670	44,132	1,573,528	1,579,885	1,178,828	1,135,815	—		—	4,167,112	3,511,532
Investment properties	—	—		—	11,708	—		—		—	—		—	11,708	—
Deferred tax assets	—	—		50,619	374,883	117,186		—		—	—		—	374,883	167,805
TOTAL ASSETS	—	—	1,694,100	1,227,163	14,121,899	7,808,381	2,101,658	2,071,600	1,322,716	1,325,468	(7	)	—	19,240,366	12,432,612

	Distribution
	Chile		Argentina			Brazil				Colombia		Peru		Eliminations			Total
Line of business	12-31-2018	12-31-2017	12-31-2018	12-31-2017		12-31-2018		12-31-2017		12-31-2018	12-31-2017	12-31-2018	12-31-2017	12-31-2018		12-31-2017	12-31-2018		12-31-2017
Country	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$		ThUS$		ThUS$	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$	ThUS$		ThUS$
LIABILITIES AND EQUITY
CURRENT LIABILITIES		—	710,708	919,538		3,434,286		2,042,696		650,767	547,781	268,882	299,001	(7	)	—	5,064,636		3,809,016
Other current financial liabilities		—		—		479,938		299,790		156,230	112,159	65,715	57,279	—		—	701,883		469,228
Trade and other current payables		—	548,694	739,200		2,117,898		1,306,373		377,606	360,181	131,188	130,252	—		—	3,175,386		2,536,006
Current accounts payable to related parties		—	2,686	3,755		483,142		286,177		64,627	25,303	36,369	65,585	(7	)	—	586,817		380,820
Other current provisions			131,593	150,498		194,941		10,594		10,325	2,839	10,315	14,854	—		—	347,174		178,785
Current tax liabilities			14,808	10,298		1,024		—		21,562	30,612	4,963	2,402	—		—	42,357		43,312
Current provisions for employee benefits				—				—			—		—	—		—	—		—
Other current non-financial liabilities			12,927	15,787		157,343		139,762		16,582	16,687	20,332	28,629	—		—	207,184		200,865
Liabilities associated with assets or disposal groups held for sale or distribution to owners		—		—				—		3,835	—	—	—	—		—	3,835		—
NON-CURRENT LIABILITIES	—	—	347,653	298,112		5,247,163		2,699,977		598,455	636,504	431,856	440,183	—		—	6,625,127		4,074,776
Other non-current financial liabilities	—	—	—	—		2,033,008		1,109,949		491,775	503,229	378,835	382,166	—		—	2,903,618		1,995,344
Trade and other non-current payables	—	—	150,992	253,113		726,711		629,388			—		294	—		—	877,703		882,795
Non-current accounts payable to related parties	—	—		—				54,016			—		—	—		—	—		54,016
Other long-term provisions	—	—	23,144	21,826		1,275,636		558,465		2,928	16,768	481	489	—		—	1,302,189		597,548
Deferred tax liabilities	—	—	161,250	—		11,188		121,112		1,696	6,582	47,103	52,263	—		—	221,237		179,957
Non-current provisions for employee benefits	—	—	11,091	20,776		1,198,014		227,047		96,164	98,843	3,552	3,005	—		—	1,308,821		349,671
Other non-current non-financial liabilities	—	—	1,176	2,397		2,606		—		5,892	11,082	1,885	1,966	—		—	11,559		15,445
EQUITY	—	—	635,739	9,513		5,440,450		3,065,708		852,436	887,315	621,978	586,284	—		—	7,550,603		4,548,820
Equity attributable to shareholders of Enel Américas	—	—	635,739	9,513		5,440,450		3,065,708		852,436	887,315	621,978	586,284	—		—	7,550,603		4,548,820
Issued capital	—	—	563,803	44,904		2,873,858		2,346,393		4,153	4,518	157,383	—	—		—	3,599,197		2,395,815
Retained earnings	—	—	69,177	(37,196	)	(1,184,278	)	(1,330,578	)	192,954	161,435	414,874	203,281	—		—	(507,273	)	(1,003,058	)
Share premium	—	—		—				—		58,677	63,832		—	—		—	58,677		63,832
Treasury shares	—	—		—		(12,704	)	—			—		—	—		—	(12,704	)	—
Other equity interests	—	—		—				—			—		—	—		—	—		—
Other reserves	—	—	2,759	1,805		3,763,574		2,049,893		596,652	657,530	49,721	383,003	—		—	4,412,706		3,092,231
Non-controlling interests	—	—	—	—				—		—	—	—	—	—		—	—		—
TOTAL LIABILITIES AND EQUITY	—	—	1,694,100	1,227,163		14,121,899		7,808,381		2,101,658	2,071,600	1,322,716	1,325,468	(7	)	—	19,240,366		12,432,612

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-182

																	Distribution
	Chile				Argentina						Brazil						Colombia						Peru						Eliminations				Total
Line of business Country	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$	12-31-2016 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
STATEMENTS OF PROIT (LOSS)
REVENUE AND OTHER OPERATING INCOME	—	—	—		1,189,950		1,223,343		982,122		6,922,417		4,612,551		2,490,631		1,713,801		1,537,957		1,366,350		912,950		879,266		865,430		(3	)	—	—	10,739,115		8,253,117		5,704,533
Revenues	—	—	—		1,174,151		1,193,683		939,610		5,965,107		3,798,613		2,032,870		1,702,390		1,527,674		1,358,209		907,247		874,408		861,275		—		—	—	9,748,895		7,394,378		5,191,964
Energy sales	—	—	—		1,130,353		1,138,069		878,062		5,396,919		3,447,388		1,893,471		1,422,918		1,264,632		1,127,793		856,278		813,804		809,474		—		—	—	8,806,468		6,663,893		4,708,800
Other sales	—	—	—		170		194		206		2,225		1,855		2,107		1,137		1,166		162		626		490		804		—		—	—	4,158		3,705		3,279
Other services rendered	—	—	—		43,628		55,420		61,342		565,963		349,370		137,292		278,335		261,876		230,254		50,343		60,114		50,997		—		—	—	938,269		726,780		479,885
Other operating income	—	—	—		15,799		29,660		42,512		957,310		813,938		457,761		11,411		10,283		8,141		5,703		4,858		4,155		(3	)	—	—	990,220		858,739		512,569
RAW MATERIALS AND CONSUMABLES USED	—	—	—		(729,223	)	(686,912	)	(448,621	)	(5,084,253	)	(3,323,143	)	(1,689,265	)	(1,032,452	)	(867,491	)	(787,177	)	(610,701	)	(578,759	)	(584,948	)	—		—	—	(7,456,629	)	(5,456,305	)	(3,510,011	)
Energy purchases	—	—	—		(655,312	)	(617,960	)	(395,267	)	(3,621,322	)	(2,281,798	)	(1,158,531	)	(784,872	)	(632,783	)	(587,454	)	(576,420	)	(549,326	)	(550,433	)	—		—	—	(5,637,926	)	(4,081,867	)	(2,691,685	)
Fuel consumption	—	—	—				—		—				—		—				—		—				—		—		—		—	—	—		—		—
Transportation expenses	—	—	—		(30,477	)	(8,537	)	(1,202	)	(609,880	)	(258,156	)	(94,069	)	(171,492	)	(160,406	)	(133,050	)			—		—		—		—	—	(811,849	)	(427,099	)	(228,321	)
Other miscellaneous supplies and services	—	—	—		(43,434	)	(60,415	)	(52,152	)	(853,051	)	(783,189	)	(436,665	)	(76,088	)	(74,302	)	(66,673	)	(34,281	)	(29,433	)	(34,515	)	—		—	—	(1,006,854	)	(947,339	)	(590,005	)
CONTRIBUTION MARGIN	—	—	—		460,727		536,431		533,501		1,838,164		1,289,408		801,366		681,349		670,466		579,173		302,249		300,507		280,482		(3	)	—	—	3,282,486		2,796,812		2,194,522
Other work performed by the entity and capitalized	—	—	—		49,297		69,437		40,174		82,661		68,186		24,407		26,940		18,476		11,955		9,632		8,235		6,666		—		—	—	168,530		164,334		83,202
Employee benefits expense	—	—	—		(219,849	)	(297,520	)	(262,559	)	(369,620	)	(269,029	)	(110,570	)	(69,130	)	(61,974	)	(52,698	)	(35,663	)	(34,482	)	(34,587	)	—		—	—	(694,262	)	(663,005	)	(460,414	)
Other expenses	—	—	—		(110,973	)	(150,619	)	(139,339	)	(545,006	)	(439,809	)	(300,598	)	(116,190	)	(106,038	)	(85,628	)	(44,081	)	(44,194	)	(41,413	)	3		—	—	(816,247	)	(740,660	)	(566,978	)
GROSS OPERATING RESULT	—	—	—		179,202		157,729		171,777		1,006,199		648,756		414,605		522,969		520,930		452,802		232,137		230,066		211,148		—		—	—	1,940,507		1,557,481		1,250,332
Depreciation and amortization expense	—	—	—		(52,229	)	(22,411	)	(16,716	)	(343,158	)	(231,358	)	(117,594	)	(120,115	)	(106,158	)	(86,553	)	(51,969	)	(50,297	)	(44,688	)	—		—	—	(567,471	)	(410,224	)	(265,551	)
Impairment (losses) reversals recognized in profit or loss	—	—	—		(48,983	)	15,633		(13,637	)	(54,784	)	(75,174	)	(98,646	)	(13,852	)	(3,107	)	(1,991	)	(4,319	)	(5,510	)	(2,054	)	—		—	—	(121,938	)	(68,158	)	(116,328	)
OPERATING INCOME	—	—	—		77,990		150,951		141,424		608,257		342,224		198,365		389,002		411,665		364,258		175,849		174,259		164,406		—		—	—	1,251,098		1,079,099		868,453
FINANCIAL RESULT	—	—			127,247		(176,791	)	(162,045	)	(263,904	)	(250,354	)	(148,927	)	(57,795	)	(55,757	)	(51,858	)	(22,151	)	(24,279	)	(24,404	)	—		—	—	(216,603	)	(507,181	)	(387,234	)
Financial income	—	—	—		33,729		34,724		27,124		173,459		137,208		115,858		11,463		10,271		8,756		4,470		5,031		4,448		—		—	—	223,121		187,234		156,186
Cash and cash equivalents	—	—	—		5,917		18,799		19,204		15,225		3,869		14,305		5,498		5,935		5,903		661		2,982		1,064		—		—	—	27,301		31,585		40,476
Other financial income	—	—	—		27,812		15,925		7,920		158,234		133,339		101,553		5,965		4,336		2,853		3,809		2,049		3,384		—		—	—	195,820		155,649		115,710
Financial costs	—	—	—		(174,402	)	(213,931	)	(187,941	)	(421,956	)	(377,095	)	(271,077	)	(67,561	)	(65,385	)	(60,318	)	(26,543	)	(29,667	)	(29,208	)	—		—	—	(690,462	)	(686,078	)	(548,544	)
Bank borrowings	—	—	—		(133	)	(47	)	(2,123	)	(86,228	)	(62,079	)	(48,772	)	(13,022	)	(15,335	)	(8,258	)	(1,722	)	(6,122	)	1,063		—		—	—	(101,105	)	(83,583	)	(58,090	)
Secured and unsecured obligations	—	—	—				—		—		(72,172	)	(35,259	)	(58,202	)	(37,995	)	(32,353	)	(41,574	)	(24,973	)	(13,651	)	—		—		—	—	(135,140	)	(81,263	)	(99,776	)
Other	—	—	—		(174,269	)	(213,884	)	(185,818	)	(263,556	)	(279,757	)	(164,103	)	(16,544	)	(17,697	)	(10,486	)	152		(9,894	)	(30,271	)	—		—	—	(454,217	)	(521,232	)	(390,678	)
Gains (losses) from indexed assets and liabilities	—	—	—		260,137		—		—				—		—				—		—				—		—		—		—	—	260,137		—		—
Foreign currency exchange differences	—	—	—		7,783		2,416		(1,228	)	(15,407	)	(10,467	)	6,292		(1,697	)	(643	)	(296	)	(78	)	357		356		—		—	—	(9,399	)	(8,337	)	5,124
Positive	—	—	—		16,088		3,560		1,766		148,186		18,721		34,044		5,150		1,115		2,339		1,745		2,141		3,334		—		—	—	171,169		25,537		41,483
Negative	—	—	—		(8,305	)	(1,144	)	(2,994	)	(163,593	)	(29,188	)	(27,752	)	(6,847	)	(1,758	)	(2,635	)	(1,823	)	(1,784	)	(2,978	)	—		—	—	(180,568	)	(33,874	)	(36,359	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	—	—			(160	)	—		—		—		—		—		—		—		1,443		—		—		—		—		—	—	(160	)	—		1,443
Other gains (losses)	—	—	—		—		128		56		386		954		(1,232	)	166		145		(15,071	)	(6	)	1,305		32		—		—	—	546		2,532		(16,215	)
Gain (loss) from other investments	—	—	—				72		56				—		—				—		(13,760	)			—		—		—		—	—	—		72		(13,704	)
Gain (loss) from the sale of assets	—	—	—				56		—		386		954		(1,232	)	166		145		(1,311	)	(6	)	1,305		32		—		—	—	546		2,460		(2,511	)
Income before tax	—	—	—		205,077		(25,712	)	(20,565	)	344,739		92,824		48,206		331,373		356,053		298,772		153,692		151,285		140,034		—		—	—	1,034,881		574,450		466,447
Income tax	—	—	—		(101,101	)	36,981		(10,267	)	251,360		23,851		2,618		(125,242	)	(144,932	)	(134,584	)	(49,024	)	(46,154	)	(48,535	)	—		—	—	(24,007	)	(130,254	)	(190,768	)
Net income from continuing operations	—	—	—		103,976		11,269		(30,832	)	596,099		116,675		50,824		206,131		211,121		164,188		104,668		105,131		91,499		—		—	—	1,010,874		444,196		275,679
Income from discontinued operations	—	—	—		—		—		—		—		—		—		—		—		—		—		—		—					—	—		—		—
NET INCOME	—	—	—		103,976		11,269		(30,832	)	596,099		116,675		50,824		206,131		211,121		164,188		104,668		105,131		91,499		—		—	—	1,010,874		444,196		275,679
	Chile				Argentina						Brazil						Colombia						Peru						Eliminations				Total
Line of Business	12-31-2018 ThUS$	12-31-2017 ThUS$	12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$		12-31-2018 ThUS$		12-31-2017 ThUS$	12-31-2016 ThUS$	12-31-2018 ThUS$		12-31-2017 ThUS$		12-31-2016 ThUS$
STATEMENT OF CASH FLOWS
Net cash flows from (used in) operating activities	—	—	5,895		47,301		69,724		264,533		154,589		186,215		572,727		404,403		386,853		353,771		165,498		141,431		175,728		—		—	—	771,791		784,223		1,372,654
Net cash flows from (used in) investing activities	—	—	(3,018	)	(82,268	)	(102,586	)	(123,187	)	(533,164	)	(667,942	)	(367,158	)	(296,082	)	(262,574	)	(207,825	)	(111,035	)	(89,334	)	(99,451	)	—		—	—	(1,022,549	)	(1,122,436	)	(800,639	)
Net cash flows from (used in) financing activities	—	—	(45,945	)	(118	)	(48	)	(782	)	551,548		576,686		(149,062	)	(79,475	)	(161,966	)	(70,396	)	(104,032	)	(52,807	)	(30,516	)	—		—	—	367,923		361,865		(296,701	)

The Eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-183

36.THIRD PARTY GUARANTEES, CONTINGENT ASSETS, LIABILITIES, AND OTHER COMMITMENTS

36.1Direct guarantees

				Assets Committed
	Debtor					Carrying	Outstanding balance as of			Guarantees released
Creditor of Guarantee	Company	Relationship	Type of Guarantee	Type	Currency	Amount	Currency	12-31-2018	12-31-2017	2018	Assets	2019	Assets	2020	Assets
Mitsubishi Corporation	Enel Generación Costanera	Creditor	Pledge	Combined cycle plant	ThUS$	7,692	ThUS$	54,460	53,161	—	—	—	—	—	—
Various Creditors	Enel Distribución Río S.A. (ex Ampla S.A.)	Creditor	Pledge on collection and others	Collection accounts	ThUS$	18,961	ThUS$	225,471	105,335	—	—	—	—	—	—
Various Creditors	Enel Distribución Ceará S.A. (ex Coelce S.A.)	Creditor	Pledge on collection and others	Collection accounts	ThUS$	19,378	ThUS$	126,674	106,854	—	—	—	—	—	—
Banco Nacional de Desarrollo Económico y Social	Enel Cien	Creditor	Mortgage, pledge and others	Collection accounts	ThUS$	—	ThUS$	—	4,074	—	—	—	—	—	—
Various Creditors	CELG Distribución S.A.	Creditor	Pledge on collection and others	Collection accounts	ThUS$	24,783	ThUS$	101,507	154,954	—	—	—	—	—	—
Various Creditors	Enel Distribucion Sao Paulo	Creditor	Pledge on collection and others	Collection accounts	ThUS$	9,286	ThUS$	828,266	—
Banco Crédito del Perú	Enel Generacion Piura	Creditor	Mortgage	Collection accounts	ThUS$	18,371	ThUS$	37,824	48,443

As of December 31, 2018 and 2017, the carrying amount of property, plant and equipment pledged as security for liabilities is ThUS$7,692 and ThUS$26,156, respectively (see Note 19.e.ii). Enel Américas is joint and several co-signer of the local bonds of Enel Generación Chile, whose outstanding balance as of December 31, 2018 amounts to ThCh$329,260,529 (ThUS$474,439).

As of December 31, 2018, the Company had future energy purchase commitments amounting to ThUS$108,423,549 (ThUS$84,423,377 as of December 31, 2017).

F-184

36.2Indirect guarantees

				Debtor			Outstanding balance as of
Type	Contract	Maturity	Creditor of Guarantee	Company	Relationship	Type of Guarantee	Currency	12-31-2018	12-31-2017
Secured	Bonds Serie H	October  2028	Bondholders of Endesa Chile’s Bonds	Enel Generación Chile S.A.	Entities demerged from original debtor Endesa Chile (codebtor Endesa Américas and after merger Enel Américas) (1)	Codebtor	ThUS$	78,925	96,857
Secured	Bonds Serie M	December  2029	Bondholders of Endesa Chile’s Bonds	Enel Generación Chile S.A.	Entities demerged from original debtor Endesa Chile (codebtor Endesa Américas and after merger Enel Américas) (1)	Codebtor	ThUS$	394,987	431,524
Secured	DEBÊNTURES 9ª EMISSÃO (AMPL19)	December 2020	DEBENTURES	Enel Distribución Río	Enel Brasil	Codebtor	ThUS$	155,237	—
Secured	CITIBANK 4131 II	March 2021	CITIBANK	Enel Distribución Río	Enel Brasil	Codebtor	ThUS$	97,276	—
Secured	CITIBANK 4131 III	June 2019	CITIBANK	Enel Distribución Río	Enel Brasil	Codebtor	ThUS$	37,159	—
Secured	ITAÚ 4131	July 2021	ITAÚ	Enel Distribución Río	Enel Brasil	Codebtor	ThUS$	77,203	—
Secured	CITI 4131 FORTALEZA	April 2020	CITIBANK	Enel Generación Fortaleza	Enel Brasil	Codebtor	ThUS$	60,974	—
Secured	ITAÚ 4131 CELG - I	July 2020	ITAÚ BBA INTERNATIONAL PLC	Enel Distribución Goias (ex-CELG)	Enel Brasil	Codebtor	ThUS$	77,143	—
Secured	ITAÚ 4131 CELG - II	August 2020	ITAÚ BBA INTERNATIONAL PLC	Enel Distribución Goias (ex-CELG)	Enel Brasil	Codebtor	ThUS$	96,524	—
Secured	ITAÚ 4131 CELG - IV	February 2021	ITAÚ BBA INTERNATIONAL PLC	Enel Distribución Goias (ex-CELG)	Enel Brasil	Codebtor	ThUS$	31,011	—
Secured	ITAÚ 4131 CELG - V	January 2020	ITAÚ BBA INTERNATIONAL PLC	Enel Distribución Goias (ex-CELG)	Enel Brasil	Codebtor	ThUS$	41,264	—
Secured	NP 1ª Emissão	October 2019	ITAÚ UNIBANCO S.A.	Enel Distribución Goias (ex-CELG)	Enel Brasil	Codebtor	ThUS$	54,145	—
Secured	BNDES_FINAME_GIRO	May  2023	BNDES	Enel Distribución Goias (ex-CELG)	Enel Brasil	Codebtor	ThUS$	26,058	—
Secured	BNP PARIBAS 4131	November 2019	BNP PARIBAS- CREDIT AGREEMENT	Volta Grande	Enel Brasil	Codebtor	ThUS$	267,302	—
Secured	DEBÊNTURES - 23ª EMISSÃO - 1ª serie	September 2021	DEBENTURES	Enel Distribución Sao Paulo	Enel Brasil	Codebtor	ThUS$	185,268	—
Secured	DEBÊNTURES - 23ª EMISSÃO - 2ª série	September 2023	DEBENTURES	Enel Distribución Sao Paulo	Enel Brasil	Codebtor	ThUS$	367,520	—
Secured	DEBÊNTURES - 23ª EMISSÃO - 3ª serie	September 2025	DEBENTURES	Enel Distribución Sao Paulo	Enel Brasil	Codebtor	ThUS$	237,325	—
						Total		2,285,321	528,381

(1)Upon the demerger of the original issuer, Endesa Chile (currently Enel Generación Chile S.A.), and in accordance with the bond indenture, all entities arising from the demerger (i.e., Endesa Américas) are liable for the debt, regardless that the payment obligation remains in Enel Generación Chile S.A. After the Merger, the Company became liable for the obligations of Endesa Américas.

F-185

36.3Lawsuits and Arbitration Proceedings

As of the date of these consolidated financial statements, the most relevant litigation and arbitrations involving the Company and its subsidiaries and affiliates are as follows:

a)Enel Américas lawsuits pending

The Chilean Internal Revenue Service (SII) carried out a regular audit for the 2012 business year (AT 2013). On September 4, 2015, it provided notice of a tax assessment for the additional tax due, based on Section 74 of the Income Tax Act, justifying its position on the ground that a modification of the Retained Taxable Earnings Registry (FUT) allegedly entailed a modification of the base for the additional tax. The company pointed out 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), alleging that the tax obligation had been fully complied with, since the additional tax had been paid provisionally on a monthly basis.  As a result, the tax obligation had been fully settled and paid when the income rectification was made on May 8, 2014, which included the rectification of the FUT amount. An unfavorable ruling was rendered and the company filed an appeal in January 2018. The case was pleaded before the Court of Appeal on September 12, 2018 and the decision on the appeal was unfavorable, with the dissenting vote of one judge. On November 15, 2018, the company filed a plea of cassation on the merits, which was declared admissible by the Court of Appeal and is pending before the Supreme Court.  As of December 31, 2018, the amount involved in this lawsuit was Ch$6,495,277,499 (ThUS$9,359).

b)Subsidiary lawsuits pending:

Argentina:

1. -   Edesur S.A. filed an administrative claim against the Argentine Ministry of Energy (now the Secretary of Energy) for damages arising from the breach of the Concession Contract from November 1, 2005 to January 31, 2017. The damage to be indemnified arises from the non-fulfilment on the part of the National Government, in its capacity as grantor of the public electricity distribution service concession, of the obligations set out in the Public Service Concession Contract for the Distribution and Marketing of Electrical Energy concluded with Edesur which was granted pursuant to Decree No. 714/1992, in accordance with the terms resulting from the Agreement for the Adaptation of the Public Service Concession Contract for the Distribution and Marketing of Electrical Energy concluded on February 15, 2006, ratified by Decree No. 1959/2006 (the “Agreement Act”). The damages claimed arise from the breach of: (i) the obligation to transfer to the tariff the “actual variations” of the distributor’s costs, or, failing this, to recognize in the distributor’s favor income equivalent to what would have resulted from the transfer to the tariff of such actual higher costs, from the signature of the Agreement Act until the entry into force of Resolution No. 64/2017 of the Argentine National Regulatory Authority for Energy (ENRE). The administrative procedure started on July 31, 2018, and is now being analyzed by the Administration. As of December 31, 2018, the amount involved in the lawsuit was Ar$48,114,773,121 (US$1,277,337,463). Considering that it is an administrative claim filed by Edesur against the Administration, no allowances were established.

Colombia:

2. -   Jose Rodrigo Alvarez and approximately 1,400 other individuals -all of them residents of the municipality of Garzón filed a class-action lawsuit in 2013, currently pending in the Fourth Civil Court of the Bogotá Circuit, against Emgesa S.A. ESP (formerly known as Central Betania). It is claimed that, as a consequence of the construction of El Quimbo hydroelectric project, their income from artisan or business activities was reduced by an average of 30% without this having been taken into account when the project’s socio-economic study was carried out. The amount of the claim is US$7,597,595, equivalent to CP$24,673,189,693. No provision has been made for the case. The case has been in the evidentiary stage since 2016 and no expert opinion has been issued due to the counterparty’s lack of activity. This case has been reported since 2014 in the Notes to the Company’s Financial Statements and its Annual Report.

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3. -   Emgesa filed an action for annulment and restoration of rights against the Colombian National Tax and Customs Department (DIAN) before the Administrative Court of Huila. Emgesa enjoyed a corporate income tax benefit, known as the “Páez Law”, which provided a tax relief for companies located in a specific area that suffered a natural disaster. DIAN opposed the method used by Emgesa to determine the basis for the income tax using this benefit. DIAN argues that some of the Emgesa’s revenues, such as inflation adjustments and non-operating income, do not qualify for this exemption, as they are not related to electricity generation activity. Emgesa’s position is substantiated on the fact that, under the law, this special benefit applies to the company as an entity and not just to certain company revenues. On July 27, 2017, the Administrative Court of Huila issued the decision endorsing the arguments of the DIAN, considering that there is no benefit on this income since it does not come from the normal development of the company’s corporate objectives. The court’s decision did not set any substantial legal basis, nor did it rely on the several defense arguments submitted by the company. The Administrative Court also confirmed the penalty for inaccuracy without analyzing the difference in criteria or defining the sanctionable act. Emgesa appealed on August 10, 2017, reiterating that the benefit had accrued to the company and the law does not differentiate between its applications when it comes to non-operating income. New rulings by the Council of State supporting the company’s position were presented. It was emphasized there was a difference of opinion and therefore the penalty for inaccuracy must be lifted. On September 22, 2017, the proceedings were assigned to the Council of State where the matter will be reviewed by the court of second instance. Emgesa’s lawyers presented closing arguments on November 24, 2017 and in January 2018 the docket was taken under submission for the final decision. The total value of this lawsuit is estimated at CP$117,113million (ThUS$36,063).

4. -   Emgesa brought an action for annulment and restoration of rights against the Corporación Autónoma Regional de Cundinamarca (CAR). By means of Resolutions Nos. 506 of March 28, 2005, and 1189 of July 8, 2005, CAR ordered Emgesa, Empresa de Energía de Bogotá S.A. (EEB) and Empresa de Acueducto y Alcantarillado de Bogotá S.A. (EAAB) to execute construction of works at the El Muña dam reservoir. Emgesa filed a lawsuit against those decisions seeking their annulment in the Administrative Court of Cundinamarca. First instance court dismissed the annulment of these decisions. Appeals were filed by Emgesa, EEB and EAAB, which are currently pending. There is a parallel annulment and restoration action initiated by Emgesa against CAR. This action seeks the annulment of Article 2 of Resolution No. 1318 of 2007 and Article 2 of Resolution No. 2000 of 2009, through which Emgesa was ordered to implement a “Contingency Plan’ and to carry out an “Air Quality” study for the possible suspension of water pumping from the reservoir. The annulment of the above-mentioned administrative acts is being sought due to the technical impossibility of carrying out the “Air Quality” study and implementing the “Contingency Plan”. In this parallel action, an expert opinion favorable to the company from an accountant was presented. Emgesa requested clarification concerning this opinion, which was also favorable. The Administrative Court has appointed a second expert, who has accepted the position. The issuance of the second expert opinion is pending. The amount involved in this lawsuit is indeterminate.

5. -   A class action lawsuit filed against Emgesa, the Colombian Ministry of Environment and Development and the Colombian Ministry of Mines and Energy, Comepez S.A. and other fishing companies, is currently under review by the Huila Administrative Court. Artisanal fishermen are seeking the protection of collective rights and a healthy environment, public health, food security and safety and  the prevention of technically foreseeable disasters. Furthermore, the plaintiffs are seeking the issuance of an order compelling the entities to immediately take the necessary corrective and preventive measures to put an end to 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 judicial monetary amount because of its nature as an action regarding the protection of collective rights. Therefore, no provision has been made. The matter has been pending decision since June 18, 2018. During the evidentiary stage, the environmental authorities ANLA and CAM jointly presented a report in which they stated that the company had complied with the obligations imposed by the Administrative Court within its precautionary measures. Although the value of this lawsuit is indeterminate, it is being reported as it generates a risk for the power plant’s operation and because the precautionary measure prevented the filling of the El Quimbo reservoir at the time, a measure that was modified but has not yet been entirely lifted although the power plant is in operation today.

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6.-   In a class-action lawsuit filed by several residential complexes -including Centro Medico de la Sabana- against Codensa S.A. ESP, the plaintiffs are demanding the refund of an alleged tariff cost excess that they were charged. The lawsuit is based on the concept of a tariff benefit to which the plaintiff argue they are entitled as Voltage Level One users and as infrastructure owners -as established in Resolution No. 082 of 2002, modified by Resolution No. 097 of 2008. Codensa responded to the complaint by rejecting it in its entirety. A conciliation hearing was held between the parties, without success. An evidence order was issued on May 15, 2018 and the joinder of new plaintiffs was denied. The proceedings are in the evidentiary stage, and the estimated value of this lawsuit is approximately CP$337,000 million (ThUS$103,772). This class action is being heard by the First Administrative Court of the Bogotá Capital District.

7.-   Henry Andrew Barbosa filed a class-action lawsuit against Codensa and the Special Public Services Administrative Unit (UAESP) of the Bogotá Capital District before the Tenth Administrative Judge of Bogotá. Subsequently, Codensa filed an action for nullification and restoration of rights against the UAESP, currently pending before the Cundinamarca Administrative Court. The judge’s ruling in the class action, ordered Codensa and the UAESP to re-assess the 1997 Public Lighting Agreement between them, since it was determined that there were 8,661 fewer lights than Codensa had actually taken into account in its billing. In 2014, the parties agreed to the reassessment and carried out a transaction for the periods 1998 to 2004, leaving a debt of CP$14,433 million (ThUS$4,924) owed by Codensa 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 should pay CP$113,082 million (ThUS$38,584). The action for nullification and restoration of rights filed against the UAESP is in the notification stage. The UAESP commenced compulsory collection, but the collection was suspended with the lawsuit’s admission. Codensa made a payment of CP$24,400 million (ThUS$8,068), which is what it determined is payable under the 2014 agreements. Finally, the nullification action has an approximate value of CP$88,698 million (ThUS$27,313).

8.-   On December 4, 2017, Grupo Energía de Bogotá (GEB) notified Enel Américas of its intention to submit to arbitration the dispute between the parties regarding the distribution of the profits of the 2016 fiscal year for Emgesa and Codensa in accordance with the provisions of the Investment Framework Agreement (AMI). GEB claims that Enel Américas is acting contrary to its own previous conduct by voting for a 70% distribution of profits, under the allegedly incorrect interpretation that this proportion corresponds to “all available profits in accordance with good commercial practice.” Furthermore, GEB claims that Enel Américas’ conduct violates the provisions of Clause 3.8 of the AMI, which regulates the form of distribution of profits by obliging the parties to vote in favor of the distribution of all (100%) profits that may be distributed during each fiscal year. The claims seek a declaration of Enel Américas’ breach of the AMI and the consequent distribution of 100% of the profits of the 2016 fiscal year for each company. Regarding this litigation, the amount of CP$63,619,000,000 (about ThUS$ 19,590) is disputed for Codensa, corresponding to the distributions not received as consequence of the partial distribution of profits. For Emgesa, the amount of CP$82,820,000,000 (about ThUS$ 25,503) corresponds to the amount of distributions not received as consequence of the partial distribution of profits. Once the date for the appointment of the arbitration panel was set, GEB decided to withdraw the claims to make amendments and to include new issues, forcing a joinder with 17 other applications for arbitration proceedings that were ongoing (described below). The new lawsuit was notified to Enel Américas at the formal installation hearing of the Arbitration Court held on April 10, 2019, with the deadline to answer pending. The amounts and concepts demanded correspond to the following: i) The amount of ThCP$182,360,273 (ThUS$56,154) for the net market value not paid to Emgesa for assets and information relevant to the development, operating, administration and maintenance of non-conventional renewable energies, ii) The amount of ThCP$384,011,000 (ThUS$118,248), for the damages suffered by GEB as a result of the updated value as of August 31, 2018 of the ordinary dividend not received by GEB on the profits of Emgesa and Codensa for the years 2016 and 2017, iii) Others for an amount of ThCP$8,089,000 (ThUS$2,491) for the damages suffered by GEB for the expected values not received and additional unexpected costs incurred as a result of the value of the ordinary dividends not received by GEB over the income of Emgesa and Codensa for the years 2016 and 2017.

9.-   Twenty-four applications for arbitration proceedings were filed by Grupo Energía de Bogotá - against Codensa and Emgesa, seeking the nullification of the Minutes of the Board of Directors and the Shareholders’ General Meeting.

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These applications present the following arguments: i) Conflicts of Interest with economically-affiliated companies; ii) Impossibility of ratification of authorizations to contract; iii) Undue waiver of the conflict of interest; and iv) Violation of the AMI in terms of distribution of profits.

The claims are similar for each application, and the principal argument alleges that the decisions are flawed as they contravene public policy. The applications seek the declaration that the decisions are null and void due to their presumed unlawful object and reason, the breach of AMI provisions regarding the profits distribution and some minutes that were adopted while the arbitration was pending. However, the litigation amount is indeterminate. Nevertheless, the case involves high impact decisions made concerning financial transactions with affiliated companies. As there was no agreement regarding the appointment of arbitrators to consolidate the arbitrations against Enel Américas, the selection of arbitrators took place on July 5, 2018. The procedure is at the stage of appointing arbitrators and disclosures of arbitrators and parties.

Perú:

10.-   The Peruvian National Customs and Tax Authority (SUNAT) challenged Enel Generación Perú S.A.A. (formerly known as Edegel S.A.A.), through Notices of Assessments and Penalties, about the deduction as an expense of the depreciation corresponding to part of the highest book value assigned to the assets in the appraisal carried out as a result of their voluntary revaluation in 1996. The rejected value of the appraisal relates to financial interest paid during the construction stage of the power generation plants. SUNAT’s position is that Enel Generación Perú has neither reliably demonstrated that it was necessary to obtain financing in order to build the generation plants that were revalued, nor that such financing had actually been incurred. Enel Generación Perú’s position is that SUNAT cannot demand such proof, since the appraisal is intended to assign to the asset the market value appropriate to it at the time the appraisal is conducted, and not its historical value. In this case, the appraisal methodology took into consideration the fact that power plants of such magnitude are built with financing. If SUNAT did not agree with the valuation, it should have presented its own appraisal, which it did not do.

Concerning the year 1999: In February 2012, the Tax Court (“TF”) resolved the lawsuit regarding the 1999 tax year in favor of Enel Generación Perú with regard to two plants and against it with respect to four plants, reasoning that only the first two were proven to have been financed. Enel Generación Perú paid the taxes reassessed by SUNAT in June 2012, amounting to PS$37,710 million (ThUS$11,160), which will have to be refunded if a favorable outcome is obtained in the complaint filed with the judicial courts (“PJ”) against the TF’s decision, filed in May 2012 against SUNAT and the TF.

In March 2018, Enel Generación Perú received the appeals court’s decision declaring the PJ’s decision null and void and ordering the rendering of a determination on the claim. The file was referred to the PJ in June 2018 and the oral report was submitted in August 2018. In September 2018, Enel Generación Perú submitted its written arguments to assist the PJ in rendering a decision.

Concerning the years 2000 and 2001: The reasoning adopted for 1999 tax year was applied to the 2000 and 2001 periods and Enel Generación Perú paid PS$18,786 million (ThUS$5,558).

Judicial case: In March 2018, the PJ rendered a decision declaring the lawsuit groundless, and ruled in favor of Enel Generación Perú with respect to the non-application of interest on the advances from March to December 2001. In the same month, Enel Generación Perú appealed the unfavorable portion. In October 2018, the Attorney General’s Office issued a tax ruling holding that it is inclined to uphold the ruling handed down at the trial court. In December 2018, the oral report was submitted and several briefs were filed to assist the PJ in issuing its decision. In December 2018, the PJ issued a ruling to vacate the trial court decision, ordering that the trial court issue a new decision taking account of the arguments set out in its ruling.

Administrative case: In August 2017, Enel Generación Perú was served with the Compliance Order, which was issued taking into consideration the TF’s ruling for the 1999 fiscal year, by means of which SUNAT reassessed the tax due for the period 2000-2001. According to SUNAT, Enel Generación Perú’s updated tax due amounted to PS$ 220

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million, because of the annual corporate tax for 2000, a related fine, and payments on account for the 2001 fiscal year. Also, the discounted credits in the company’s favor amounted to PS$ 22 million, for the 2001 corporate tax. In September 2017, Enel Generación Perú was served with a decision in which SUNAT corrected the Compliance Order of August 2017, stating that it had applied an incorrect restatement factor to the assessed tax, which resulted in the tax assessed by SUNAT amounting to PS$ 190 million, and not PS$ 220 million. In September 2017, Enel Generación Perú appealed the above-mentioned Compliance Order. Enel Generación Perú presented written arguments in July 2018.

Next steps are:

For the year 1999:

·Enel Generación Perú is awaiting  the trial court’s issuance  of  a resolution (ruling) on Enel Generación Perú´s lawsuit.

For the years 2000-2001:

·Enel Generación Perú is awaiting  the TF’s issuance of  the corresponding resolution and for the trial court to rule on Enel Generación Perú’s lawsuit.

The total amount involved in these lawsuits is estimated at PS$75,333 million (ThUS$22,288).

11.-  SUNAT disallowed recognition by Enel Distribución Perú of the commercial energy losses recognized by the company between 2006 and 2011, equivalent to approximately 2% of the total purchased and self-generated energy. SUNAT challenged the cost of sale of that energy determined by Enel Distribución Perú, on the basis of an energy theft crime that was not established by the courts of law. SUNAT’s position is that the infeasibility of a legal action can only be demonstrated through a police report and a Resolution issued by the Attorney General (Public Prosecutor’s Office) declaring, on a definitive or provisional basis, the filing of the criminal action for energy theft. The TF has rendered some decisions stating that such a decision is necessary. Enel Distribución Perú’s position is that since the law does not establish a specific mechanism on how the infeasibility of a legal action will be demonstrated, it is possible to present any available, appropriate and reasonable evidence for this situation (free review of evidence). Enel Distribución Perú chose to demonstrate that it was futile to prosecute these crimes through legal actions, presenting reports produced by specialized engineers, reports issued by the General Directorate of Electricity (DGE) of the Ministry of Energy and the Mines and by the Energy and Mining Investment Supervisor Authority (OSINERGMIN), the Peruvian electricity regulatory authority, demonstrating that there was no sense to go to the courts and prosecute a crime that would be useless because the perpetrators of the crime, the exact occurrence of theft, the specific place where it occurs and the amount stolen at each opportunity could not be identified. The TF has allowed this type of proof in case of theft in the distribution of water (an industry similar to the distribution of electricity) and has not indicated that a decision issued by the Attorney General (Public Prosecutor’s Office) is the only admissible evidence demonstrating the futility of pursuing legal action in this case.

The proceedings have progressed as follows:

For the year 2006: The TF ruled against Enel Distribución Perú in the appeal, although it agreed with Enel Distribución Perú’s position on the merits of the disputed issue. Therefore, the TF upheld the defense after holding that Enel Distribución Perú did not demonstrate the amount of commercial losses attributable to theft. This finding stems from the fact that commercial energy loss is not exclusively composed of stolen energy, but also of energy lost due to other reasons, such as measurement errors, billing errors and errors in estimating physical losses. Due to the immediate enforceability of the TF judgment, Enel Distribución Perú paid the tax due in full to SUNAT amounting to a total of PS$14,517 million (US$4,296 million). Following a decision partially in favor of Enel Distribución Perú, in January 2017, both SUNAT and Enel Distribución Perú filed extraordinary appeals with the Supreme Court of Justice. In January 2018, Enel Distribución Perú was served with the decision dismissing its extraordinary appeal and upholding SUNAT’s extraordinary appeal. In June 2018, Enel Distribución Perú was served with the decision of the Supreme Attorney General’s Office (Public Prosecutor’s Office) stating that the extraordinary appeal filed by SUNAT

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should be declared unfounded. In September 2018, Enel Distribución Perú submitted an oral report and presented written closing arguments.

For the years 2007 and 2008: Taking into account the result obtained in connection with the 2006 tax year, Enel Distribución Perú initiated a new defense strategy: (i) in theory, commercial energy losses may be composed of errors of measurement, billing and estimation of physical losses; (ii) since such losses are determined by “subtraction” (the energy that entered the system “minus” the energy supplied to customers and “minus” the physical loss of energy), commercial energy loss may actually be composed of such errors only in cases of under-measurement or under-invoicing or underestimation of physical losses; (iii) if there are no such errors, the amount shown as commercial energy loss is composed only of losses from theft, (iv) during the inspection, SUNAT reviewed both the billing and the physical loss report and neither challenged nor investigated them; therefore, in this respect, SUNAT cannot raise billing errors or errors in estimating physical losses as part of the commercial energy loss, (v) with respect to measurement errors, the margins for this type of errors are minimal as a business’ electrical energy distribution is regulated.

For the year 2007: Enel Distribución Perú presented evidence that a small amount of loss was attributable to under-measurement. At that time, commercial energy losses consisted mainly of theft (95%) and, to a lesser extent (5%), measurement errors. Enel Distribución Perú presented an oral report and pleadings.

For the year 2008: Enel Distribución Perú presented evidence that demonstrated an excess of measurement. Therefore, commercial energy losses were only theft. Enel Distribución Perú provided an oral report to the TF and presented the final written arguments.

For the year 2009: SUNAT objected to the deduction of commercial energy losses, for the same reasons as in previous years. In November 2013, Enel Distribución Perú filed a claim in which, in addition to reiterating the reasons why the commercial loss of energy is deductible, it provided evidence that demonstrated that the loss of commercial energy consisted mainly of theft (93%) and, to a lesser extent (7%) of measurement errors.  In June 2014, SUNAT requested information on the details of the calculation of the “standard energy loss”. In July 2014, Enel Distribución Perú responded to the points requested by SUNAT. In August 2014, SUNAT served Enel Distribución Perú with the decision ruling on the latter’s claim. In that decision, SUNAT set aside the objection related to the standard loss of commercial energy, confirming the excess attributable to such amount. In September 2014, Enel Distribución Perú paid the debt it owed to SUNAT amounting to PS$5,274 million (ThUS$1,560), this amount includes default interest for payments on account and fines. It filed an appeal with the TF.

For the year 2010: SUNAT only objected to the deduction of commercial energy losses corresponding to the excess of the standard commercial energy loss. In July 2015, Enel Distribución Perú paid the debt owed to SUNAT amounting to PS$5,085 million (ThUS$1,505) including taxes, interest on late payments and fines. A claim was filed with SUNAT. In April 2016, Enel Distribución Perú was notified of SUNAT’s decision, which upheld the objections, and an appeal was filed that same month.

For the year 2011: SUNAT also objected to the deduction of commercial energy losses corresponding to the excess of the standard commercial energy loss. In July 2016, Enel Distribución Perú paid the debt owed to SUNAT amounting to PS$3,126 million (ThUS$925) by way of payment on accounts and fines with the respective default interest. In September 2016, Enel Distribución Perú was served with tax assessments and fines. In October 2016, Enel Distribución Perú filed a claim for taxes and fines. In June 2017, Enel Distribución Perú received a decision through which SUNAT maintained the objections raised. In July 2017, Enel Distribución Perú filed an appeal.

Next steps are:

For the year 2006, Enel Distribución Perú is awaiting the Supreme Court ruling on SUNAT´s extraordinary appeal (cassation).

For the years 2007, 2008, 2009, 2010 and 2011, the TF’s issuance of the corresponding decisions are pending.

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The total amount involved in these lawsuits is estimated at PS$76,753 million (approximately ThUS$22,715), of which PS$16,826 million (ThUS$4,980) have been provisioned.

12.- In 1997, Enel Generación Perú, Perené and Simsa entered into a joint venture agreement for the development of the Chimay and Yanango power plants, agreeing to a payment of US$13 million for Enel Generación Perú. In 1998, Enel Generación Perú signed a contract with its parent company, Generandes (now Enel Perú, after the merger with Generandes), for Enel Perú to provide supervision services for the power plants’ construction, agreeing  to a payment of US$13 million for Enel Perú. In turn, Enel Perú entered into contracts with its shareholders, Entergy Perú and Conosur, transferring its commitments with Enel Generación Perú and agreeing to a payment of US$3 million for each party. SUNAT challenged this transaction (i) of Enel Generación Perú for the use of VAT as a tax credit that was surcharged by Enel Perú, and (ii) of  Enel Perú for treating the expense as deductible from the company’s income tax and for the use of VAT as a tax credit that was surcharged by its shareholders. SUNAT’s position is that the transactions are not valid because Enel Perú and its shareholders are holding companies that have no personnel to provide such services. The supervision services were provided directly by Enel Generación Perú through its personnel. The TF has endorsed SUNAT’s position in the Enel Generación Perú case and Enel Perú case. With this in mind, Enel Perú hopes that the PJ will order a new decision be issued, indicating that not only do the costs not exist, but that there is no income either. According to this expected new determination, there would be a payment due in excess of Enel Perú’s income tax paid, and this excess would be offset with VAT, eliminating the contingency for this case.

These proceedings have progressed as follows:

Following an adverse decision in the administrative process, Enel Perú paid SUNAT the tax due of PS$87,055 million (ThUS$26,500) and filed a lawsuit against SUNAT and the TF.  In September 2018, the Prosecutor’s Opinion was issued indicating that Enel Perú’s claim should be declared unfounded, and this was notified to the parties for rebuttals. In October 2018, the oral report was delivered in the absence of the SUNAT representatives.  The total sum at stake in this lawsuit is estimated at PS$87,055 million (ThUS$26,500 as of December 31, 2018) which was already paid to SUNAT and a ruling is still pending.

13.- On July 5, 2016, Electroperú filed a request for arbitration against Enel Generación Perú due to disagreements regarding the interpretation of certain technical aspects (committed power, start date of the contract’s second stage, determination of the Base Gas Price) of an electric power supply contract entered into in 2003. The total amount of this arbitration is estimated at approximately PS$41.2 million (ThUS$12,189). At the same time, the dispute stems from claims by Enel Generación Perú against Electroperú for approximately US$18.5 million. plus interest. Electroperú filed its claim on June 4, 2017 and Enel Generación Perú filed its answer to the claim and its counterclaim on August 4, 2017. On August 10, 2017, the arbitration court notified Enel Generación Perú on its calculation of arbitration expenses. On September 18, 2017, Electroperú filed its response to the answer to the claim and counterclaim that had been filed by Enel Generación Perú. On October 3, 2017, Electroperú filed its answer to the counterclaim that had been filed by Enel Generación Perú. On November 2, 2017, Enel Generación Perú filed its rejoinder to the response that had been filed by Electroperú. On November 17, 2017, Enel Generación Perú acknowledged proper service of the answer to the counterclaim filed by Electroperú. On January 2, 2018, Enel Generación Perú filed its rejoinder to the allegations made by Electroperú.  Arbitration hearings were held on July 23, 24 and 25, 2018.  On August 24, 2018, the parties filed their closing arguments and the arbitration process is awaiting decision on the part of the arbitration panel.

Brazil:

Enel Distribución Ceará (Companhia Energética do Ceará S.A., or “Coelce”)

14.- The Public Prosecutor’s Office filed a public civil action against Enel Distribución Ceará affirming that the transfer of the costs of the Social Integration Program (PIS) and Contribution for Social Security Financing (COFINS) tax collection to consumers through the tariff is illegal, and that the collection should be suspended. It also demanded the return of the sums unduly charged by the concessionaire during the prior 5 years. There is no interim decision. On

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January 10, 2018, the case was transferred to the federal courts and no first instance decision has been rendered yet. As of December 31, 2018 the amount involved in this lawsuit was R$1,029.96 million (US$265,742,748).

15.- The Instituto Brasiliero de Defesa do Consumidor (IPEDC), a Brazilian consumer protection group, filed a public civil action against Enel Distribución Ceará in Ceará state court asserting that the inclusion of energy theft costs reflected by distributors in the tariff is illegal. It is seeking the exclusion of this tariff component and the return of the sums unduly collected by the concessionaire. There is no interim decision and no first instance decision from the Ceará state court. The judge ruled that the case be transferred to the federal courts, considering the interest ANEEL has in this case.  As of December 31, 2018 the amount involved in this lawsuit was R$602 million (US$155,362,857).

16.- The Public Prosecutor’s Office has filed a public civil action against Enel Distribución Ceará, Enel Generación Fortaleza and ANEEL (the Brazilian Electricity Regulatory Agency) alleging that a) the electric power purchase agreement (PPA) signed between Enel Distribución Ceará and Enel Generación Fortaleza (companies of the same economic group) is illegal, the price of the contracted energy being very high, with excessive costs in the final consumers’ tariff, b) the tariff review conducted by ANEEL since 2002 is wrong, since it took into consideration inaccurate data in the process. It 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 to be erroneous at these instances. A special appeal filed by Enel Distribución Ceará is currently pending before the Superior Court of Justice. The amount involved in this lawsuit cannot be estimated.

17.- The Public Prosecutor’s Office for Labor Matters filed a public civil action against Enel Distribución Ceará 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 trial by the Collective Bargaining Section (reviewing instance in the Superior Labor Court). The amount involved in this lawsuit cannot be estimated.

18.- 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. In spite of Enel Distribución Ceará regularly paying 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 substituted by Enel Distribución Ceará throughout the more than 30 years of these lease contracts.

·Cooperativa de Eletrificação Rural do Vale do Acaraú (COPERVA): There is no interim decision and there is still no first instance decision from the Ceará state court.

·Cooperativa de Eletrificação Rural do Vale do Acaraú (COPERVA): 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 Supreme Court 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 plea. Enel Distribución Ceará filed a plea against this decision on December 3, 2018 with the Supreme Court in order that an en-banc decision be rendered (since the ruling had been issued by a single judge), which plea has yet to be docketed. As of December 31, 2018, the amount involved in these two lawsuits was R$234.23 million (ThUS$60,434).

·Cooperativa de Energia, Telefonia e Desenvolvimento Rural (COERCE): There is no interim decision and there is still no first instance decision from the Ceará state court. As of December 31, 2018, the amount involved in this lawsuit was R$140.5 million (ThUS$36,252).

·Cooperativa de Energia, Telefonia e Desenvolvimento Rural (COPERCA): There is no interim decision and there is still no first instance decision from the Ceará state court. As of December 31, 2018, the amount involved in this lawsuit was R$122 million (ThUS$31,490).

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19.- 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. It is seeking the declaration of adjustment’s illegality and an order that its effects be reflected in all subsequent readjustments and the return of inappropriately collected amounts. The Court of Justice (court of second instance) rendered a decision declaring the readjustment made in 1986 illegal, but it has rejected its reflection in the other readjustments (cascade effect). A special appeal filed by COPERVA is currently pending before the Superior Court of Justice (court of third instance). As of December 31, 2018, the amount involved in this lawsuit was R$87.1 million (ThUS$22,484).

20.- Enel Distribución Ceará must apply the “pro rata” rule to calculate the amount of 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 (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 subsidy). Due to the differences that arose in the interpretation of these laws, Enel Distribución Ceará has a total of 9 lawsuits covering the years 2005 to 2013. The Company continues its defense in the administrative and judicial proceedings. As of December 31, 2018, the total amount involved in these lawsuits was estimated at R$189 million (ThUS$48,904).

21.- The State of Ceará issued assessments to Enel Distribución Ceará for the periods 2003, and from 2004 to 2017, since it considered that the ICMS included in the acquisition of fixed assets had been incorrectly deducted. Enel Distribución Ceará has filed its administrative defenses in all administrative actions and is awaiting final decisions. As of December 31, 2018, the total amount involved in this lawsuit was estimated at R$174 million (ThUS$44,894).

Enel Distribución Goiás S.A. (formerly CELG Distribuição S.A.)

22.- Several municipalities have filed lawsuits against Enel Distribución Goiás claiming that an agreement made between Enel, 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 municipalities by the State of Goiás is illegal. The amounts transferred were used to pay electric bills in arrears. Enel states 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 unanimous decision, which will only be rendered by the Superior Court of Justice (the court of third instance).

As of December 31, 2018, the following lawsuits with amounts involved of US$20 million or more were pending against Enel Distribución Goiás:

·Municipality of Aparecida de Goiânia: As of December 31, 2018, the amount involved in this lawsuit was US$133.6 million (ThR$517.8).

·Municipality of Quirinópolis: As of December 31, 2018, the amount involved in this lawsuit was US$71.8 million (ThR$278.28).

·Municipality of Vicentinópolis: As of December 31, 2018, the amount involved in this lawsuit was US$25.4 million (ThR$98.44).

·Municipality of Mineiros: As of December 31, 2018, the amount involved in this lawsuit was US$39.0 million (ThR$151.15).

·Municipality of Anápolis: As of December 31, 2018, the amount involved in this lawsuit was US$70.3 million (ThR$272.47).

·Municipality of Bela Vista de Goiás: As of December 31, 2018, the amount involved in this lawsuit was US$22.4 million (ThR$86.8).

·Municipality of Goiatuba:  As of December 31, 2018, the amount involved in this lawsuit was US$77.4 million (ThR$299.9).

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·Municipality of Caiapônia:  As of December 31, 2018, the amount involved in this lawsuit was US$23.8 million (ThR$92.2).

·Municipality of Cezarina:  As of December 31, 2018, the amount involved in this lawsuit was US$30.1 million (ThR$116.7).

23.- A group of 21 suppliers have filed a lawsuit against Enel Distribución Goiás claiming that the contracting model (outsourcing) carried out by Enel Distribución Goiás had been ruled illegal by the Labor Courts and that they suffered damages which should be compensated. The Court of Justice (court of second instance) ruled in the suppliers’ favor. A special appeal filed by Enel Distribución Goiás is currently pending before the Superior Court of Justice (court of third instance). As of December 31, 2018, the amount involved in this lawsuit was R$117.7 million (ThUS$30,371).

24.- 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, consequently the Brazilian Tax Authority issued 4 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. Judgment on an appeal to this decision filed by the Tax Authority is still pending. In the specific case of Enel Distribución Goiás, the final decision by the court is pending. As of December 31, 2018, the amount involved in this lawsuit was R$607 million (ThUS$156,614).

Enel Distribución Río (Ampla Energia e Serviços S.A.)

25.- Companhia Brasileira de Antibióticos (CIBRAN) has filed several lawsuits against Enel Distribución Río seeking compensation for energy supply failures in the years 1987 to 1994 and 1995 to 1999.

·CIBRAN vs. Ampla Energia e Serviços S.A. The Court of Justice of the State of Río de Janeiro (court of second instance) ruled in Enel Distribución Río’s favor, dismissing the claim for compensation, and a special appeal filed by CIBRAN is currently pending before the Superior Court of Justice (court of third instance). The amount involved in this lawsuit cannot be determined, as it will be determined by an expert at the end of the lawsuit.

·CIBRAN vs. Ampla Energia e Serviços S.A. The court of first instance ruled against Enel Distribución Río, and an appeal filed by Enel Distribución Río is currently pending before the Court of Justice of the State of Río de Janeiro (court of second instance). As of September 30, 2018 the amount involved in this lawsuit was ThR$481.62 (US$124,264,478).

26.- Indústria de Papel e Embalagens S.A. (CIBRAPEL) filed a lawsuit against Enel Distribución Río seeking compensation due to energy supply failures. A final decision was rendered against Enel Distribución Río. The expert opinion fixed the compensation at R$ 21.5 million, but the amount has been challenged by Enel Distribución Río, and the appeal has not yet been resolved as of this date. As of December 31, 2018, the amount involved in this lawsuit was R$190.1 million (ThUS$49,054).

27.- The Niterói Workers Union filed a labor claim against Enel Distribución Río 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. Enel Distribución Río lost  all of the preceding court instances, and an extraordinary appeal filed by Enel Distribución Río is currently pending before the Federal Supreme Court. As of December 31, 2018, the amount involved in this lawsuit was R$97.7 million (ThUS$25,214).

28.- The Brazilian Tax Authority served a notice of breach 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 Superior Court and is awaiting its decision. The amount involved in this dispute is R$166 million (ThUS$ 42,830).

29.- 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)

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issued by the Company in 1998. Enel Distribución Río is still litigating this issue in the judicial court of the first instance. The total amount of this dispute is estimated at R$1,272 million (ThUS$328,192).

30.- 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 was of the opinion that the ICMS levied 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, 2018, the total amount involved in this lawsuit was estimated at R$126 million (ThUS$32,510).

Eletropaulo (commercially known as Enel Distribución Sao Paulo) .

31.- Centrais Elétricas Brasileiras S.A. (Eletrobrás) filed a lawsuit against Eletropaulo seeking the payment of amounts owed due to inflation in a funds contract signed in 1986. A final decision was rendered against Eletropaulo. The expert work to define the amount was started, but on May 31, 2018 the parties signed an agreement (pending ratification by the trial court) and Eletropaulo will pay Eletrobrás the amount of R$1,500 million over 5 years. As of December 31, 2018, the amount involved in this lawsuit was R$1,601.4 million (ThUS$413,286).

32.- Eletropaulo filed an action seeking the annulment of ANEEL’s administrative decision, which determined the retroactive exclusion of the tariffs applied by Eletropaulo 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 Eletropaulo) for inclusion of other existing service assets (network), but not recorded in the company’s remuneration base. There is no first instance decision and the lawsuit is in its initial phase. As of December 31, 2018, the amount involved in this lawsuit was R$827.5 million (ThUS$213,559).

33.- Sindicato dos Trabalhadores na Indústrias de Energia Elétrica de São Paulo filed 5 class-actions seeking the payment of hazard allowance for all employees (except management positions) of Eletropaulo 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. There is still no first instance decision. As of December 31, 2018, the amount involved in this lawsuit was R$109.6 million (ThUS$28,288).

34.- The Federal Public Prosecutor’s Office (MPF) has filed a public civil action against Eletropaulo and ANEEL seeking to block the transfer to consumers’ tariffs of amounts contracted with affiliated parties (AES Tietê, at that time) and the double reimbursement of amounts already collected. The court ruled in Eletropaulo’s favor, rejecting the applications, but the Federal Regional Court (TRF) admitted the MPF’s appeal and overturned the decision. An Eletropaulo appeal against TRF’s decision is currently pending in the Superior Court of Justice. The amount involved in this lawsuit cannot be estimated.

35.- The Public Prosecutor’s Office for Labor Matters filed a public civil action against Eletropaulo 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. There is still no decision by the court of first instance. The amount involved in this lawsuit cannot be estimated.

36.- Neoenergía commenced arbitration against Eletropaulo for alleged non-compliance with the investment letter signed between the parties in the process that resulted in Enel Américas’ acquisition of shareholder control of the company. In summary, Neoenergía is seeking compensation, not yet estimated, for losses and damage suffered as a result of non-compliance with the investment letter. The arbitration tribunal has been constituted. On October 18, 2018, Neoenergía filed its first statement. On December 3, 2018, Eletropaulo filed its defense. Neoenergía will answer following which Enel may file its response.  It is expected that a final decision will be rendered towards the end of 2019.

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37.- Eletropaulo 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. MR$159.3 of the total amount involved (MR$796.4) comprise the attorneys’ fees (20%) paid by the Federal Tax Authority. The possibility of a loss with respect to this portion is probable. The remaining portion (MR$637.1) is related to the capital (tax) paid with amnesty benefits and the possibility of loss is remote. Therefore, the possible amount of loss is MR$159.3 (ThUS$41,101).

38.- In May 2008, the Brazilian Tax Authority filed a lawsuit against Eletropaulo seeking payment of the PIS (Social Integration Program) 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, Eletropaulo 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 the latter regard, while awaiting the outcome of this procedure, the Office of the Attorney General of the Department of the National Treasury of Brazil requested the replacement of the bank guarantee letter to be filed with the court. This request was rejected and the Attorney General’s Office appealed this decision. The company’s appeals and the Attorney General’s appeal are still pending. As of December 31, 2018, the amount involved in this lawsuit was MR$238.5 (ThUS$61,536).

39.- In accordance with a final decision issued after a trial, Eletropaulo was granted the right to offset claims for FINSOCIAL (social contribution system established in March 1992 before COFINS) related to amounts paid from September 1989 to March 1992. In spite of this, due to differences in the calculation of the credits stipulated by the Federal Tax Authority, part of the offsets requested by the company were not accepted and the debts were released 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, 2018, the amount involved in this lawsuit was MR$216.9 (ThUS$55,963).

40.- The Federal Tax Authority issued a tax assessment to Eletropaulo, based on the alleged non-payment of Personal Income Tax (IRPJ) and Social Contribution on Net Profit (CSLL) for the 2001 and 2002 financial 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 procedure in October 2017, the dispute was submitted to the courts of law. The court of first instance’s decision is currently pending. As of December 31, 2018, the amount involved in this lawsuit was MR$168 (ThUS$43,346).

41.- The Tax Authority issued a tax assessment to Eletropaulo 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. Currently, the case is awaiting a first instance administrative decision. As of December 31, 2018, the amount involved in this lawsuit was MR$151.8 (ThUS$39,166).

42.- Eletropaulo filed an application seeking recognition of the right to offset the total tax credits resulting from Eletropaulo’s division against the CSLL. Favorable rulings were issued in the courts of first and second instance. In May 2017, the Federal Tax Authority filed an interlocutory appeal with the Superior Court of Justice, which is pending. As of December 31, 2018, the amount involved in the lawsuit was MR$147.4 (ThUS$38,031).

43.- In July 2000, Eletropaulo 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 raised against Eletropaulo by the Federal 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

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the court of second instance. As of December 31, 2018, the amount involved in the lawsuit was MR$640.7 (ThUS$165,309). The difference between this amount and the amount previously disclosed by the company during the third quarter of 2018 originates in the reassessment conducted by the company assisted by its legal counsel. In the third quarter of 2018, only the default penalty and the Federal Tax Authority’s attorney’s fees had been taken into account, whereas now the amount includes the entire sum involved (principal (tax), default penalty, interest and fees).

44.- Eletropaulo 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 imputed to the company: (i) incorrect classification of customers, (ii) illegally applied tax exemption, and (iii) non-payment of the penalty for non-payment of late contribution payments. In July 2018, the court of first instance rendered a decision partially favorable to the company that limited the interest charged by the Tax Authority to the Brazilian preferential rate (“SELIC”). Both parties filed appeals against this decision which are currently pending before the court of second instance. As of December 31, 2018, the amount involved in the lawsuit was MR$118.7 (ThUS$30,626).

45.- 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 administrative procedures and is awaiting the final decisions. As of December 31, 2018, the amounts involved in the lawsuits were MR$107.9 (ThUS$27,840).

46.- Eletropaulo filed a complaint against Federal Decree No. 8,426/2015, which reinstated the PIS/PASEP and COFINS tax 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 second judicial instance (August 2017). In December 2017, the company filed appeals with the Superior Court of Justice and the Federal Supreme Court, with the rulings currently pending.  As of December 31, 2018, the amount involved in this lawsuit was MR$106.1 (ThUS$27,375).

47.- Eletropaulo filed a complaint claiming the right not to take into consideration, in its bases of calculation of IRPJ and 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 Eletropaulo. The Federal 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, 2018, the amount involved in this lawsuit was MR$68.2 (ThUS$17,596).

48.- Eletropaulo 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, for which final decisions are pending. As of December 31, 2018, the amount involved in this lawsuit was MR$151.5 (ThUS$39,089).

Enel CIEN S.A.

49. -   Enel CIEN is an Enel Américas group transmission company in Brazil. Its network connects the electrical system of Brazil and Argentina. Enel CIEN has signed contracts with two Brazilian companies (Furnas and Tractebel Energia S.A.) for the purchase and sale of firm power with associated energy from Argentina. In 2005, due to the energy and economic crisis in Argentina, it was no longer possible to fulfil the terms of the contract. The two companies have filed actions for declaration of contractual termination, imposition of contractual penalties and claims for compensation (not estimable to date).

Furnas vs. Enel CIEN S.A. The court of first instance issued a decision favorable to Enel CIEN and on August 21, 2018 the decision was confirmed by the Court of Justice, but the ruling has not yet been issued, at which time the deadline for an appeal by Furnas will start to run. As of December 31, 2018, the amount involved in this lawsuit was ThR$1,875.7 (ThUS$483,948).

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Tractebel Energia S.A. vs. Enel CIEN S.A. There is no interim decision and there is still no first instance decision from the Santa Catarina state court. The proceedings of the case are suspended until a new decision by the judge. As of December 31, 2018 the amount involved in this lawsuit was ThR$393.9 (ThUS$101,657).

Enel Generación Fortaleza S.A. (formerly Central Generadora Termoeléctrica Fortaleza S.A. or “CGTF”)

50.- Petróleo Brasileiro S.A (Petrobrás) has notified Enel Generación Fortaleza of its intention to terminate the gas supply contract signed in 2003 (within the scope of the Brazilian government’s thermoelectric priority program) based on an alleged economic-financial imbalance. Enel Generación Fortaleza alleges that the contractual conditions of the gas supply are “guaranteed” by the Brazilian government and that the power generation by Enel Generación Fortaleza and other generation companies linked in this program guarantee the energy supply for the country. Since the beginning of this dispute, gas supply has been suspended at some points and later restored by a court order (the most recent ruling in effect since December 10, 2018). In addition, the issue of the forum for the dispute, either the legal system or arbitration, has not yet been resolved.  The lawsuit is still at its initial stage and the production of evidence has not begun. On December 28, 2018, the parties asked for the arbitration to be recessed now that the parties have resumed discussions to reach an understanding. The court has accepted this request and the arbitration is recessed until March 28, 2019. The amount involved in this lawsuit cannot be estimated.

51.- In February 2007, the Brazilian Tax Authority sent Enel Generación Fortaleza an assessment for PIS/COFINS for the periods December 2003 and February 2004 to November 2004, regarding alleged differences between the amounts declared in the annual return (where PIS/COFINS amounts were reported under the non-cumulative regime) and the amounts declared in the monthly return (where the amounts due under the old cumulative regime were reported). After a ruling was rendered by the third administrative instance against CGTF, the company filed a plea for clarification, which is awaiting a final decision. If the outcome is unfavorable, Enel Generación Fortaleza will resort to the judicial courts. As of December 31, 2018 the total amount involved in this lawsuit was estimated at MR$86 (ThUS$22,189).

Enel Brasil S.A.

52.- 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 a sum larger than owed in 2009 and 2010. After adverse rulings at the first and second administrative instances, the company again appealed to the second administrative level. As of December 31, 2018, the total amount of this dispute is estimated at MR$284 (ThUS$73,276).

Management of Enel Américas S.A. has considered a total provision for the amount of ThUS$538,500 and believes that the provisions recorded in the consolidated financial statements as of December 31, 2018, adequately cover the risks for the lawsuits described in this Note, and therefore, they are not expected to give rise to liabilities in addition to those recorded.

Given the nature of the risks covered by these provisions, no reasonable payment schedule, if any, can be determined.

36.4Financial restrictions

A number of the Company’s loan agreements, and those of some of its subsidiaries, include the obligation to comply with certain financial ratios, which is normal in contracts of this nature. There are also affirmative and negative covenants requiring the monitoring of these commitments. In addition, there are restrictions in the events-of-default clauses of the agreements which require compliance to avoid acceleration of such debt.

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1.Cross Default

Some of the financial debt contracts of the Company contain cross default clauses. The credit line agreements governed by Chilean law, which the Company signed in March 2016 for UF 2.8 million, stipulate that cross default is triggered only in the event of non-compliance by the borrower itself (i.e. the Company, with no reference made to its subsidiaries). In order for debt acceleration to occur in these credit lines due to cross default originating from other debt, the amount overdue of a debt must exceed US$50 million, or its equivalent in other currencies, and other additional conditions must be met such as the expiry of grace periods. These credit lines have not been used.

In Enel Américas’ bank loan under the law of the State of New York, signed in February 2018 and that expires in February 2021, the cross default for non-payment could be triggered by another debt either of Enel Américas on a stand-alone basis or of some “Significant Subsidiary” (as defined in the contract). In order to accelerate the debt in this loan due to the cross default originating such other indebtedness, the amount in default, whether over an  individual loan and an aggregate of such, must exceed US $ 150 million, or its equivalent in other currencies, and other additional conditions must be met, including the expiry of grace periods (if any in the contract in default) and formal notice of the intention to accelerate the debt by creditors representing more than 66.67 % of the amount owed or committed. As of December 31, 2018, the amount owed in connection with this loan totals ThUS$ 352,387.

For a substantial number of the bonds issued by the Company that are registered with the SEC, commonly called “Yankee bonds”, a cross default might be triggered by another debt of the Company on an individual level, or of any significant subsidiary (as defined in the contract), for any amount overdue provided that the principal of the debt giving rise to the cross default exceeds US$150 million, or its equivalent in other currencies. Debt acceleration due to cross default does not occur automatically but has to be demanded by the holders of at least 25% of the bonds of the specific series of Yankee bonds. In addition, events of bankruptcy or insolvency of foreign subsidiaries have no contractual effects on the Yankee bonds of the Company. The Yankee bonds of the Company mature in 2026. As of December 31, 2018, the outstanding amount for the Yankee Bonds was ThUS$588,882.

The Company’s bonds issued in Chile state that cross default can be triggered only by the default of the issuer, either on a stand-alone or on an aggregate debt basis, when the amount in default exceeds 3% of total consolidated assets. Debt acceleration requires the agreement of at least 50% of the bondholders of the specific series. As of December 31, 2017, the outstanding amount for the domestic bonds was ThUS$22,798.

2.Financial covenants

Financial covenants are contractual commitments with respect to minimum or maximum financial ratios that the Company is obliged to meet at certain periods of time (quarterly, annually, etc.) and in some cases only when certain conditions are met. Most of the financial covenants of the Company limit the level of indebtedness and evaluate the ability to generate cash flows in order to service the companies’ debts. 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 domestic bonds of the Company include the following financial covenants, whose definitions and calculation formulas are set out in the respective contract:

·      Consolidated Equity: Minimum Equity of Ch$677,228 million must be maintained, a limit adjusted at the end of each year as established in the indenture. Equity is the sum of Equity attributable to the shareholders of Enel Américas and non-controlling interests. As of December 31, 2018, the Company’s equity was Ch$6,136,139 million (at the closing exchange rate).

·      Debt to Equity Ratio: A debt to equity ratio, defined as Total liabilities to Equity, shall not be more than 2.24. Total liabilities are the sum of Total current liabilities and Total non-current liabilities, while Equity is the sum of Equity attributable to the shareholders of Enel Américas and non-controlling interests. As of December 31, 2018, the debt to equity ratio was 2.10.

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·      Unsecured Assets: The ratio of Unsecured assets to Unsecured total liabilities must be at least 1. Total Unsecured or free assets is the difference between Total assets and Total secured assets. Total unsecured or free assets consists of Total Assets less the  sum of Cash, Bank balances, Current accounts receivable from related parties, Current payments in advance, Non-current accounts receivable from related entities, and Gross identifiable intangible assets, while Total secured assets relates to assets pledged as security. On the other hand, Total unsecured liabilities consist of the sum of Total current liabilities and Total non-current liabilities, less liabilities secured by collateral. As of December 31, 2018, this ratio was 1.09.

The undisbursed credit lines in Chile include the following covenants, whose definitions and calculation formulas are set out in the respective contract:

·      Debt to Equity Ratio: A debt to equity ratio shall not be more than 1.3. Debt is defined as the sum of current and non-current interest-bearing borrowings, while Equity is the sum of Equity attributable to the shareholders of Enel Américas and non-controlling interests. As of December 31, 2018, the debt to equity ratio was 0.71.

·      Debt repayment capacity (Debt/EBITDA ratio): A debt to EBITDA ratio shall not be more than 3.5. Debt is defined as the sum of current and non-current interest bearing borrowings, while EBITDA is defined as operating income less depreciation and amortization expenses and impairment losses (or reversals) for the four moving quarters ended at the time of calculation. As of December 31, 2018, the Debt/EBITDA ratio was 1.87.

On the other hand, the Yankee bonds or any other debt of the Company on a stand-alone basis are not subject to financial covenants.

As of December 31, 2018, the most restrictive financial covenant for the Company was the Unsecured Assets ratio with respect to Series B2 domestic bonds.

In Perú, the debt of Enel Distribución Perú S.A. only has a single covenant:

·      Local bonds of the fourth program, whose outstanding amount as of December 31, 2018 was ThUS$82,865 and final maturity in January 2033, are subject to Debt to Equity Ratio which is calculated by dividing Total liabilities less deferred liabilities by Equity.

On the other hand, the debt of Enel Generación Perú S.A. includes the following covenants:

·      Local bonds whose outstanding amount as of December 31, 2018 was ThUS$43,895 and final maturity in January 2028, are subject to Debt to Equity Ratio which is calculated by dividing Debt less cash by Equity.

·      Bank borrowings of Chinango, Enel Generación Perú’s subsidiary, with Bank of Nova Scotia, whose outstanding amount as of December 31, 2018 was ThUS$424 and final maturity in January 2019, include covenants, calculated at the individual level, to maintain an indebtedness ratio calculated as net debt less cash divided by net equity and ability to pay the debt calculated as financial debt divided by EBITDA.

·      As of December 31, 2018, the most restrictive financial covenant for Enel Generación Perú S.A. was the ratio of indebtedness corresponding to the local bonds, while Chinango’s most restrictive covenant was the ability to pay the debt.

Finally, in Perú, the debt of Enel Generación Piura includes the following covenants:

·      Finance lease arrangement with Banco de Crédito del Perú whose outstanding amount as of December 31, 2018 was ThUS$43,866 and final maturity in June 2020, is subject to the following covenants: Debt Repayment Capacity Ratio calculated by dividing Cash Flows for Debt Service by Debt Service, and Debt to Equity Ratio calculated by dividing Total liabilities less Deferred Liabilities by Equity.

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·      Finance lease arrangement with Banco Scotiabank whose outstanding amount as of December 31, 2018 was ThUS$31,165 and final maturity in March 2022, is subject to the same financial covenants as those for the finance lease arrangement with Banco de Crédito del Perú.

·      As of December 31, 2018, the most restrictive financial covenant for Enel Generación Piura was the Debt repayment capacity with Scotiabank.

In Brazil, the debt of Enel Distribución Río S.A includes the following covenants:

·     Ninth local bond issue whose outstanding amount as of December 31, 2018 was ThUS$154,663 and final maturity in December 2020, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and Debt to Equity Ratio calculated by dividing Debt by Net Equity.

·      Loan with Banco Nacional de Desenvolvimiento (“BNDES”) whose outstanding amount as of December 31, 2018 was ThUS$225,414 and final maturity in December 2023, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt to Equity Ratio calculated by dividing Debt by Net Equity.

·      Loan with Citibank and Banco Itaú whose outstanding amount as of December 31, 2018 was ThUS$172,865 and final maturity in July 2021, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt to Equity Ratio calculated by dividing Debt by Net Equity.

·      As of December 31, 2018, the most restrictive financial covenant for Enel Distribución Río S.A. was the Debt Repayment Capacity contained in bank borrowings with BNDES.

In addition, the debt of Enel Distribución Ceará S.A. includes the following covenants:

·      Loan with Eletrobrás and Banco do Brasil whose outstanding amount as of December 31, 2018 was ThUS$25,049 and final maturity in October 2023, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA.

·      Loans with BNDES and Banco Itaú whose outstanding amount as of December 31, 2018 was ThUS$48,607 and final maturity in December 2023, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and Debt to Equity Ratio calculated by dividing Debt and Net Equity.

·      Third local bond issue whose outstanding amount as of December 31, 2018 was ThUS$25,049 and final maturity in October 2018, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt Coverage Ratio calculated by dividing EBITDA by Interest Expense.

·      Fifth local bond issue, Sixth local bond issue and promissory notes with Itaú whose outstanding amount at December 31, 2018 was ThUS$250,972 and maturity in June 2025 is subject to the Debt Repayment Capacity Ratio, calculated by dividing Debt by EBITDA.

·      As of December 31, 2018, the most restrictive financial covenant for Enel Distribución Ceará S.A. was the Debt/EBITDA ratio for the corresponding local bonds and promissory notes.

Finally, in Brazil, the debt of Eletropaulo includes the following covenants:

·      14th and 23rd local bond issue whose outstanding amount as of December 31, 2018 was ThUS$922,422 and final maturity in September 2025, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt Coverage Ratio calculated by dividing EBITDA by Interest Expense (only applicable to the 14th issue).

·      As of December 31, 2018, the most restrictive financial covenant for Eletropaulo was the Debt/EBITDA ratio.

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In Colombia, the debt of Codensa S.A. (“Codensa”) includes the following covenants:

Loan with the Bank of Tokyo whose outstanding amount as of December 31, 2018 was ThUS$113,223 and final maturity in June 2020, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA.

All of our subsidiaries not mentioned in this note are not subject to compliance with financial covenants.

Lastly, in most of the contracts, debt acceleration for non-compliance with these covenants does not occur automatically but is subject to certain conditions, such as a cure period.

As of December 31, 2018 and 2017, neither the Company nor any of its subsidiaries were in default under their financial obligations summarized herein or other financial obligations whose defaults might trigger the acceleration of their financial commitments.

36.5Other Information

Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)

Availability Agreements for Combined Cycles and Turbosteam

On March 18, 2015, the Undersecretary of Electric Energy issued its Note SS.EE. 476/2015, which established the procedure to coordinate the remuneration according to SE Resolution No. 95/2013 and the “Availability Agreements for Combined Cycles and Turbosteam” (hereinafter the “Availability Agreements”) entered into between Enel Generación Costanera and CAMMESA, effective on February 2014. As established in Note SS.EE. 476/2015, Enel Generación Costanera shall temporarily relinquish its right to receive the “Additional Remuneration Trust” established under SE Resolution No. 95/2013, except for those already committed, its amendments and supplements, as well as, the “Remuneration for Non-Recurrent Maintenance” as established in Res. SE No. 529/2014, its amendments and supplements.

The procedure led to the reversal of the deductions made and applied to Enel Generación Costanera S.A. as established in Notes S.E. No. 7594/2013 and No. 8376/2013. Since January 2015, the rights that Enel Generación Costanera relinquished were applied to compensate for the funds received from CAMMESA from that date on to perform the works provided for in the agreements.

On June 29, 2015, the Secretary of Energy issued Note S.E. No. 1210/2015 instructing CAMMESA on the methodology to adapt the remuneration conditions set forth in the respective terms of the Availability Agreements, taking into account the concepts defined in SE Resolution Nos. 95/2013 and 529/2014 and any applicable regulation.

On July 3, 2015, Enel Generación Costanera and CAMMESA signed an addendum to the Availability Agreements. The initial terms and those in the addendum shall rule the agreement between the parties and shall be understood as entirely valid until the expiration date referred to in the agreements. Consequently, CAMMESA gathered all the required documents, as well as the modifications included in the addenda, according to the defined procedure.

On August 30, 2016, CAMMESA through Note B-110359-1 informed Enel Generación Costanera that the Secretary of Electrical Energy authorized the re-allocation of the funds from the Supplementary Works for up to US$5,287,772, which were originally assigned to Turbosteam Units No. 3 and 4 and 6. Likewise, the scope of the Supplementary Works to be performed in Turbosteam Units No. 6 and No. 7 was expanded for an amount up to US$ 10,575,000 plus VAT and import duties. On December 16, 2016, Addendum No. 5 to the Turbosteam Equipment Availability Contract with the MEM was signed. The amendments approved the re-allocation of funds required to perform the supplementary works in turbosteam unit No. 6 for US$5,287,772 plus taxes, and the funds for the supplementary works in Turbosteam Units No. 6 and No. 7 was increased to US$10,575,000 plus taxes.

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The availability contract for combined cycles equipment expired on October 31, 2016. In December 2017, and despite that certain minor works subsequently performed, Enel Generación Costanera submitted letters to CAMMESA in order to request to finalize the availability contracts of equipment. As of the date of these financial statements, Enel Generación Costanera has not received any notification from CAMMESA related to finalizing such contracts. The financial statements of Enel Generación Costanera as of December 31, 2017 include the estimated effects based on management’s judgement considering the expected resolution of this matter.

Central Vuelta de Obligado (VOSA)

During the 2016 year, Central Vuelta de Obligado S.A. (“VOSA”) continued generating energy at the demand of CAMMESA with the two simple cycle Gas Turbine with both fuels. However, the project progress slowed down. This fact resulted in several claim notes from VOSA to General Electric Internacional Inc. and General Electric Internacional Inc. Argentina branch (“GE”), acting on behalf of Fideicomiso Central Vuelta de Obligado (“FCVO), to get the project pace back on track. In this regard, on February 12, 2016, GE initiated a higher costs claim to the FCVO through the contractual clause of “friendly negotiations”. During September 2016, due to the additional costs derived from inflation, the negotiations ended in an arbitration process provided in the contract. On November 10, 2016, FCVO and VOSA were notified by the Arbitration Court of the Buenos Aires Stock Exchange about the arbitration suit filed by GE.

On August 7, 2017, following a series of negotiations tasks, FCVO and GE signed a Second Supplemental Agreement (“SAS” for its acronym in Spanish) by means of which GE commits to achieve the Beginning of the Total Operation (“IOT” for its acronym in Spanish) no later than February 28, 2018. In addition to other issues, the parties agreed to new penalties for non-compliance, the delivery of new guarantees, and the suspension of all judicial and/or extrajudicial deadlines until May 29, 2018 regarding the actions and claims between the FCVO and GE. For this reason, the parties requested the Court to suspend the arbitration process. The Court finally resolved to suspend the process until May 28, 2018.

Subsequently, on June 11, 2018, the Parties resolved to extend the period of suspension of all judicial and / or extrajudicial deadlines until September 15, 2018, and before the expiration of this deadline, on September 13, 2018, the Parties decided to extend again the period of suspension of all judicial and / or extrajudicial deadlines until November 15, 2018. Once again, on November 13, 2018, the Parties decided a new extension of the suspension period of all judicial and / or extrajudicial deadlines until March 15, 2019.

Finally, on March 20, 2018, CAMMESA began the commercial operation in the Wholesale Electricity Market, of the two TGs and TV units in its operation as a combined cycle plant of VOSA , for up to 778,884 MW (net capacity).

On February 7, 2019, VOSA signed with CAMMESA the Supply Contract, the  Operation and Maintenance Contract and the pledge and assignment contracts in guarantee. For this reason, the next stage now is to receive the collection of fees. Once CAMMESA reports the payment schedule of the installments, the Company will restructure the current/non-current credit classification.

CAMMESA Debts

On August 18, 2016, CAMMESA and Enel Generación Costanera formalized a mutual and collateral assignment agreement, for Ar$ 1,300 million required to finance the power plant operation. The methodology and deadlines to implement for the repayment will be a maximum of 48 equal monthly payments with a 12 month grace period, counted from the installment of the last partial advance or on December 31, 2016, whichever occurs first. The interest rate to apply will be equivalent to the average monthly yield obtained by CAMMESA in its financial placements.

As of December 31, 2018, this debt balance was Ar$2,120,074,389 (including interest), with Ar$1,485,382,516 as non-current liabilities and Ar$634,691,873 as current liabilities. As of December 31, 2017, the debt balance was to Ar$2,739,439,172 (including interest) which the amount of Ar$2,054,579,379 are registered as non-current liabilities.

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Enel Generación El Chocón S.A.

Provisions and Contingent Liabilities

Federal Administration of Public Revenue — General Taxation Office (AFIP in Spanish)

The Company presented its sworn income tax statement for the year 2013, applying the adjustment mechanism for tax inflation provided by the Income Tax Law. As for the Company, the regulatory impossibility for inflationary adjustment in tax matters would result in a non-existent income tax determination. This is because the inflationary adjustment mechanisms on tax assessment result in a tax loss, and if the adjustment mechanisms for inflation were not applied, there would be a confiscation assumption in accordance with the jurisprudence of the Supreme Court of Justice of the Nation in “Candy S.A.” matter. In a supplementary manner, the Company filed a Declaration of Certainty Action and Precautionary Measures to the National Court of First Instance in the Federal Administrative Matters, with the purpose of obtaining the statement, in the specific case, the inapplicability of any rule that suspends the application of adjustment mechanisms for inflation due to an alleged confiscatory nature. On October 31, 2014, the negative judicial resolution of the precautionary measure requested by Company was notified. Against this resolution, on November 7, 2014, the Company filed an appeal to the Appeals Chamber in Federal Administrative Litigation. The Appeals Chamber notified its resolution on March 12, 2015, confirming the rejection of the precautionary measure. On November 21, 2014, the Company requested that the court of first instance transfer the Declaratory Action to the National Treasury, in order to proceed with the substantive issue, treatment parallel with the challenge of the rejected requested precautionary measure resolution. On May 13, 2015, the Company requested the intervening court to open the period allowed for producing evidence, which was on May 18, 2015. By virtue of this, the, transfers of the proof points offered were answered and carried out and which the Court resolved making room for the expert proof points offered by both parties. On May 30, 2017, the expert presented the expert report, in which arrived at the same coefficients as those indicated by the Company in the filed claim. On June 6, 2017, the Court ordered a transfer to the parties of the expert report. Thus, the Company proceeded to notify personally the expert report and submitted its transfer reply, where it agreed with said report. On other hand, the National Treasury replied to the transfer in a timely manner, formulating certain challenges to the aforementioned report.  Given that the National Treasury has transferred   its challenges to the expert, the latter replied to said challenges  on March 8, 2018 ratifying completely the expert report. On September 4, 2018, the Company requested that the term for submitting evidence be declared closed. Finally, on September 6, 2018, the close of the term for submitting evidence was ordered and now arguments must be submitted based on the evidence of the case.

Additionally, the Company presented its sworn income tax statement for the year 2014, applying the tax inflationary adjustment mechanism provided for in the Income Tax Law to the same effect as done for fiscal year 2013. Pursuant to the above, in a complementary manner, the Company filed on May 8, 2015 a Declarative of Certainty Action to the National Court of First Instance in Federal Administrative Matters. This in order to obtain a declaration, in the specific case, of the inapplicability of any rule that suspends the application of inflationary adjustment mechanisms due to an alleged confiscatory nature. On June 11, 2015, the court took into account the lawsuit filed, ordering its communication to the Procurator of the Treasury of the Nation. On September 25, 2015, the file was sent to the Federal Prosecutor’s Office on the issue of on the jurisdiction of the intervening Court. On October 30, 2015, and in response to the statement made by the Federal Prosecutor, the court was deemed competent, and the claim was also sent to the AFIP. Consequently, on December 11, 2015, the Company transferred the claim to the AFIP, who answered it in due time and form. Subsequently, on April 6, 2016, the Company requested the intervening court to open the provisionary period, which was ordered on April 28, 2016. Thus, on June 23, 2016, the parties provided the evidence. As a result, the transfers of the offered proof points were carried out, and were answered in a timely manner by both parties. On December 22, 2016, the court decided to reject the objections raised by the Company and acknowledge the additional points proposed by the National Treasury. On May 31, 2017, having examined the administrative file, the Company observed the discharge report dated February 2, 2017, signed by the AFIP, which. The aforementioned states that there are no observations to be made regarding the adjustments and items affected by the adjustment for inflation related to the sworn income tax statement presented by the Company and submitting said report to the External Inspection Division II for its consideration.

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On the other hand, in regards to the judicial file, after successive extensions, on March 23, 2018 the expert accountant submitted the expert report. On July 6, 2018, the defendant was notified of, and presented with, the accounting expert report. On August 21, 2018 the Treasury answered the expert report, requesting certain clarifications to the same, which was incorrectly notified to the expert accountant by the court on November 5, 2018. Since the notification was incorrect, on November 20, 2018, the court ordered a new notification to the expert of the challenges made by the AFIP to the expert report, which is pending notification.

The Company presented its sworn income tax statement for the year 2016, applying again the adjustment mechanism for tax inflation provided by the Income Tax Law to the same effect as made for the business years 2013 and 2014. In a supplementary manner, the Company filed, on May 15, 2017, a Declaration of Certainty Action with the National Court of First Instance in the Federal Administrative Contentious Matters, for the same purposes as that carried out for the aforementioned business years. The Federal Administrative Contentious Court No. 2, Secretary No. 3 processed these claims and, on May 31, 2017, ordered to accompany all the documentation offered by the Company. On July 31, 2017, the aforementioned documentation was attached to the file, and subsequently on August 16, 2017, the filing of the official letter addressed to the Procurator General of the Nation was accredited. On September 22, 2017, the court ordered the transfer of the claim to the National Treasury. Consequently, on November 17, 2017, the pertinent official letter was submitted to the Court to complete the transfer of the claim to the National Treasury for the purpose of confrontation, and the file is currently in office.

On February 8, 2018, the official letter was received by the court, and the notification to the defendant was correctly made. On April 16, 2018, the AFIP answered the lawsuit and filed a motion indicating that the plaintiff lacked a power of attorney to act before the court, and therefore the court ordered that the plaintiff be notified of the motion filed by the National Treasury. Subsequently, the Company answered the notification about lack of power of attorney, by attaching the new power of attorney. Finally, on October 31, 2018, the Court considered the notification as answered, and on November 7, 2018 it ruled resolved in favor of the Company, and the power of attorney was judicially validated.

Following a reasonable criterion consistent with the prior business years, the Company presented its sworn income tax statement for the year 2017, applying the adjustment mechanism for tax inflation provided by the Income Tax Law applying the same mechanism  as for the business years 2013, 2014 and 2016. The Company filed, on October 16, 2018, a Declaration of Certainty Action so that a court be chosen that would hear these proceedings. Federal Administrative Litigation Court No. 11 Secretariat No. 21 was designated.

As a result, on October 19, 2018 the court considered the action as filed, ordering the enforcement of Resolutions 7/94 and 13/05 and that the documentation offered as evidence be submitted to the court. On November 8, 2018, the court considered the aforementioned Resolutions as enforced and the documentation as submitted, and ordered that a notice be sent to the Office of the Treasury of the Nation, and that it be sent to the Prosecutor, in order to reach resolution  regarding the jurisdiction of the court and the authorization of the instance. Finally, on November 13, 2018, the court fee was considered accredited .

Given the high probability that Enel Generación El Chocón’s proposal should find a favorable resolution both at the judicial level and at the National Tax Court in terms of income tax inadmissibility for the years 2013, 2014, 2016 and 2017 as a result of an assumption of confiscation, the Company has not recorded any liabilities for this matter as of December 31, 2018 and also during 2018 the Company reversed a AR$268,075,396, tax provision which corresponds to AR$ 354.395.675 in homogeneous currency. As of December 31, 2017 the Company had reversed a AR$411,770,483 tax provision plus the AR$107,792,572, reimbursement interest which were previously included in current liabilities.

Edesur S.A.

On April 5, 2016, ENRE issued Resolution Nos. 54 and 55. Resolution No. 54 the ENRE approved the tender specifications for contracting an advisor for the RTI of Edesur.

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On the other hand, Resolution No. 55 approved the 2016 program for the RTI. The resolution defined the criteria, methodology and work plan that Edesur must follow to carry out its tariff studies. To elaborate on the tariff proposals, ENRE informed Edesur of the parameters for quality objectives and management, and the rate of return to be used in determining its own distribution cost.

On September 28, 2016, ENRE, through Resolution No. 522/2016, summoned a public audience for a hearing intended to notify of and allow comments on tariff proposals presented by distribution companies for the next five-year period.

On October 28, 2016, in relation to the RTI process, a hearing was held to notify and allow comments on tariff proposals presented by the distribution companies Edesur and Edenor S.A. under ENRE Resolution No. 55/2016.

Edesur presented a summary of its proposal for the next five years, which highlighted the projected significant investments for the period 2017 — 2021. Likewise, it stated its focus on improving the quality of service through the reduction of supply restitution timing, optimization of customer service and the incorporation of technology in all of its operating processes.

On November 14, 2016, ENRE published in the Diario Official a note in relation to the public hearing, and committed to issue a final resolution on the hearing 30 days after November 11, 2016.

On December 30, 2016, ENRE issued Resolution No. 626, which approved the document titled “Final Resolution Public Audience” (Resolución Final Audiencia Pública, in Spanish) prior to defining the tariffs to be applied. Likewise, it transferred to MEyM’s Undersecretary for Coordination of Tariff Policy (Subsecretaría de Coordinación de Política Tarifaria in Spanish) the topics discussed at the hearing that fall within the purview of that regulatory body.

On February 1, 2017, ENRE issued Resolution No. 64, which approved new prices for the tariff table.

In relation to the application of the new structure and tariff charges, the MEyM understood that it was timely and convenient to instruct ENRE to limit the increase in the VAD arising as a result of the RTI process to be applied from February 1, 2017, to a maximum of 42% with respect to the VAD in effect to date, having to complete the application of the remaining value of the new VAD, in two stages: the first one in November of 2017 and the second one, in February of 2018.

In addition, it provides that ENRE must recognize, to the concessionary company, the difference of the VAD resulting from the application of the gradual increase in the tariff recognized in the RTI, in installments from February 1, 2018 to January 31, 2021, which will incorporate to the value of the resulting VAD at that date. On July 26, 2017, ENRE issued Resolution No. 329/2017, which establishes the determination the recovery process of the loan and its billing in 48 installments from February 1, 2018.

The regulations also establish the updating method of the company´s income for the effect of changes in the prices on the economy and all other issues related to the quality of service provision and the supply regulation.

In compliance with ENRE Resolution No. 64/2017, on March 20, 2017 Edesur confirmed the investment plan for the 2017-2021 period, duly informed for the RTI plus the reconversion of the Balcarce and Tres Sargentos Substations from 27.5 to 13.2 kW. Additionally, indicated the adapting possibility of said plan in the future to changes in demand.

With the issue of ENRE Resolution No. 64/2017, its amendments and SEE Resolution No. 20/2017 which approved the seasonal summer rescheduling and fixed seasonal reference prices, is overcome the tariff transition stage established in the Agreement. This Agreement signed on August 29, 2005, counted on with the signatures of Edesur and the then Ministries of Economy and Production, and Federal Planning, Public Investment and Services, becoming the Company rule by as established in its Concession Contract.

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On May 2017, SEE, through Resolutions No. 256 and No.261, approved the winter seasonal rescheduling and extended the seasonal reference prices set by SEE Resolution No. 20/2017, until October 31, 2017.

On May 16, 2017, the Electricity Dependent Law 27,351 was enacted through PEN Decree No. 339/2017. It provides free, continuous electricity supply to those who registered. As a consequence of the above, on July 26, 2017 the ENRE issued Resolution No. 292, establishing the free service and the connection cost for this category of users. Likewise, on September 25, 2017, the Ministry of Health, through Resolution No. 1538-E, created the “Register of Electrodependents for Health Matters”. As of the date of issuance of these financial statements, the definition of enforcement authority by PEN and the allocation of the item’s budget required for compliance with the standard are pending.

On October 27, 2017 the ENRE, in compliance with the MEyM Resolution No. 403, through Resolutions 526 and 527 convened a Public Hearing by November 17, 2017 at Palacio de las Aguas. The following matters were treated: Firstly,

1)The new power and energy reference prices, the reference price for power and reference energy stabilized for the distribution companies in each one’s equivalent node, corresponding to the Seasonal Summer Period 2017-2018;

2)The Electrical energy saving promotion plan.

3)The welfare tariff and the distribution methodology, between the demand of the MEM, (the cost represented by the remuneration of the electric power transportation in extra high voltage) and, the respective region demand (that corresponds to the regional distribution. system).

Secondly, it informed about the impact the MEyM measures will have on the bills for users of distribution companies as a result it of the Public Hearing that the Ministry convened by Resolution MEyM 403/2017. The Public Hearing mentioned the prices of the Wholesale Electricity Market, subsidies withdrawal from the electric power, transportation and the distribution criteria among the transportation users about the Carriers remuneration (which this agency resolved at the time of the Comprehensive Tariff Review of the Transportation of Electric Power).

On November 1, 2017, the ENRE published Resolution No. 525, partially making the reconsideration appeal filed by Edesur against ENRE Resolution 64/2017. In the resolution, accepted its proposal regarding the treatment of the easements and requesting submit the annual plan for the regularization of easements to be developed during the period 2017-2021, within 60 days after the notification. This time-lapse also applies to CAMMESA’s expenses recognitions, fees and others that should be present in future adjustments ex -post and minor modifications to the quality system and other recognitions.

As a result, on December 1, 2017, through Resolution No. 602, ENRE resolved to approve the new Edesur’s Own Cost of Distribution values, through the application of the mechanisms provided in the RTI. It jointly issued the new Tariff Tables that reflect the new Seasonal Prices (generation and transportation) contained in the resolution of the 1091 Electric Energy Secretariat of 2017, as well as the new subsidy schemes for the Welfare Tariff and bonus for consumption savings for residential users.

On April 17, 2017, the MINEM issued a notice instructing the Secretariat of Electric Energy (SEE) to determine within a period of 120 working days if there are pending obligations of the Agreement Minutes and the treatment to be applied, and to issue during the following 30 days a final resolution report. For these purposes, the SEE requested from Edesur, ENRE and CAMMESA the relevant information.

Within the framework of the process initiated under the aforementioned note, on December 28, 2017 the MINEM issued another notice communicating to CAMMESA that regarding the credits that may correspond to the distributor with respect to the National Government as a result of the provisions in the Agreement Minutes in connection with facts and omissions that had occurred until the enforcement of the tariff tables resulting from the RTI, after discounting the obligations of the concessionaires that are determined to be pending compliance and originated in said period, the National State assumes Edesur’s obligations that  with CAMMESA as a result of the purchase of electric power in the MEM.

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The foregoing occurs as a result of the authority set forth in article 15 of Law 27.341 and based on said article in relation to the obligations of the distributing companies for which no revenue is recognized.

On December 29, 2017, Edesur agreed to the terms of this notice.

Based on the Company’s income update set forth in ENRE Resolution No. 64/2017, on January 31, 2018, the ENRE approved the new figures effective as of February 1, 2018. These tables include a new reduction of wholesale price subsidies, leaving it at 90% of the seasonal price operated in 2017, as well as maintaining the social rate and a bonus of the stimulus plan, due to a reduction in the lower scope electricity consumption.

Regarding the VAD component, the third installment of the increase arising as a result of the RTI process, the proportional part of the deferred revenue produced by said step up  corresponding to the period September 2017 - January 2018 and the application of the efficiency factor, which reflects Edesur’s compliance with the investment plan committed to the RTI, were added to this tariff tables.

At the same time and in order to resume structural normality conditions, the Argentine National Government decided not to extend the validity of the Electric Emergency Law (valid until December 31, 2017) and the Economic Emergency (valid until January 6, 2018).

Regarding the pending issues in connection with the RTI regulation, on May 31, 2018 the ENRE issued Resolution 170/2018 which approves the penalty regime for deviation from the Investment Plan submitted by the distribution companies at the time of the RTI.

On August 23, 2018, the ENRE, by means of resolution 222, rejected the motion filed by EDESUR against the penalty regime for deviation from the Investment Plan submitted in the RTI and published on May 31, 2018.

In turn, on September 5, 2018, EDESUR filed a new Appeal against the above resolution.

On July 30, 2018, Edesur signed a commitment with the former MINEM, in line with the Ministry’s intention to make tariff increases more gradual.

The commitment establishes that Edesur will receive 50% of the increase corresponding to the adjustment mechanism set forth in the tariff as of August 1, while the remaining 50% will be received in 6 adjusted installments as of February 1, 2019.

The commitment also includes maintaining the Investment Plan agreed in the RTI.

On August 1, 2018, 50% (7.925%) of the increase corresponding to the application of the August 2018 MMC to the VAD was applied.Together with this increase, the path of elimination of subsidies to the wholesale energy price, which had been delayed due to the devaluation of June and July 2018, was resumed.

In addition, the former MINEM modified the ceilings to the social tariff, decreasing subsidies to this tariff and the distortions caused by this to the Distributors that are still pending solution and that are being analyzed by the ENRE.

Regarding the Agreement for the solution of the Regulatory Assets and Liabilities, which is delayed, administrative progress for the final execution of the agreement continues to be made.

The Subsecretariat of Electric Energy requested, the last week of September, both from the ENRE and the involved companies, the relevant and necessary information to submit  to the Office of the Attorney General of the Nation and the SIGEN.

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Voluntary retirement plan

During 2018, the Board of Directors of the Company approved a voluntary retirement plan for Company employees who meet certain requirements, effective until March 31, 2019. In all cases, Edesur reserves the final decision about whether to include or note the interested employees in the plan.

As a result of the employees included as of December 31, 2018, a charge to profit or loss of approximately Ar$ 911 million was recognized, and Ar$ 97 million was outstanding for payment at that date, which is disclosed in “Corporate and fiscal debts” under current and non-current liabilities, as appropriate

Financial Position of Edesur

Pursuant to the provisions of article 206 of Law 19,550, as of December 31, 2018, Edesur is in a situation of mandatory reduction of capital stock because the accumulated losses include all the reserves and more than 50% of the corporate capital. Edesur believes that the measures ordered for the tariffs during 2018 and the final resolution of the RTI will allow it to restore the economic-financial equation provided for in the law and in the Concession Contract, and to reverse the effects in the network of the limited levels of investment as a result of the sustained decrease in revenue in the years 2002 to 2014 and consequent financial restrictions, and thus achieve the final normalization of the situation of the electric service provided by the company.

In addition, although the company has a negative working capital, the main components of the current liabilities (debt with CAMMESA for the energy purchase of energy and debt for fines with ENRE) are subject to modifications to specific regulations and discussions and work meetings with the area authorities. These discussions and meetings are in progress at the date of these financial statements. The company’s Management considers that will be successful in adapting the payment periods of said obligations to the company’s actual payments possibilities, by not enforce them in the short term. However, and until the results of these negotiations are specified and implemented, said liabilities are disclosed as current.

The following applies to all the companies in Argentina

Tax Reform

On December 29, 2017, the Decree 1112/2017 of the National Executive Branch was signed, enacting the Tax Reform Law No. 27,430 sanctioned by the National Congress on December 27, 2017. The law was published in the Official Gazette on the date of its enactment. The following points are significant aspects of that reform:

a)Corporate Income Tax and Additional Dividend Tax

Reduction of the corporate income tax rate and the additional tax on distribution of dividends.

Until the fiscal year ended December 31, 2017, the corporate income tax rate of 35% is maintained, which will be reduced to 30% during   fiscal years starting from January 1, 2018, and 25% for fiscal years beginning on or after January 1, 2020.

The reduction in the corporate tax rate supplements the application of the additional tax on distribution of dividends to local individuals and beneficiaries abroad, which the company must withhold and pay to the Treasury as a single, definitive payment when the dividends are paid. This additional tax will be 7% or 13%, depending on whether the dividends distributed correspond to earnings of a fiscal year in which the company was taxed at the 30% or 25% rate, respectively. For these purposes it is considered, without admitting proof to the contrary, that the dividends that are made available correspond, firstly, to the retained earnings of greater age

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b)Equalization Tax

In accordance with the Law 25,063, the dividends paid in excess of the tax profits accumulated at the end of the business year immediately prior to the date of said payment (when applicable, distribution of profits), generates the obligation to withhold a surplus of 35% of income tax as a single, final payment. Said withholding will no longer apply to dividends (when applicable, profits) attributable to earnings accrued in business years from January 1, 2018.

c)Tax Revaluation

Law 27,430 allows the exercise of the option to revalue for tax purposes, for one time only, certain assets owned by the taxpayer existing at the end of the first fiscal year ended after December 29, 2017 (legal effective date ), to the extent that:

(i)they are located, placed or used economically in the country, and are used to generate taxable profits,

(ii)they are not assets with accelerated depreciation or are not fully depreciated, and

(iii)they are not assets that were externalized in accordance with Law 27,260.

The exercise of the option entails the payment of an excise duty on all revalued assets according to the proportion established for each type of asset, which will be applied to the difference between the residual revalued tax value and the tax value of residual origin, calculated in accordance with the provisions of the Income Tax Law. The determined tax is not deductible for the purposes of the income tax assessment, and the gain for the revaluation amount is exempt from income tax. Also, the amount of the revaluation, net of the corresponding depreciation, is not computable for the purposes of the assessment of the minimum presumed income tax.

The revaluation is made applying a revaluation factor from the year of acquisition of the assets that arise from a table contained in Law 27,430, and the value thus determined is subtracted from the depreciation that would have corresponded according to the Income Tax Law for the periods of useful life elapsed, including the period of the option. For non-exchangeable real estate assets and depreciable fixed assets, there is the option of the estimate made by an independent appraiser, as long as it does not exceed the 50% that would result from applying the revaluation factor. The revalued assets will continue to be price-level restated for tax purposes based on the percentage variations of the Internal Wholesale Price Index index provided by the National Institute of Statistics and Census, according to the tables drawn up by the AFIP for these purposes. Thus, the depreciation to be deducted in the income tax assessment will have as components (i) the depreciation installment calculated based on the value of origin, method and useful life timely adopted for the calculation of the income tax, plus (ii) the depreciation installment corresponding to the amount of the revaluation with the aforementioned subsequent price-level adjustment. If a revalued asset is disposed of in one of the two business years immediately following the year taken as the basis for the revaluation calculation, the computable cost will have a penalty, consisting of reducing the residual amount of the price-level restated revaluation by 60% if the disposal takes place in the first of the aforementioned years, or by 30% if it takes place in the second of those years.

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37.PERSONNEL FIGURES

The Group personnel, including that of subsidiaries and jointly-controlled companies in the five Latin American countries where the Group is present, is distributed as follows as of December 31, 2018 and 2017:

	12-31-2018
	Managers	Professionals
	and key	and	Staff and
Country	executives	Technicians	others	Total	Annual Average
Chile	10	44	3	57	53
Argentina	21	1,914	2,413	4,348	4,521
Brazil	56	4,839	6,005	10,900	7,935
Peru	41	874	—	915	920
Colombia	38	2,104	2	2,144	2,148
Total	166	9,775	8,423	18,364	15,577

	12-31-2017
	Managers	Professionals
	and key	and	Staff and
Country	executives	Technicians	others	Total	Annual Average
Chile	7	45	3	55	58
Argentina	45	3,709	1,107	4,861	4,801
Brazil	19	2,756	814	3,589	3,788
Peru	45	863	—	908	907
Colombia	37	1,941	2	1,980	1,963
Total	153	9,314	1,926	11,393	11,517

38.  SANCTIONS

The following Group companies have received fines from administrative authorities:

Subsidiaries

1.Edesur (Empresa Distribuidora del Sur S.A.)

As of December 31, 2018, in view of the pending sanctions imposed by the National Electricity regulator (ENRE) starting in the period that began on October 1, 2018, Edesur has been sanctioned: (i) on 4 occasions for street safety violations in the total sum of Ar$220,453,759 (US$5,852,544), and (ii) on two occasions for violation of commercial quality standards in the total sum of Ar$2,831,196 (US$75,162). In the case of the sanctions for street safety violations, these have been appealed before the ENRE, and the investigation is presently being substantiated. In the case of the commercial quality sanctions, and considering that the deadline to appeal expires after the date of this report, they are the same that have been challenged before the regulator.

2.Enel Generación Costanera S.A. (formerly Endesa Costanera)

As of December 31, 2018, an appeal against a fine imposed by the Federal Administration of Public Revenues (“AFIP”) during 2015 for Ar$58,480 (approximately US$1,553) is pending. Likewise, together with said sanction, the payment of a tax difference of Ar$9,746.63 (approximately US$259) was ordered for violation of article 970 of the Customs Code. Said sanction was appealed and is pending resolution, since the return of the temporary export was fulfilled in a legal time and manner, a circumstance that it proved with the presentation of the corresponding support documentation.

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3.Enel Distribución Río (Ampla Energia e Serviços S.A, or “Ampla”)

In 2018, the São Gonçalo Municipal Secretariat for the Environment issued a notice of violation against Enel Distribución Río amounting to R$47.0 million for alleged “air, water and soil pollution caused by the discarding and burning of irregularly disposed waste”. Enel Distribución Río has filed an administrative appeal against the fine which has not been resolved to date. As of December 31, 2018 the amount involved in the fine was ThR$47.0 (ThUS$12,130).

Tax sanctions: On August 13, 2018, the company received two sanctions by the Río de Janeiro state tax authority for regulatory violations (obligations to register purchase invoices and tax files). The sum of 70,000 euros (US$81,092) has been paid.

The company was fined upon being denied authorization to offset federal taxes. The Brazilian Tax Authority has been imposing isolated fines for 50% of the value of the offset that is requested and denied by the authority. The company filed its administrative defense against the fines and is awaiting a decision. As of December 31, 2018, the amount involved is ThR$4,126 (ThUS$1,065).

4.Enel Distribución Ceará (Companhia Energetica do Ceará, or “Coelce”)

In 2012, the Brazilian Electricity Regulatory Agency (ANEEL) imposed a fine of R$20.6 million on Enel Distribución Ceará for alleged errors in the records of the company’s asset base. Enel Distribución Ceará appealed against the fine which has been reduced to R$11.2 million. Considering the need to legalize the company’s status with the ANEEL, Enel Distribución Ceará paid the fine and filed a lawsuit for the fine’s total nullification. The lawsuit is pending resolution. A favorable decision would result in an updated refund of the amount paid by Enel Distribución Ceará. As of December 31, 2018 the amount involved in the fine was MR$20.7 (ThUS$5,331).

Tax sanctions: The company was fined upon being denied authorization to offset federal taxes. The Brazilian Tax Authority has been imposing isolated fines for 50% of the value of the offset that is requested and denied by the authority. The company filed its administrative defense against the fines and is now awaiting a decision. As of December 31, 2018, the amount involved is ThR$299.4 (US$77,249).

5.Enel Distribución Goiás (CELG Distribuição S.A.)

In 2016, ANEEL imposed a fine of R$61.0 million on Enel for non-fulfilment of a sectorial obligation (linked to the Account for the Development of Energy (Conta de Desenvolvimento Energético or CDE). Enel filed an appeal against the fine that has not yet been resolved to date. As of December 31, 2018 the amount involved in the fine was MR$32.7 (ThUS$8,437).

6.Eletropaulo (commercially known as Enel Distribución Sao Paulo)

ANEEL fined Eletropaulo for alleged errors in the records of the company’s asset base. Eletropaulo filed an appeal which was dismissed. Eletropaulo filed a lawsuit seeking the total nullification of the fine. The judge rendered a decision rejecting Eletropaulo’s claim, and Eletropaulo has lodged an appeal with the court of second instance, which to date is pending resolution. As of December 31, 2018 the amount involved in the fine was MR$177.7 (ThUS$45,855).

ANEEL fined Eletropaulo for alleged formal inconsistencies of asset accounting records. Eletropaulo asserted that the errors have not generated any negative practical consequences for tariffs, and even less for the service provided by the company. Eletropaulo’s administrative appeal was dismissed, so Eletropaulo filed a lawsuit for the total nullification of the fine, for which there has not yet been any first instance decision to date. As of December 31, 2018, the amount involved in the fine was MR$88.4 (ThUS$22,822).

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ANEEL fined Eletropaulo for alleged formal inconsistencies (in 2012) of records of consumer supply quality indices (PRODIST 8), as well as the payment of compensation to consumers for non-compliance with these indices (DIC, FIC and DMIC). Eletropaulo filed an administrative appeal and is awaiting the decision of ANEEL’s Board of Directors. As of December 31, 2018, the amount involved in the fine was MR$23.4 (ThUS$6,029).

ANEEL fined Eletropaulo for alleged formal inconsistencies (in 2015) of records of consumer supply quality indices (PRODIST 8), as well as the payment of compensation to consumers for non-compliance with these indices (DIC, FIC and DMIC). Eletropaulo has filed an administrative appeal and is awaiting the decision of ANEEL’s Board of Directors. As of December 31, 2018 the amount involved in the fine was MR$23.3 (US$6,016).

On December 4, 2018, ANEEL fined Eletropaulo for customer service quality issues. On December 12, 2018, Eletropaulo filed an administrative appeal against the sanction and is awaiting the analysis and decision of ANEEL’s Electric Services Oversight Authority (SFE). As of December 31, 2018 the amount involved in the fine was MR$38.5 (ThUS$9,941).

Tax sanctions: The company was fined upon being denied authorization to offset federal taxes. The Brazilian Tax Authority has been imposing isolated fines for 50% of the value of the offset that is requested and denied by the authority. The company filed its administrative defense against the fines and is awaiting a decision. As of December 31, 2018, the amount involved is ThR$44,796 (ThUS$11,558).

7.Enel Green Power Cachoeira Dourada S.A.

Tax sanctions: The company was fined upon being denied authorization to offset federal taxes. The Brazilian Tax Authority has been imposing isolated fines for 50% of the value of the offset that is requested and denied by the authority. The company filed its administrative defense against the fines and is awaiting a decision. As of December 31, 2018, the amount involved is ThR$999.6 (ThUS$258).

8.Enel CIEN S.A.

Tax sanctions: The company was fined upon being denied authorization to offset federal taxes. The Brazilian Tax Authority has been imposing isolated fines for 50% of the value of the offset that is requested and denied by the authority. The company filed its administrative defense against the fines and is awaiting a decision. As of December 31, 2018, the amount involved is ThR$80.3 (US$20,718).

9.Enel Generación Fortaleza (Central Geradora Termoelétrica Fortaleza S.A.)

Tax sanctions: The company was fined upon being denied authorization to offset federal taxes. The Brazilian Tax Authority has been imposing isolated fines for 50% of the value of the offset that is requested and denied by the authority. The company filed its administrative defense against the fines and is now awaiting a decision. As of December 31, 2018, the amount involved is ThR$1,924 (US$496,416.

10.Enel Distribución Perú S.A.A. (formerly Edelnor)

As of December 31, 2018, Enel Distribución Perú has incurred the following tax penalties:

·As part of a corporate tax audit procedure for the 2006 fiscal year, SUNAT issued a Notice of Penalty to Enel Distribución Perú by means of which it imposed a fine of PS$2,451,254 (US$725,223), by way of annual corporate tax, whose default interest as of the payment date amounted to PS$2,264,959 (US$670,106). It should be noted that the imposition of this penalty is being challenged in the Supreme Court of Justice.

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·As part of a corporate tax audit procedure for the 2007 fiscal year, SUNAT issued a Notice of Penalty to Enel Distribución Perú by means of which it imposed a fine of PS$2,424,073 (US$717,181), by way of income tax, whose current default interest amounts to PS$2,964,862 (US$877,178). Similarly, SUNAT issued Notices of Penalty to Enel Distribución Perú by means of which it imposed fines for omissions in the advances for the periods from January to December for 2007 corporate tax, which amounted to PS$2,150,442 (US$636,225), whose current default interest to date amounts to PS$2,853,727 (US$844,298). It should be noted that the imposition of these penalties is being challenged in the TF (the administrative court of last instance).

·As part of a corporate tax audit procedure for the 2008 fiscal year, SUNAT issued a Notice of Penalty to Enel Distribución Perú by means of which it imposed a fine of PS$2,591,405 (US$767,575) by way of annual corporate tax, whose current default interest to date amounts to PS$2,696,593 (US$797,809). Similarly, SUNAT issued Notices of Penalty to Enel Distribución Perú by means of which it imposed fines for omissions in the advances for the periods from January to December for the 2008 corporate tax, which amounted to PS$2,631,295 (US$778,490), whose current default interest to date amounts to PS$3,046,048 (US$901,198). It should be noted that the imposition of these penalties is being challenged in the TF.

·As part of a corporate tax audit procedure for the 2009 fiscal year, SUNAT issued a Notice of Penalty to Enel Distribución Perú by means of which it imposed a fine of PS$616,333 (US$182,347) by way of annual corporate tax, whose default interest as of the payment date amounted to PS$400,616 (US$118,525). Similarly, SUNAT issued Notices of Penalty to Enel Distribución Perú by means of which it imposed fines for omissions in the advances for the periods from January to December for the 2009 corporate tax, which amounted to PS$1,538,153 (US$455,075), whose default interest as of the payment date amounted to PS$1,595,377 (US$472,005). It should be noted that the imposition of these penalties is being challenged in the TF.

·As part of a corporate tax audit procedure for the 2010 fiscal year, SUNAT issued a Notice of Penalty to Enel Distribución Perú by means of which it imposed a fine of PS$500,298 (US$148,017) by way of annual corporate tax, whose default interest as of the payment date amounted to PS$314,788 (US$93,133). Similarly, SUNAT issued Notices of Penalty to Enel Distribución Perú by means of which it imposed fines for omissions in the advances for the periods from January to December for the 2010 corporate tax, which amounted to PS$374,545 (US$110,812), whose default interest as of the payment date amounted to PS$422,876 (US$125,111). It should be noted that the imposition of these penalties is being challenged in the TF.

·As part of a corporate tax audit procedure for the 2011 fiscal year, SUNAT issued a Notice of Penalty to Enel Distribución Perú by means of which it imposed a fine of PS$507,761 (US$150,225) by way of annual corporate tax, whose default interest as of the payment date amounted to PS$317,452 (US$93,921). Similarly, SUNAT issued Notices of Penalty to Enel Distribución Perú by means of which it imposed fines for omissions in the advances for the periods from January to December for the 2011 corporate tax, which amounted to PS$593,147 (US$175,487), whose default interest as of the payment date amounted to PS$425,908 (US$126,008). It should be noted that the imposition of these penalties is being challenged in the TF.

11.Enel Generación Perú S.A.A. (formerly Edegel S.A.A.)

As of December 31, 2018, Enel Generación Perú has incurred the following tax penalties:

·As part of a corporate tax audit procedure for the 1999 fiscal year, SUNAT issued a Notice of Penalty to Enel Generación Perú by means of which it imposed a fine of PS$2,076,888 (US$614,464) by way of annual corporate tax, whose default interest as of the payment date amounted to PS$10,501,965 (US$3,107,090). It should be noted that 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 a Notice of Penalty to Enel Generación Perú by means of which it imposed a fine by way of corporate tax for the year 2000. Taking into account various payments made and the reassessment made by SUNAT, to date, this penalty amounts to PS$6,460,523 (US$1,911,397), and the default interest to date amounts to PS$14,636,762

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(US$4,330,403). Enel Generación Perú is currently challenging the recalculation of the fine at the TF and the substantive matter in the judicial courts. It is noted that PS$7,928,535 (US$2,345,720) have been duly paid.

·As part of a corporate tax audit procedure for the 2007 fiscal year, SUNAT issued Notices of Penalties to Enel Generación Perú by means of which it imposed fines for omissions in the advances for the periods from March to December for the 2007 corporate tax, which amounted to PS$4,338,344 (US$1,283,534), whose current default interest to date amounts to PS$5,757,637 (US$1,703,443). It should be noted that the imposition of these penalties is being challenged in the TF.

·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 a Notice of Penalty to Enel Generación Perú by means of which it imposed a fine of PS$2,974,314 (US$879,974.5) (customs fines were settled in dollars). It should be noted that the imposition of this penalty is being challenged in the judicial courts, for which PS$5,832,129 (US$1,725,482) had to be paid, and its default interest as of the payment date amounted to PS$3,395,224 (US$1,004,504). It should be noted that the full amount of the tax due related to the above-mentioned Notice of Penalty was not paid since part of it was prescribed.

12.Enel Perú S.A.C. (formerly Generandes)

As of December 31, 2018, Enel Perú has incurred the following tax penalties:

As part of an audit procedure for corporate tax and IGV for fiscal year 2000, SUNAT issued a Notice of Penalty to Enel Perú by means of which it imposed a fine of PS$2,920,104 (US$863,936) by way of annual corporate tax and whose default interest as of the payment date amounted to PS$14,053,695 (US$4,157,898). Similarly, SUNAT issued Notices of Penalty to Enel Perú by means of which it imposed fines of PS$1,771,933 (US$524,241) for the improper application of the IGV for the periods of April, June and October 2000, whose default interest as of the payment date amounted to PS$10,231,619 (US$3,027,106). It should be noted that the imposition of these penalties is being challenged in the judicial courts.

13.Enel Generación Piura (formerly EEPSA)

As of December 31, 2018, Enel Generación Piura has incurred the following tax penalties:

As part of a tax audit procedure for the IGV and IPM on imports for the 2011 fiscal year, SUNAT issued a Notice of Penalty to Enel Generación Piura by means of which it imposed a penalty of PS$6,868,256 (US$2,032,028), whose current default interest to date amounts to PS$5,326,715 (US$1,575,951). It should be noted that the imposition of this penalty is being challenged in the TF, and a provision has been created in the amount of PS$12,194,971 (US$3,607,980).

14.Emgesa

·The ANLA confirmed the penalty imposed on Emgesa amounting to CP$2,503,258,650 (US$770,826), for the alleged non-compliance with the Environmental License, in relation to the removal of wood and biomass resulting from the exploitation for forestry purposes of the reservoir basin of the El Quimbo Hydroelectric Project. A lawsuit for annulment and restoration of rights has been filed and is awaiting decision.

·The CAM ruled on the appeal filed against Resolution No. 2239 of July 29, 2016, in which a penalty of CP$758,864,176 (US$233,676) was imposed on Emgesa for infringement of environmental regulations. The decision held that Emgesa’s activities were undertaken without a prior environmental permit as established by law (Opening of the road above the 720 level of the El Quimbo-PHEQ Hydroelectric Project). The fine was reduced to CP$492,007,073 (US$151,503) A request for conciliation was filed to exhaust the procedural requirement and a lawsuit for annulment and restoration of rights has been filed and is awaiting decision.

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·ENVIRONMENTAL AUTHORITY (CAM): The Regional Autonomous Corporation (CAR) imposed three (3) penalties consisting of a fine of CP$50,670 (approximately US$15.6) each, the following are the resolutions and the facts for which they sanction us :

·RESOLUTION No. 3590 of November 10, 2016: CAM sanctioned the Company for not having the discharge permit for the Montea resettlement, the sanction is for CP$50,670 (approximately US$15.6). There was a demand for Nullity and Restoration of the right and it is pending pronouncement.

·RESOLUTION No. 3653 of November 10, 2016: CAM sanctioned the Company for not having the discharge permit for the resettlement of Santiago and Palacios, the sanction is for CP$50,670 (approximately US$15.6). There was a demand for Nullity and Restoration of the right and it is pending pronouncement.

·RESOLUTION No. 3816 of November 10, 2016: CAM sanctioned the Company for not having the discharge permit for the resettlement of Santiago and Palacios, the sanction is for CP$50,670 (approximately US$15.6). There was a demand for Nullity and Restoration of the right and it is pending pronouncement.

·Vehicle Tax. Imposed on vehicles sold without transfer to buyer. Amount of fine was CP$713,000 (US$220).

15.Codensa

·On February 12, 2018, the Superintendency of Public Services, within the file No. 2016240350600061E, imposed a fine of CP$ 15,624,840 (US $ 4,811) on Codensa S.A. ESP. Considering that the company’s failure to provide the service was because the estimated regulatory compensations for 1 user of the service exceeded the invoiced distribution charge for the respective month. The sanction imposed was appealed in replacement before the same SSPD and is awaiting resolution of the aforementioned appeal.

·On February 28, 2018, the Superintendency of Public Services, within file No. 2015240350600113E, decided to impose a fine of CP$ 62,499,360 (US $ 19,245) on Codensa S.A. ESP. Considering that the company’s failure to provide the service was because the estimated regulatory compensations for 10 users of the service exceeded the invoiced distribution charge for the respective month. The sanction imposed was appealed in replacement before the same SSPD and is awaiting resolution of the aforementioned appeal.

·On April 12, 2018, the Superintendency of Public Services, within file No. 2015240350600082E, decided to fine Codensa S.A. with a fine of CP$ 15,624,840 (US $ 4,811). ESP., Considering that the company’s failure to provide the service because the estimated regulatory compensations for 1 user of the service exceeded the invoiced distribution charge for the respective month. The sanction imposed was appealed in replacement before the same SSPD and is awaiting resolution of the aforementioned appeal.

·On June 30, 2017, Codensa was notified of a decision in which the Superintendency of Industry and Commerce (SIC) fined Codensa CP$241,309,250 (US$74,306) on the basis of a complaint filed by Mrs. Claudia Milena Muñoz Triviño. The decision held that Codensa violated the Colombian personal data protection regime by publishing personal information referring to the complainant (her residence address) on Twitter. On December 13, 2017, the SIC issued a decision of October 4, 2017 by which it resolved the appeals filed against the initial decision, confirming the fine. On December 20, 2017, the fine was paid. An action for nullification and restoration of rights has been filed and is awaiting decision.

·By order No. 26346 of March 15, 2018 the SIC imposed a fine of $ 37,834,434 (US $ 11,650) on Codensa, for 339 days of delay in payment for compensation for defective product to a customer . An appeal for reconsideration was filed against the order that imposed the sanction and Codensa is waiting for the Authority to resolve this appeal.

·Vehicle Tax. Special requirement for value correction valued vehicle. The amount of fine plus interest was CP$229,000 (US $ 71).

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·Lighting tax. Codensa received a fine for provision of information to the Municipality of Itagüí. The amount of the fine was CP$179,624,170 (US$55,312).

·Manta retention 2017 and 2018. Extemporaneity Retentions in municipality. The amount of fine was CP$ 1,607,000 (US $ 495).

·Auto retention ICA ANAPOIMA I and II BIM 2018. Extemporaneity in declarations by change of periodicity in municipal agreement. The amount of fine was CP$ 6,325,000 (US$1,947.65).

16.Sociedad Portuaria Central Cartagena (SPCC):

On July 12, we were notified of the Resolution in which the Superintendence of Ports and Transport confirmed, in the instance of reinstatement, a sanction imposed on SPCC for not reporting the information referred to in Circular 88 of 2016, regarding the vehicle service capacity per day and the storage capacity of each port operation. The amount of the sanction is CP$18,442,925 (US$5,679). Appeal for reinstatement and subsidy of appeal was filed, and in this appeal the sanction was confirmed. Action of Nullity and Restoration of the right was filed and is awaiting a ruling.

In relation to the sanctions described above, the Group has set up provisions for ThUS$40,697 as of December 31, 2018 (see Note 25). Although there are other sanctions that also have associated provisions but are not described in this note because they individually represent small amounts, the Administration considers that the provisions recorded adequately cover the risks for sanctions, so they do not expect them additional liabilities to be released to those already registered.

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39  ENVIRONMENT

Environmental expenses for the years ended December 31, 2018, 2017 and 2016, are as follows:

				12-31-2018
										12-31-2017
							Disbursements	Expected date		Total
Company				Disbursements	Disbursements		amount in the	of	Total	disbursements
incurring the			Project	incurred	capitalized	Expenses	future	disbursements	disbursements	in prior period
cost	Project Name	Description	Status	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
EMGESA	Environmental resource management HIDRA	Environmental resource management HIDRA	In progress	—	—		7,495	12/31/2020	7,495	5,727
EDESUR	Contaminating material	Handling of polluting material	In progress	130	—	130	—		130	5,773
	Preventing activities	Biodiversity protection, sewage water treatment	In progress	301	—	301	—	12/31/2018	301	270
	Environmental studies	Environmental studies	In progress	256	—	256	—	12/31/2018	256	314
ENEL GENERACIÓN PERÚ	Waste management	Hazardous waste management	In progress	314	—	314	—	12/31/2018	314	317
	Mitigation and restoration	Soil and water protection and recovery	In progress	37	—	37	—	12/31/2018	37	41
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	In progress	180	—	180	—	12/31/2018	180	311
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	In progress	220	—	220	—	12/31/2018	220	196
	Preventing activities	Biodiversity protection of the environment	In progress	57	—	57	—	12/31/2018	57	27
	Environmental monitoring	Environmental studies	In progress	63	—	63	—	12/31/2018	63	66
CHINANGO	Waste management	Hazardous waste management	In progress	44	—	44	—	12/31/2018	44	73
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	In progress	426	—	426	—	12/31/2018	426	453
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	In progress	11	—	11	—	12/31/2018	11	14
	PCBs dismantling	With the 2008 Bill 1196 Colombia hosted the Stockholm Convention and that this fact was regulated with the resolution of the Ministry of the environment 222 in December 15, 2011, recognized the provision for dismantling of transformers contaminated with PCBs.	In progress	373	113	260	7	12/31/2018	380	784
CODENSA	Nueva Esperanza environmental compensation	Compensations included in Resolution 1061 and Agreement 017 of 2013 of the Ministry of the Environment and the Autonomous Regional Corporation of Cundinamarca, respectively, where the substitution of the protective and productive forest reserve of the upper basin of the Bogotá River is approved, compromising the company to carry out a compensation and reforestation plan in the construction zone of the Nueva Esperanza, Gran sabana and Compartir sub-station.	In progress	494	481	12	1	12/31/2019	494	170
		Total		2,906	594	2,311	7,503		10,408	14,536

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				12-31-2017
							Disbursements	Expected date
Company				Disbursements	Disbursements		amount in the	of	Total
incurring the			Project	incurred	capitalized	Expenses	future	disbursements	disbursements
cost	Project Name	Description	Status	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
EMGESA	Environmental resource management HIDRA	Environmental resource management HIDRA	In progress	—	—	—	5,727	12/31/2019	5,727
EDESUR	Contaminating material	Investment project in the environment	In progress	5,773	5,773	—	—	—	5,773
		Handling of polluting material	In progress	110	—	110	—	—	110
ENEL GENERACIÓN PERÚ	Preventing activities	Biodiversity protection, sewage water treatment	Completed	270	—	270	—	12/31/2017	270
	Environmental studies	Environmental studies	Completed	314	—	314	—	12/31/2017	314
	Waste management	Hazardous waste management	Completed	317	—	317	—	12/31/2017	317
	Mitigation and restoration	Soil and water protection and recovery	Completed	41	—	41	—	12/31/2017	41
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	Completed	311	—	311	—	12/31/2017	311
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	Completed	196	—	196	—	12/31/2017	196
CHINANGO	Preventing activities	Biodiversity protection of the environment	In progress	27	—	27	—	—	27
	Environmental monitoring	Environmental studies	In progress	66	—	66	—	—	66
	Waste management	Hazardous waste management	In progress	73	—	73	—	—	73
	Mitigation and restoration	Soil and water protection and recovery	In progress	—	—	—	—	—	—
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	In progress	453	—	453	—	—	453
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	In progress	14	—	14	—	—	14
	PCBs dismantling	With the 2008 Bill 1196 Colombia hosted the Stockholm Convention and that this fact was regulated with the resolution of the Ministry of the environment 222 in December 15, 2011, recognized the provision for dismantling of transformers contaminated with PCBs.	In progress	5,825	1,261	7,086	6,609	12/31/2027	784
CODENSA	Nueva Esperanza archaeological rescue	Rescue of archaeological B.C. remains of culture Herrera at substation Nueva Esperanza construction site	Completed	—	—	—	—	—	—
	Nueva Esperanza environmental compensation	Compensations included in Resolution 1061 and Agreement 017 of 2013 of the Ministry of the Environment and the Autonomous Regional Corporation of Cundinamarca, respectively, where the substitution of the protective and productive forest reserve of the upper basin of the Bogotá River is approved, compromising the company to carry out a compensation and reforestation plan in the construction zone of the Nueva Esperanza, Gran sabana and Compartir sub-station.	In progress	132	625	757	302	12/31/2019	170
		Total		13,922	7,659	10,035	12,638		14,646

				12-31-2016
								Disbursements	Expected date
Company				Disbursements	Disbursements			amount in the	of	Total
incurring the			Project	incurred	capitalized	Expense		future	disbursements	disbursements
cost	Project Name	Description	Status	ThUS$	ThUS$	ThUS$		ThUS$	ThUS$	ThUS$
EMGESA	Environmental resource management HIDRA	Environmental partner plan - Thermal power stations	In progress	1,463	1,463	—		—	01/00/1900	1,463
		Environmental partner plan - Hydro power plants	In progress	6,330	6,330	—		106,863	12/31/2020	113,193
	Preventing activities	Biodiversity protection, sewage water treatment	In progress	55	—	55		—	12/31/2016	55
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	In progress	186	—	186		—	12/31/2016	186
ENEL GENERACIÓN PERÚ	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	In progress	393	—	393		—	12/31/2016	393
	Waste management	Hazardous waste management	In progress	303	—	303		—	12/31/2016	303
	Environmental studies	Environmental studies	In progress	10	—	10		—	12/31/2016	10
	Mitigation and restoration	Soil and water protection and recovery	In progress	—	—	—		—	12/31/2016	—
	Preventing activities	Biodiversity protection, sewage water treatment	In progress	—	—	—		—	12/31/2016	—
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	In progress	15	—	15		—	12/31/2016	15
CHINANGO	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	In progress	497	—	497		—	12/31/2016	497
	Waste management	Hazardous waste management	In progress	61	—	61		—	12/31/2016	61
	Environmental studies	Environmental studies	In progress	1	—	1		—	12/31/2016	1
	Preventing activities	Investment in environmental protection	In progress	65	65	—		—	12/31/2016	65
	Contaminating material	Contaminating material management	In progress	105	—	105		—	12/31/2016	105
	PCBs dismantling	Dismantling transformers with PCBS residues	In progress	1,173	1,237	(64	)	6,883	12/31/2027	8,056
CODENSA	Nueva Esperanza archaeological rescue	Rescue of archaeological B.C. remains of culture Herrera at substation Nueva Esperanza construction site	In progress	96	96	—		—	12/31/2019	96
	Nueva Esperanza environmental compensation	Environmental compensation for construction of Nueva Esperanza substation	In progress	1,716	1,545	171		735	12/31/2019	2,451
	Dismantling power plant of Negro River	Contingency power plant of Negro River	In progress	500	—	500		3,594	12/31/2036	4,094
		Total		12,969	10,736	2,233		118,075		131,044

F-220

40.  FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED

As of December 31, 2018, 2017 and 2016, summarized financial information of our principal subsidiaries prepared under IFRS is as follows:

	12-31-2018
	Financial	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
	Statements	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$	ThUS$	ThUS$		ThUS$	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Enel Argentina S.A.	Separate	6,657	139,508	146,165	776	—	145,389		146,165	—	—		—	(618	)	(618	)	2,812		3,657		(669	)	2,988		(138,136	)	(135,148	)
Enel Generación Costanera S.A.	Separate	132,613	267,952	400,565	136,446	99,309	164,810		400,565	162,894	(15,271	)	147,623	103,430		89,235		19,250		108,963		(17,345	)	91,618		(43,235	)	48,383
Enel Generación El Chocón S.A.	Separate	95,054	370,645	465,699	82,599	85,399	297,701		465,699	67,134	(4,675	)	62,459	53,087		32,994		106,969		141,617		(51,466	)	90,151		(130,515	)	(40,364	)
Empresa Distribuidora Sur S.A.	Separate	312,128	1,381,972	1,694,100	710,707	347,653	635,740		1,694,100	1,189,950	(729,223	)	460,727	179,203		77,990		127,247		205,078		(101,101	)	103,977		(347,881	)	(243,904	)
Enel Trading Argentina S.R.L	Separate	14,550	1,008	15,558	13,940	—	1,618		15,558	4,738	(305	)	4,433	1,357		1,083		(2,456	)	(1,370	)	(408	)	(1,778	)	(571	)	(2,349	)
Grupo Dock Sud, S.A.	Consolidated	55,921	263,659	319,580	63,756	55,240	200,584		319,580	94,769	(20,986	)	73,783	58,725		33,999		35,743		69,850		(29,790	)	40,060		(104,651	)	(64,591	)
Grupo Enel Argentina	Consolidated	263,345	916,274	1,179,619	221,534	182,169	775,916		1,179,619	229,458	(19,945	)	209,513	155,467		121,179		140,459		307,883		(72,221	)	235,662		(355,051	)	(119,389	)
Enel Brasil S.A.	Separate	1,681,474	3,892,112	5,573,586	2,720,641	225,312	2,627,633		5,573,586	174	(96	)	78	(46,334	)	(46,374	)	(119,900	)	(106,575	)	44,864		(61,711	)	(441,136	)	(502,847	)
Enel Generación Fortaleza S.A.	Separate	140,483	189,912	330,395	123,850	60,960	145,585		330,395	211,536	(207,475	)	4,061	(6,852	)	(16,483	)	(5,857	)	(22,340	)	7,309		(15,031	)	(25,888	)	(40,919	)
EGP Cachoeira Dourada S.A.	Separate	301,315	103,975	405,290	244,418	3,075	157,797		405,290	540,344	(417,506	)	122,838	109,049		102,351		7,959		110,311		(37,719	)	72,592		(18,168	)	54,424
Enel Green Power Proyectos I (Volta Grande)	Separate	94,170	355,666	449,836	274,015	—	175,821		449,836	81,939	(10,644	)	71,295	68,654		68,653		(15,031	)	53,622		(18,732	)	34,890		(30,953	)	3,937
Enel Cien S.A.	Separate	120,897	183,601	304,498	9,403	18,424	276,671		304,498	82,608	(1,626	)	80,982	72,831		56,219		31,686		87,905		(29,729	)	58,176		(40,853	)	17,323
Compañía de Transmisión del Mercosur S.A.	Separate	9,097	2,196	11,293	50,940	2,493	(42,140	)	11,293	1,193	—		1,193	716		(650	)	(21,535	)	(22,185	)	44		(22,141	)	13,101		(9,040	)
Transportadora de Energía S.A.	Separate	6,912	5,755	12,667	50,780	5,431	(43,544	)	12,667	1,140	—		1,140	591		(986	)	(21,519	)	(22,506	)	(176	)	(22,682	)	13,664		(9,018	)
Enel Distribución Ceará S.A.	Separate	538,216	1,209,995	1,748,211	517,761	440,495	789,955		1,748,211	1,410,602	(1,037,015	)	373,587	213,754		140,035		(17,507	)	122,528		(22,092	)	100,436		(128,063	)	(27,627	)
Enel Distribución Goias S.A.	Separate	611,450	1,964,754	2,576,204	865,349	781,211	929,644		2,576,204	1,510,676	(1,026,864	)	483,812	294,177		172,577		(96,634	)	75,943		(27,646	)	48,297		(152,089	)	(103,792	)
CELG Distribución S.A.	Separate	694,885	2,478,860	3,173,745	613,692	1,154,300	1,405,753		3,173,745	1,541,938	(1,106,151	)	435,787	254,481		157,911		(51,253	)	107,044		318,307		425,351		(199,597	)	225,754
Enel X Brasil	Separate	14,153	9,180	23,333	5,512	42	17,779		23,333	17,882	(8,136	)	9,746	(559	)	(1,412	)	(169	)	(1,581	)	394		(1,187	)	(2,104	)	(3,291	)
Enel Distribución Sao Paulo S.A.	Separate	1,535,494	4,426,898	5,962,392	1,438,355	2,871,158	1,652,879		5,962,392	2,459,201	(1,914,222	)	544,979	243,789		137,736		(98,509	)	39,227		(17,209	)	22,018		(202,092	)	(180,074	)
Grupo Enel Brasil	Consolidated	4,112,113	11,587,158	15,699,271	6,524,502	5,555,695	3,619,074		15,699,271	7,492,092	(5,366,693	)	2,125,399	1,201,286		766,565		(435,467	)	331,484		217,615		549,099		(689,804	)	(140,705	)
Emgesa S.A. E.S.P.	Separate	336,791	2,511,365	2,848,156	510,844	1,032,101	1,305,211		2,848,156	1,259,471	(478,264	)	781,207	707,149		633,075		(101,981	)	531,118		(185,554	)	345,564		(117,250	)	228,314
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	414,711	1,686,783	2,101,494	650,760	598,455	852,279		2,101,494	1,713,801	(1,032,452	)	681,349	522,969		389,002		(57,795	)	331,372		(125,242	)	206,130		(81,177	)	124,953
Enel Perú, S.A.C.	Separate	36,807	1,376,103	1,412,910	69,295	10,460	1,333,155		1,412,910	—	—		—	337		337		(4,852	)	185,519		—		185,519		(56,062	)	129,457
Enel Generación Perú S.A.	Separate	333,468	914,287	1,247,755	169,579	234,383	843,793		1,247,755	653,276	(336,615	)	316,661	257,625		209,490		13,325		263,975		(69,105	)	194,870		(35,507	)	159,363
Chinango S.A.C.	Separate	5,798	137,059	142,857	7,946	25,562	109,349		142,857	54,434	(15,469	)	38,965	33,910		29,643		(255	)	29,388		(8,562	)	20,826		(4,445	)	16,381
Enel Generación Piura S.A.	Separate	85,080	175,196	260,276	51,046	68,377	140,853		260,276	89,395	(37,266	)	52,129	42,112		30,028		(4,368	)	25,685		(8,003	)	17,682		(6,155	)	11,527
Enel Distribución Perú S.A.	Separate	112,287	1,210,429	1,322,716	268,883	431,856	621,977		1,322,716	912,950	(610,701	)	302,249	232,137		175,848		(22,150	)	153,693		(49,024	)	104,669		(25,666	)	79,003
Grupo Enel Perú	Consolidated	488,824	2,401,685	2,890,509	490,068	770,021	1,630,420		2,890,509	1,505,635	(798,330	)	707,305	564,020		443,246		(18,583	)	451,681		(134,059	)	317,622		(127,835	)	189,787

F-221

	12-31-2017
	Financial	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
	Statements	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$	ThUS$	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Enel Argentina S.A.	Separate	5,657	275,369	281,026	490	—	280,536		281,026	—	—		—		(651	)	252,340		1,135		256,836		(185	)	256,651		(45,736	)	210,915
Enel Generación Costanera S.A.	Separate	119,110	204,611	323,721	137,870	142,832	43,019		323,721	152,399	(8,612	)	143,787		76,145		40,137		(27,529	)	13,009		6,625		19,634		(8,824	)	10,810
Enel Generación El Chocón S.A.	Separate	81,241	297,979	379,220	68,075	84,620	226,525		379,220	58,459	(6,837	)	51,622		38,115		34,920		54,815		91,041		2,392		93,433		(39,053	)	54,380
Empresa Distribuidora Sur S.A.	Separate	396,740	830,423	1,227,163	919,538	298,111	9,514		1,227,163	1,276,849	(740,418	)	536,431		157,730		150,952		(176,791	)	(25,712	)	36,981		11,269		(4,442	)	6,827
Enel Trading Argentina S.R.L	Separate	23,397	188	23,585	22,479	—	1,106		23,585	4,271	(583	)	3,688		(457	)	(543	)	416		(127	)	(307	)	(434	)	(242	)	(676	)
Grupo Dock Sud, S.A.	Consolidated	63,803	147,504	211,307	50,858	33,693	126,756		211,307	88,071	(12,070	)	76,001		55,486		39,097		24,711		63,907		(17,212	)	46,695		(23,122	)	23,573
Grupo Enel Argentina	Consolidated	228,046	506,432	734,478	206,678	225,111	302,689		734,478	209,346	(15,449	)	193,897		113,259		74,056		31,581		112,122		7,771		119,893		(57,436	)	62,457
Enel Brasil S.A.	Separate	386,459	3,395,350	3,781,809	201,292	392,169	3,188,348		3,781,809	—	(256	)	(256	)	(44,430	)	(44,561	)	18,874		182,137		(894	)	181,243		(97,449	)	83,794
Enel Generación Fortaleza S.A.	Separate	114,507	204,939	319,446	71,632	61,310	186,504		319,446	261,358	(146,668	)	114,690		103,174		88,737		(804	)	87,933		(29,488	)	58,445		(8,669	)	49,776
EGP Cachoeira Dourada S.A.	Separate	231,833	129,520	361,353	221,039	1,443	138,871		361,353	503,093	(372,087	)	131,006		115,811		107,414		520		107,935		(37,023	)	70,912		(9,035	)	61,877
Enel Green Power Proyectos I (Volta Grande)	Separate	27,586	416,760	444,346	5,170	261,883	177,293		444,346	8,546	(759	)	7,787		7,473		7,473		(753	)	6,720		(1,027	)	5,693		(5,667	)	26
Enel Cien S.A.	Separate	65,440	273,718	339,158	12,165	60,455	266,538		339,158	88,727	(2,654	)	86,073		75,234		58,479		9,371		67,850		(23,180	)	44,670		(6,945	)	37,725
Compañía de Transmisión del Mercosur S.A.	Separate	15,560	789	16,349	19,603	26,531	(29,785	)	16,349	1,465	—		1,465		881		753		(12,405	)	(11,651	)	—		(11,651	)	5,543		(6,108	)
Transportadora de Energía S.A.	Separate	12,373	1,466	13,839	20,856	27,122	(34,139	)	13,839	1,378	—		1,378		513		348		(12,955	)	(12,606	)	(50	)	(12,656	)	6,385		(6,271	)
Enel Distribución Ceará S.A.	Separate	568,437	1,209,306	1,777,743	546,763	388,085	842,895		1,777,743	1,453,275	(1,022,360	)	430,915		262,901		191,446		(24,074	)	167,693		(30,373	)	137,320		(22,054	)	115,266
Enel Distribución Rio S.A.	Separate	723,616	2,145,932	2,869,548	831,455	1,006,034	1,032,059		2,869,548	1,661,756	(1,206,285	)	455,471		241,314		109,275		(153,947	)	(44,041	)	13,330		(30,711	)	(28,186	)	(58,897	)
CELG Distribución S.A.	Separate	666,468	2,365,423	3,031,891	664,476	1,305,858	1,061,557		3,031,891	1,536,277	(1,133,252	)	403,025		144,544		41,504		(72,334	)	(30,826	)	40,895		10,069		(16,279	)	(6,210	)
Enel Soluciones S.A.	Separate	10,809	6,425	17,234	4,924	634	11,676		17,234	18,399	(9,826	)	8,573		798		183		(910	)	(726	)	1,095		369		(471	)	(102	)
Grupo Enel Brasil	Consolidated	2,505,682	6,810,297	9,315,979	2,157,412	3,398,528	3,760,039		9,315,979	5,174,413	(3,540,939	)	1,633,474		908,152		560,994		(250,488	)	311,459		(66,715	)	244,744		(76,845	)	167,899
Emgesa S.A. E.S.P.	Separate	327,288	2,696,892	3,024,180	399,751	1,335,485	1,288,944		3,024,180	1,159,789	(396,303	)	763,486		682,009		610,958		(119,198	)	492,089		(191,743	)	300,346		(1,000	)	299,346
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	402,852	1,668,741	2,071,593	547,780	636,505	887,308		2,071,593	1,542,994	(872,528	)	670,466		520,930		411,666		(55,757	)	356,055		(144,932	)	211,123		1,953		213,076
Enel Perú, S.A.C.	Separate	11,481	1,448,680	1,460,161	76,002	10,912	1,373,247		1,460,161	—	—		—		(2,269	)	(2,271	)	(123	)	29,500		—		29,500		7,964		37,464
Enel Generación Perú S.A.	Separate	330,595	980,250	1,310,845	175,026	249,370	886,449		1,310,845	595,379	(299,959	)	295,420		240,666		174,623		(7,835	)	189,052		(52,740	)	136,312		28,646		164,958
Chinango S.A.C.	Separate	7,621	144,813	152,434	16,351	25,269	110,814		152,434	52,094	(14,169	)	37,925		31,518		27,203		(448	)	26,755		(7,705	)	19,050		3,775		22,825
Enel Generación Piura S.A.	Separate	80,426	189,558	269,984	53,974	86,622	129,388		269,984	87,519	(37,928	)	49,591		39,492		26,869		(1,293	)	25,581		(8,075	)	17,506		4,618		22,124
Enel Distribución Perú S.A.	Separate	169,384	1,156,086	1,325,470	299,001	440,185	586,284		1,325,470	884,291	(583,785	)	300,506		230,065		174,257		(24,278	)	151,284		(46,154	)	105,130		13,416		118,546
Inversiones Distrilima S.A.	Separate	—	—	—	—	—	—		—	—	—		—		(1	)	(1	)	484		15,986		(160	)	15,826		2,501		18,327
Generandes Perú S.A.	Separate	—	—	—	—	—	—		—	—	—				(12	)	(12	)	15		12,955		4		12,959		9,705		22,664
Grupo Eléctrica Cabo Blanco, S.A.C.	Consolidated	—	—	—	—	—	—		—	29,653	(12,030	)			14,433		11,699		1,127		11,167		(2,840	)	8,327		4,832		13,159
Grupo Enel Perú	Consolidated	458,175	2,477,110	2,935,285	487,028	812,357	1,635,900		2,935,285	949,802	(487,661	)			363,132		265,430		(23,071	)	249,116		(76,548	)	172,568		(21,614	)	150,954
Grupo Distrilima	Consolidated	—	—	—	—	—	—		—	303,228	(204,910	)			76,389		58,184		(7,357	)	51,465		(15,874	)	35,591		17,636		53,227
Grupo Generandes Perú	Consolidated	—	—	—	—	—	—		—	197,769	(93,827	)	103,942		84,435		64,530		(4,006	)	62,197		(18,304	)	43,893		31,813		75,706

	12-31-2016
	Financial	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
	Statements	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$		ThUS$	ThUS$	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Chilectra Américas S.A.	Consolidated	—	—	—	—	—	—		—	—	—		—		(2,575	)	(2,575	)	2,350		16,623		(192	)	16,431		74,224		90,655
Inversiones Distrilima S.A.	Separate	26,813	71,595	98,408	106	—	98,303		98,409	—	—		—		(8	)	(8	)	1,583		21,327		(441	)	20,886		(3,999	)	16,887
Enel Distribución Perú S.A.	Separate	190,383	1,045,207	1,235,590	294,325	442,113	499,152		1,235,590	874,119	(590,819	)	283,300		213,269		166,057		(24,648	)	141,442		(49,021	)	92,421		(20,003	)	72,418
Endesa Américas S.A.	Separate	—	—	—	—	—	—		—	2	—		2		(10,134	)	(10,134	)	2,213		90,965		(74	)	90,891		(7	)	90,884
Enel Argentina S.A.	Separate	6,372	67,352	73,724	4,175	—	69,548		73,723	—	—		—		(121	)	(121	)	867		746		(212	)	534		(14,367	)	(13,833	)
Enel Generación Costanera S.A.	Separate	64,020	216,261	280,281	99,523	148,582	32,175		280,280	138,367	(7,702	)	130,665		73,746		48,470		(33,469	)	15,303		1,563		16,866		(6,894	)	9,972
Enel Generación El Chocón S.A.	Separate	83,507	316,261	399,768	107,282	77,218	215,267		399,767	42,185	(4,796	)	37,389		26,000		22,985		48,748		73,083		(25,191	)	47,892		(55,725	)	(7,833	)
Emgesa S.A. E.S.P.	Separate	289,865	2,712,409	3,002,274	422,919	1,418,040	1,161,315		3,002,274	1,163,428	(437,977	)	725,451		653,176		555,783		(146,729	)	409,125		(159,720	)	249,405		10,928		260,333
Generandes Perú S.A.	Separate	1,098	321,417	322,515	83	—	322,431		322,514	2	—		2		(26	)	(26	)	287		24,106		(75	)	24,031		(14,335	)	9,696
Enel Generación Perú S.A.	Separate	261,485	970,275	1,231,760	195,194	261,198	775,367		1,231,759	538,018	(298,284	)	239,734		164,309		107,145		(6,493	)	134,037		(70,132	)	63,905		(33,312	)	30,593
Chinango S.A.C.	Separate	34,081	142,768	176,849	15,970	50,882	109,997		176,849	54,697	(14,387	)	40,310		33,488		28,950		(820	)	39,595		(13,619	)	25,976		(3,513	)	22,463
Enel Brasil S.A.	Separate	271,399	1,304,479	1,575,878	95,966	11,988	1,467,924		1,575,878	—	(9	)	(9	)	(39,824	)	(44,859	)	68,352		149,406		11,146		160,552		178,487		339,039
Central Generadora Termoeléctrica Fortaleza S.A.	Separate	69,443	201,866	271,309	61,492	1,103	208,714		271,309	238,213	(143,920	)	94,293		81,487		73,157		839		73,995		(26,869	)	47,126		27,117		74,243
EGP Cachoeira Dourada S.A.	Separate	136,712	132,381	269,093	117,359	1,381	150,352		269,092	288,156	(150,561	)	137,595		125,785		118,233		6,490		124,723		(42,655	)	82,068		19,723		101,791
Enel Cien S.A.	Separate	58,663	293,459	352,122	65,338	39,623	247,161		352,122	77,941	(2,959	)	74,982		66,545		50,787		(8,095	)	42,692		(14,583	)	28,109		29,453		57,562
Compañía de Transmisión del Mercosur S.A.	Separate	17,227	1,015	18,242	15,002	26,891	(23,652	)	18,241	1,570	—		1,570		986		841		(9,233	)	(8,392	)	—		(8,392	)	5,499		(2,893	)
Enel Distribución Ceará (ex Coelce S.A.)	Separate	482,880	1,048,701	1,531,581	419,383	340,877	771,321		1,531,581	1,201,906	(802,341	)	399,565		244,744		159,771		(21,213	)	138,836		(23,975	)	114,861		89,729		204,590
Enel Solucoes S.A.	Separate	6,136	4,945	11,081	12,476	—	(1,395	)	11,081	9,744	(6,030	)	3,714		(2,095	)	(2,371	)	(438	)	(2,809	)	54		(2,755	)	33		(2,722	)
Enel Distribución Río S.A. (ex Ampla Energía S.A.)	Separate	531,919	1,952,235	2,484,154	641,593	1,128,351	714,210		2,484,154	1,313,724	(903,880	)	409,844		174,022		40,585		(129,209	)	(90,146	)	26,620		(63,526	)	90,351		26,825
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	411,321	1,493,800	1,905,121	548,849	510,364	845,909		1,905,122	1,387,098	(795,079	)	592,019		464,379		374,945		(52,379	)	315,669		(135,935	)	179,734		(131	)	179,603
Empresa Distribuidora Sur S.A.	Separate	378,242	666,194	1,044,436	742,583	299,166	2,687		1,044,436	991,979	(453,123	)	538,856		173,500		142,843		(163,671	)	(20,771	)	(10,370	)	(31,141	)	(8,380	)	(39,521	)
Generalima S.A.C.	Separate	8,716	58,327	67,043	33,257	9,849	23,937		67,043	1	—		1		(13,718	)	(13,720	)	(1,967	)	(15,687	)	—		(15,687	)	(1,739	)	(17,426	)
Endesa Cemsa, S.A.	Separate	25,704	192	25,896	24,114	—	1,782		25,896	3,224	(347	)	2,877		(268	)	(397	)	49		(319	)	(173	)	(492	)	(635	)	(1,127	)
Grupo Dock Sud, S.A.	Consolidated	48,286	159,109	207,395	42,865	54,573	109,956		207,394	129,002	(79,115	)	49,887		36,293		19,316		11,333		30,674		(10,709	)	19,965		(29,312	)	(9,347	)
Eléctrica Cabo Blanco, S.A.C.	Consolidated	97,063	165,037	262,100	51,201	89,795	121,104		262,100	97,309	(42,312	)	54,997		44,378		36,174		(2,444	)	33,726		(10,440	)	23,286		(4,496	)	18,790
Grupo Distrilima	Consolidated	197,936	1,045,207	1,243,143	275,170	442,113	525,859		1,243,142	874,119	(590,819	)	283,300		213,261		166,049		(23,065	)	143,017		(49,463	)	93,554		(21,198	)	72,356
Grupo Endesa Américas	Consolidated	739,600	5,274,797	6,014,397	844,423	1,953,633	3,216,341		6,014,397	1,582,909	(619,201	)	963,708		771,871		611,033		(146,233	)	569,842		(206,257	)	363,585		198,867		562,452
Grupo Enel Brasil	Consolidated	1,377,303	3,685,719	5,063,022	1,235,334	1,207,825	2,619,863		5,063,022	2,811,032	(1,688,731	)	1,122,301		652,275		396,574		(101,824	)	293,506		(70,272	)	223,234		332,372		555,606
Grupo Gerenandes Perú	Consolidated	296,618	1,094,096	1,390,714	211,201	312,080	867,433		1,390,714	592,368	(312,321	)	280,047		197,770		136,069		(7,026	)	166,081		(83,826	)	82,255		(19,250	)	63,005
Grupo Enel Argentina	Consolidated	153,273	535,021	688,294	210,237	223,513	254,545		688,295	179,030	(12,498	)	166,532		99,597		71,306		15,731		88,468		(23,861	)	64,607		(80,989	)	(16,382	)

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41.SUBSEQUENT EVENTS

1.     Enel Américas S.A.

i.On February 27, 2019, Enel Américas S.A. announced in a significant event filing that it had summoned an Extraordinary Shareholders’ Meeting of the Company to be held on April 30, 2019.

The Extraordinary Shareholders’ Meeting will consider and decide on a capital increase for up to ThUS$ 3,500,000 which is intended to take advantage of investment opportunities through merger and acquisition transactions and acquiring minority interests in existing investments, and to provide funds to its subsidiary Enel Brasil S.A., through a subsequent capital increase in Enel Brasil S.A. and / or one or more loans thereto, to enable Enel Brasil S.A. to repay a loan provided by Enel Finance International N.V., which replaced debt of Enel Brasil S.A. with banks, associated with the acquisition of the Brazilian company Enel Distribución Sao Paulo S.A., as well as the restructuring of the liabilities of the pension funds of Enel Distribución Sao Paulo and the reduction of contingent funds.

Specifically, the matters that will be submitted for the consideration and decision of the Extraordinary Shareholders’ Meeting will be the following:

1.Capital Increase. Increase the capital of Enel Américas in the amount of up to ThUS$ 3,500,000 through the issuance of the corresponding number of newly paid shares, all of the same series and without nominal value, at the price and other conditions approved by the Extraordinary Shareholders’ Meeting.

The offering price shall be calculated as the weighted average price of Enel Américas shares on the stock exchanges of Chile, corresponding to the five trading days preceding the date of the start of the first preemptive rights offering period, with a discount of 5%. For these purposes, the Extraordinary Shareholders’ Meeting will delegate to the Board of Directors of the Company the calculation of the offering price, applying the aforementioned formula, provided that the offering is commenced within 180 days following the date of the Extraordinary Shareholders’ Meeting, in accordance with article 23 of the Chilean Corporations Act Rules.

Likewise, it will be established that the offering of shares must be made in the first instance within the preemptive rights offering period required by article 25 of the Chilean Corporations Act. The shares not subscribed during this first preemptive rights offering period and those corresponding to fractions resulting from the apportionment among the shareholders, will be offered in a second rights offering period only to those shareholders or third parties that have subscribed for shares during the first preemptive rights offering period, pro rata based on the shares subscribed and paid during the aforementioned first preemptive rights offering period, and at the same price per share as they are offered during the first preemptive rights offering period.

2.Amendment of Bylaws. Amend the bylaws of Enel Américas, in order to reflect the agreement regarding the capital increase, replacing the Fifth and First Transitory Articles of the bylaws for such purposes.

3.Powers to the Board of Directors of Enel Américas for the registration of the new shares in the Securities Registry of the Financial Market Commission and in the local stock exchanges, the registration of the new shares and the new American Depositary Shares with the Securities and Exchange Commission of the United States of America and the New York Stock Exchange (NYSE), and other powers in relation to the capital increase. To empower the Board of Directors of Enel Américas to perform all actions necessary for the capital increase, including requesting the registration of the new shares representing the capital increase in the Securities Registry of the Financial Market Commission and in the local stock exchanges, as well

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as the registration of the new shares and the new American Depositary Shares with the Securities and Exchange Commission of the United States of America and the New York Stock Exchange (NYSE), to carry out the appropriate actions for the effectuation of the capital increase and, in general, to perform all other acts related to the capital increase, adopting all other agreements that are necessary to formalize and make effective the statutory modifications of Enel Américas described above, with broad powers.

4.Other matters related to the Capital Increase. Agree on those other aspects of the capital increase described that the Extraordinary Shareholders’ Meeting deems in the best interests to approve and that are necessary and ancillary to this transaction.

ii.On March 1, 2019, Enel Américas S.A. supplemented the significant event filed on February 27, 2019 (see item i above) with the following information:

1.Amount or percentage of the capital increase that will be used for investment opportunities through merger and acquisition transactions and acquisitions of minority interests.

The proceeds raised through the proposed capital increase will be used as follows:

·US$ 2,650 million will be used to provide funds to the subsidiary Enel Brasil S.A. through a subsequent capital increase in the latter and/or through one or more loans to it, in order to enable Enel Brasil S.A. to repay a loan provided by Enel Finance International N.V., which replaced debt of Enel Brasil S.A. with banks, associated with the acquisition of the Brazilian company Enel Distribución Sao Paulo .

·US$ 850 million will be used to restructure the pension funds liabilities of Enel Distribución Sao Paulo and for the reduction of contingent funds or provisions for litigation in Brazil.

Because of this, it is not contemplated that the proceeds raised through the capital increase would be used in potential merger and acquisition transactions or acquisitions of minority interests, but upon completion of this capital increase Management will be positioned to take advantage of investment opportunities by strengthening the balance sheet of Enel Américas S.A.

2.Type of merger and acquisition transactions and acquisition of minority interests to which the Significant Event refers.

In the context of the purpose of the capital increase indicated in the Significant Event filed on February 27, 2019, this transaction would grant Enel Américas S.A. a financial position that would allow it to issue debt to finance merger and acquisition transactions and acquisitions of minority interests. The potential merger and acquisition transactions and acquisitions of minority interests that would be evaluated are the following:

·Acquisition of minority interests in any of the current subsidiaries of Enel Américas S.A., which as of today represent opportunities for up to US$ 2 billion.

·Eventual acquisition of companies engaged in the electricity business in the markets where Enel Américas S.A. participates through its subsidiaries (Argentina, Brazil, Colombia and Peru).

3.What would be the restructuring of liabilities of the pension funds and reduction of contingent funds in Brazil.

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Restructuring of pension fund liabilities: Enel Distribución Sao Paulo sponsors additional retirement and pension benefit plans for its current and former employees and their beneficiaries, with FUNCESP being the entity responsible for administering said benefit plans.  FUNCESP is Brazil’s largest private pension fund (the fourth largest, including government-controlled pension funds), is multi- funded and manages assets of approximately US$ 7.5 billion for about 50 thousand people, of which 17 thousand people relate to Enel Distribución Sao Paulo.

The main pension fund risks that impact Enel Distribución Sao Paulo are related to discount rates, mortality table and expected rates of return on assets. The actuarial obligations as of December 31, 2018, were US$ 3.3 billion and the deficit was US$ 1.0 billion.

In order to verify the impact on the actuarial liabilities, the following table illustrates a sensitivity analysis of the actuarial assumptions, considering a variation of +/- 0.25% in the discount rate.  The quantitative result as of December 31, 2018 is presented as follows:

	Discount rate
Sensitivity	+ 0.25%	-0.25%
Impact on defined benefit	-0.07 Billion US$	+0.07 Billion US$
Total defined benefit obligation	3.2 Billion US$	3.3 Billion US$

If current plan’s conditions are maintained without modification, the deficit is expected to grow because of the increase in life expectancy and/or the reduction of the discount rate of pension fund liabilities.  In order to mitigate this exposure, Enel Distribución Sao Paulo has developed a voluntary migration plan from the Defined Benefit plans that Enel Distribución Sao Paulo currently has to Defined Contribution plans, mitigating the risk of an increasing deficit because of the future actuarial assumptions, and the eventual restructuring of the debt contracts of Enel Distribución Sao Paulo with FUNCESP.  This plan should be evaluated by competent bodies in the coming months.

Contingent funds or provisions for litigation in Brazil:  The distributors controlled by Enel Américas S.A. in Brazil, through Enel Brasil S.A. - Enel Distribución Sao Paulo, Enel Distribuicao Rio, Enel Distribuicao Goias and Enel Distribuicao Ceará - have approximately 70 thousand litigation matters as of December 2018.  In the balance sheets of these companies, US$ 600 million are provisioned.  According to Brazilian rules, most of these liabilities are subject to increase at a rate of 1% monthly over the inflation index, generating an excessive financial burden, and therefore reduces significantly the net result of the companies and distribution of dividends to the shareholders, draining the cash flows of the companies.

Based on the use of “analytics” on the behavior of the active parties in mass litigations, a system capable of identifying potential agreements with these active parties is being implemented, and, for future cases, to avoid new litigation.  This plan requires funds for US$ 150 million, which will be used for the management of agreements and the implementation of technological platforms.  This would provide an initial expected benefit of a 30% reduction in the amount of the provisions, and a reduction in the volume of new litigation based on the pilot program last implemented in 2018.

4.Financial effects that the aforementioned capital increase could have.

The following financial effects are expected as a consequence of the proposed capital increase:

·Improvement of the profit and cash flow of Enel Américas S.A.:  as Enel Brasil S.A.’s debt with Enel Finance International N.V. is repaid, the restructuring of the pension funds liabilities and the reduction of contingent funds or provisions for litigation in Brazil, the financial burden would be considerably alleviated, which would imply a lower financial expense and therefore a higher profit

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and an improvement in cash flow, both in Enel Brasil S.A. and in Enel Américas S.A., which consolidates the former.

·Higher dividends to be received in Enel Américas S.A.: by increasing Enel Brasil S.A.’s profits and improving its cash flow, this would increase its dividend distribution, which would allow Enel Américas S.A. to receive higher dividends.

·Greater credit capacity: as the level of debt decreases, Enel Américas S.A.’s credit indicators would improve considerably, which would allow greater flexibility to raise debt in the financial markets.

5.Any other information that is considered relevant for the adequate understanding and evaluation of the significant event.

In order to complete other information that we consider relevant for a better understanding of the transaction, we point out that on February 27, 28 and March 1, the 3 international credit rating agencies that cover Enel Américas S.A. as well as a local credit agency, published their corresponding press releases analyzing the transaction.

The aforementioned rating agencies are the following:

· Internationals: Standard & Poors, FITCH Rating and Moody’s.

· National: Feller Rate

There was unanimity of the four credit rating agencies in qualifying this transaction as “credit positive” for Enel Américas S.A. highlighting, among other things:

·“Proposed capital increase of up to US$3.5 billion is a positive credit and will help solidify its investment grade rating”

·“Once completed, the transaction is likely to have an overall positive impact on Enel S.p.A’s and Enel Américas’ credit metrics”

·“Enel Américas’ Potential US$ 3.5 billion capital increase is consistent with its aim to maintain strong financial profile”

·“We consider the proposed transaction to be a favorable development for Enel Américas’ credit quality because it should strengthen the company’s short-term credit metrics”

·“Proposed capital increase is credit positive for Enel Américas as it will reduce leverage”

·“This injection of funds is positive for the company, especially for the subsidiary Enel Brasil S.A., which would result in greater efficiencies and a deleveraging of the financial profile”.

iii.On April 10, 2019 our parent company Enel S.p.A., announced in a significant event filing, reporting a 4.62% increase in its participation in the share capital of Enel Américas S.A. through 1,707,765,225 shares of common stock; and 18,931,352 American depositary shares (“ADSs”), each representing 50 shares of common stock, having reached 56.42% of it.

In the same significant event, and in relation to the capital increase in progress, announced in a significant event issued on February 27, 2019, supplemented on March 1, 2019 (see i and ii above), Enel S.p.A., informs of its intention to vote in favor of its approval at the Extraordinary Shareholders’ Meeting

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convened for April 30, 2019; Likewise, Enel SpA expresses its intention, if the capital increase is approved and subject to market conditions, to subscribe the shares issued by Enel Américas, in proportion to its current shareholding, that is, 56.42%, through the exercise of their pre-emptive subscription rights.

iv.On April 25, 2019 Enel Américas S.A. announced in a significant event filing that the Board of Directors of the company unanimously agreed to suggest the following adjustment in relation to the capital increase to be discussed at the Company’s Extraordinary Shareholders’ Meeting to be held on April 30, 2019, in San Isidro No. 74, in the comuna and City of Santiago, immediately after the Ordinary Shareholders’ Meeting.

After an intense financial marketing activity and  after having  gathered the relevant market opinions with the view to obtaining the widest possible consensus and support  in relation to the transaction, it has been suggested that the  shareholders should agree on the sum of US$ 3,000,000,000 (three billion US dollars)  as  the amount of the capital increase  whose aim will  be to permit Enel Brasil S.A. to pay  Enel Finance International N.V., a loan made by the latter and which replaced Enel Brasil S.A.’s debt with banks, linked to the acquisition of the Brazilian company Eletropaulo Metropolitana Eletricidade de Sao Paulo S.A., as well as the restructuring that company’s pension fund liabilities.

The resulting improvement of the Company’s capital structure will allow it to take advantage of investment opportunities through mergers and acquisitions and minority investors buyout.

2.Enel Distribución Goiás

Through Law No. 17,555 of January 20, 2012, the State of Goiás in Brazil created the Contribution Fund (FUNAC) for Enel Distribución Goiás, with the purpose of accumulating and allocating financial resources to reimburse Enel Distribución Goiás for payments of contingencies of any nature originating prior to the sale of shareholding control in CELG (now known as Enel Distribución Goiás) held by Eletrobrás. This mechanism was created in 2012 for the purpose of reimbursing Enel Distribución Goiás for the contingencies whose triggering event occurred during the coverage period until January 2015. The reimbursement must be paid in cash by the State Treasury. See Note 11.

Law No. 19,473 created the State Energy Policy for the maintenance, improvement and expansion of the energy distribution network in Goiás, establishing a mechanism to strengthen the FUNAC reimbursement mechanism through ICMS credits with the same goals and coverage period (until January 2015) as Law No. 17,555 discussed above. Under the mechanism established by Law No. 19,473, the reimbursement is made through the recognition of ICMS credits (VAT tax credits) instead of cash payments made by the State Treasury. This law was an alternative guarantee offered by the State of Goiás to potential investors at the time of privatization of CELG, due to investors’ legal assessment of FUNAC.

On February 6, 2019, Law No. 20,416 amended Law No. 17,555 (which created the FUNAC) and Law No. 19,473, reducing the coverage period for contingencies from January 2015 to April 2012. It should be noted that the State of Goiás was obligated to comply with all the obligations established in Law No. 17,555 and, therefore, Law No. 20,416, by creating conditions not provided for in the legal framework of the privatization process, violates the perfected legal act, the right acquired and the legal security essential for the stability of relations between the investor and the State, which is prohibited by Brazilian law. In addition, the conditions established under Law No. 19,473 by regulations of the Brazilian tax framework cannot be modified unilaterally by the State.

Enel Brasil S.A. and Enel Distribución Goiás filed a request for a security order against the State of Goiás for the reimbursement of the amounts due to Enel Distribution Goiás in accordance with Law No. 17,555 (FUNAC) and Law No. 19,473 (VAT tax credits), which should continue to be applied normally. The judge rejected the request and Enel Brasil S.A. and Enel Distribución Goiás appealed that decision, which is still pending. There has been no decision of first instance. In addition, on April 16, 2019, the Legislative Assembly of Goiás approved Matter 757/19, and the Governor of the State of Goiás has 15 working days to enact the law or issue a veto. The veto can be rejected by the Assembly within 30 days. Enacting the law or rejecting the Governor’s veto would fully repeal Law No. 19,473, which would extinguish the reimbursement mechanism for ICMS credits. If this new law were to take effect, Enel Brasil S.A. and Enel Distribución Goiás will take the appropriate judicial measures to reject the revocation of Law No. 19,473, based on the same arguments related to the framework of privatization, legal security and regulations of the Brazilian tax framework.

There have been no other subsequent events between January 1, 2019 and the issuance date of these financial statements.

F-227

APPENDIX 1 DETAILS 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:

		12-31-2018	12-31-2017
ASSETS	Foreign currency	ThUS$	ThUS$
CURRENT ASSETS
Cash and cash equivalents		1,904,285	1,472,763
	Dollars	513,667	306,590
	Euros	2,436	7,605
	Real	633,635	470,360
	CP	372,361	322,022
	Soles	129,263	145,950
	Argentine Peso	101,209	219,761
	$ non-adjustable	151,714	475
Other current financial assets		210,393	110,352
	Dollars	46,395	—
	Real	139,462	64,924
	CP	24,434	44,890
	Soles	—	—
	Argentine Peso	—	412
	$ non-adjustable	102	126
Other non-current financial assets		307,732	283,632
	Dollars	5,198	7,986
	Euros	—	4
	Real	220,661	229,975
	CP	8,850	7,745
	Soles	46,391	22,861
	Argentine Peso	21,088	14,484
	$ non-adjustable	5,544	577
Trade and other current receivables		3,551,022	2,377,789
	Dollars	32,184	51,232
	Euros	—	—
	Real	2,801,406	1,541,468
	CP	217,987	255,373
	Soles	116,631	148,459
	Argentine Peso	381,858	377,666
	$ non-adjustable	956	3,591
Current accounts receivable from related parties		14,337	7,403
	Dollars	1,510	1,525
	Euros	2,052	1,429
	Real	4,765	2,081
	CP	1,203	1,444
	Soles	2,220	37
	Argentine Peso	476	763
	$ non-adjustable	2,111	124
Inventories		339,398	246,089
	Dollars	5,235	2,063
	Euros	208	141
	Real	209,114	134,993
	CP	57,118	48,142
	Soles	43,532	41,860
	Argentine Peso	24,191	18,890
Current tax assets		50,994	47,393
	Real	48,333	35,303
	CP	4	6
	Soles	2,282	3,516
	Argentine Peso	160	452
	$ non-adjustable	215	8,116
Total current assets other than assets or groups of assets for disposal classified as held for sale or as held for distribution to owners		5,825	—
	CP	5,825
	Dollars	—	—
TOTAL CURRENT ASSETS		6,383,986	4,545,421

F-228

		12-31-2018	12-31-2017
ASSETS	Foreign currency	ThUS$	ThUS$
NON-CURRENT ASSETS
Other non-current financial assets		2,796,475	1,752,267
	Dollars	34,133	—
	Real	2,761,730	1,751,136
	CP	598	1,103
	Soles	14	—
	Argentine Peso		28
Other non-current non-financial assets		1,140,708	560,426
	Dollars	2,165
	Real	1,125,449	546,435
	CP	8,753	7,159
	Argentine Peso	927	4,429
	$ non-adjustable	3,414	2,403
Trade and other non-current receivables		906,508	616,793
	Dollars	242,409	363,077
	Real	457,161	177,844
	CP	40,003	37,100
	Argentine Peso	166,877	38,648
	$ non-adjustable	58	124
Non-current accounts receivable from related parties		1,652	2,845
	Real	1,544	2,590
	Argentine Peso	108	255
Investments accounted for using the equity method		2,596	2,747
	CP		—
	Argentine Peso	2,596	2,747
Intangible assets other than goodwill		5,827,289	3,682,479
	Real	5,653,824	3,546,461
	CP	95,095	77,886
	Soles	56,200	40,504
	Argentine Peso	22,170	17,628
Goodwill		1,205,570	713,175
	Dollars		—
	Real	963,060	481,168
	CP	19,245	20,935
	Soles	197,010	205,516
	Argentine Peso	26,255	5,556
Property, plant and equipment		8,686,827	8,092,467
	Dólares	43	21,073
	Real	436,204	501,029
	CP	4,050,353	4,242,687
	Soles	2,345,485	2,340,496
	Argentine Peso	1,854,742	987,182
Investment property		11,708	—
	Real	11,708	—
Deferred tax assets		433,037	200,371
	Real	433,026	149,727
	CP	1	2
	Argentine Peso	10	50,642
	$ non-adjustable		—
TOTAL NON CURRENT ASSETS		21,012,370	15,623,570
TOTAL ASSETS		27,396,356	20,168,991

F-229

		12-31-2018		12-31-2017
		Less than 90  days	91 days to 1 year	Less than 90 days	91 days to 1 year
LIABILITIES	Foreign currency	ThUS$	ThUS$	ThUS$	ThUS$
CURRENT LIABILITIES
Other current financial liabilities		547,436	1,100,663	214,719	475,049
	Dollars	103,871	689,178	69,430	61,060
	Real	144,161	212,615	66,630	195,777
	CP	286,666	103,506	51,314	178,756
	Soles	12,738	89,167	27,345	32,998
	Argentine Peso	—	—	—	—
	U.F.	—	6,197	—	6,458
Trade and other current payables		3,480,302	635,945	2,952,796	371,057
	Dollars	47,292	1,576	180,622	1,292
	Euros	147,351	—	14,265	—
	Real	2,056,420	405,209	1,459,339	80,281
	CP	511,836	23,344	443,354	9,976
	Soles	200,223	—	232,088	—
	Argentine Peso	473,457	205,816	618,041	279,508
	$ non-adjustable	43,723	—	5,087	—
Current accounts payable to related parties		344,281	2,652,387	225,027	—
	Dollars	1,122	—	113,038	—
	Euros	316,215		88,558	—
	Real	12,455	2,652,387	16,575	—
	CP	1,176		959	—
	Soles	985		274	—
	Argentine Peso	3,208		448	—
	$ non-adjustable	9,120		5,175	—
Other current provisions		105,760	317,103	16,505	253,461
	Euros	—	25,516
	Real	89,466	105,475	10,594	—
	CP	—	10,325	—	33,778
	Soles	14,768	44,555	4,672	69,185
	Argentine Peso	362	131,232	—	150,498
	$ non-adjustable	1,164		1,239	—
Current tax liabilities		108,541	84,383	172,638	—
	Euros	—	52,340
	Dollars	—	—	—	—
	Real	15,965		32,399	—
	CP	21,562		84,650	—
	Soles	13,435		4,344	—
	Argentine Peso	57,579	32,043	51,191	—
	$ non-adjustable			54	—
Other current non-financial liabilities		207,994	62,126	249,304	3,780
	Dollars		3,091
	Real	139,333	51,029	175,081	3,018
	CP	16,588	7,276	23,525	—
	Soles	28,177	730	34,800	762
	Argentine Peso	23,704		15,898
	$ non-adjustable	192
Liabilities associated with disposal groups held for sale or for distribution to owners	$ non-adjustable	3,835		—	—
				—	—
TOTAL CURRENT LIABILITIES		4,798,149	4,852,607	3,830,989	1,103,347

F-230

		12-31-2018		12-31-2017
		Less than 90 days	91 days to 1 year	Less than 90 days	91 days to 1 year
LIABILITIES	Foreign currency	ThUS$	ThUS$	ThUS$	ThUS$
NON-CURRENT LIABILITIES
Other non-current financial liabilities		2,987,085	1,634,783	2,744,342	1,605,173
	Dollars	556,492	611,187	879,855	632,593
	Real	1,321,266	294,628	576,817	77,362
	CP	894,254	534,298	1,076,808	673,623
	Soles	198,472	194,670	186,026	221,595
	Argentine Peso	—	—	—	—
	U.F.	16,601	—	24,836	—
Trade and other non-current payables		901,156	31,900	527,644	450,925
	Dollars	4,606		51,103	—
	Real	695,311	31,900	416,731	213,268
	Soles	10,460	—	11,206	—
	Argentine Peso	190,779	—	48,589	237,657
	$ non-adjustable			15	—
Other non-current provisions		765,565	598,411	88,220	572,085
	Real	733,441	546,435	—	565,567
	CP	5,349	34,991	64,264	638
	Soles	3,669	16,946	2,130	5,880
	Peso Argentino	23,106	39	21,826	—
Deferred tax liabilities		192,374	353,696	83,768	371,543
	Real	11,188		8,784	121,597
	CP	29,177	3,446	18,011	—
	Soles	60,629	189,000	11,109	249,947
	Argentine Peso	83,006	161,250	37,724	—
	$ non-adjustable	8,374	—	8,140	(1	)
Non-current provisions for employee benefits		800,043	543,464	309,594	79,337
	Real	750,260	447,753	205,629	21,417
	CP	37,026	86,126	86,723	40,843
	Soles	5,130		4,526	—
	Argentine Peso	7,627	6,972	12,716	14,244
	$ non-adjustable		2,613	—	2,833
Other non-current non-financial liabilities		83,598	21,625	95,474	28,043
	Dollars	4,149
	Real	4,671	—	645	—
	CP	5,892	—	6,612	4,470
	Soles	3,893	21,625	4,062	23,573
	Argentine Peso	64,993	—	84,155	—
TOTAL NON-CURRENT LIABILITIES		5,729,821	3,183,879	3,849,042	3,107,106
TOTAL LIABILITIES		10,527,970	8,036,486	7,680,031	4,210,453

F-231

APPENDIX 2 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 time in arrears:

	12-31-2018
Trade and other current	Up-to-date portfolio		1 - 90 days in arrears		91 - 180 days in arrears		More than 181 days in arrears		Total Current		Total Non- Current
receivables	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Trade receivables, gross	1,557,837		490,061		173,268		796,303		3,017,469		171,513
Impairment provision	(41,013	)	(37,505	)	(39,952	)	(634,130	)	(752,600	)
Other receivables, gross	1,332,904		—		—		—		1,332,904		735,509
Impairment provision	(46,751	)							(46,751	)	(514	)
Total	2,802,977		452,556		133,316		162,173		3,551,022		906,508

	12-31-2017
Trade and other current	Up-to-date portfolio		1 - 90 days in arrears		91 - 180 days in arrears		More than 181 days in arrears		Total Current		Total Non- Current
receivables	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Trade receivables, gross	1,187,205		415,438		100,583		639,587		2,342,813		96,367
Impairment provision	(594	)	(4,531	)	(7,248	)	(539,178	)	(551,551	)	—
Other receivables, gross	589,738		—		—		—		589,738		520,426
Impairment provision	(3,211	)	—		—		—		(3,211	)	—
Total	1,773,138		410,907		93,335		100,409		2,377,789		616,793

F-232

·By type of portfolio:

	12-31-2018						12-31-2017
	Non-renegotiated portfolio		Renegotiated portfolio		Total Gross Portfolio		Non-renegotiated portfolio		Renegotiated portfolio		Total Gross Portfolio
	Number of	Gross amount	Number of	Gross amount	Number of	Gross Amount	Number of	Gross amount	Number of	Gross amount	Number of	Gross Amount
Time in Arrears	customers	ThUS$	customers	ThUS$	customers	ThUS$	customers	ThUS$	customers	ThUS$	customers	ThUS$
Up-to-date	9,918,200	1,580,102	1,679,833	149,248	11,598,033	1,729,350	11,239,116	1,209,494	63,799	74,078	11,302,915	1,283,572
1 to 30 days	8,803,920	302,656	257,244	19,796	9,061,164	322,452	4,620,466	264,931	132,814	13,350	4,753,280	278,281
31 to 60 days	2,917,248	100,061	148,625	11,193	3,065,873	111,254	610,861	83,411	21,069	7,589	631,930	91,000
61 to 90 days	1,802,108	48,054	105,881	8,301	1,907,989	56,355	226,842	41,237	14,384	4,920	241,226	46,157
91 to 120 days	1,460,121	50,898	95,138	7,475	1,555,259	58,373	174,170	37,609	10,605	3,916	184,775	41,525
121 to 150 days	1,304,234	62,862	79,043	6,173	1,383,277	69,035	139,518	26,491	9,390	3,362	148,908	29,853
151 to 180 days	1,111,148	40,651	72,756	5,209	1,183,904	45,860	134,039	26,203	8,786	3,002	142,825	29,205
181 to 210 days	683,370	37,456	70,761	4,883	754,131	42,339	115,132	28,420	7,790	2,708	122,922	31,128
211 to 250 days	482,245	26,603	58,518	4,447	540,763	31,050	121,587	24,371	7,137	2,493	128,724	26,864
More than 251 days	6,830,315	667,658	852,817	55,256	7,683,132	722,914	623,610	570,646	30,264	10,949	653,874	581,595
Total	35,312,909	2,917,001	3,420,616	271,981	38,733,525	3,188,982	18,005,341	2,312,813	306,038	126,367	18,311,379	2,439,180

b) Portfolio in default and in legal collection process

	Balance as of		Balance as of
	12-31-2018		12-31-2017
	Number of	Amount	Number of	Amount
Portfolio in Default and in Legal Collection Process	customers	ThUS$	customers	ThUS$
Notes receivable in default	588,962	75,562	582,771	48,357
Notes receivable in legal collection process (*)	9,838	44,981	11,612	34,390
Total	598,800	120,543	594,383	82,747

(*)Legal collections are included in the portfolio in arrears.

c) Provisions and write-offs

	Balance as of
	12-31-2018		12-31-2017
Provisions and write-offs	ThUS$		ThUS$
Provision for non-renegotiated portfolio	214,062		74,811
Provision for renegotiated portfolio	28,119		11,425
Recoveries	(127,510	)	37,884
Total	114,671		124,120

d) Number and amount of operations

	Balance as of
	12-31-2018		12-31-2017
	Total detail by	Total detail by	Total detail by	Total detail by
	type of transaction Last Quarter	type of operation Year-to- date	type of operation Last Quarter	type of operation Year-to- date
Number and Amount of Transactions	ThUS$	ThUS$	ThUS$	ThUS$
Impairment provision and recoveries:
Number of transactions	2,083,622	5,122,894	1,098,077	6,365,064
Amount of the transactions	85,139	114,671	17,865	124,120

F-233

APPENDIX 2.1 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:

	12-31-2018
	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	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Trade receivables, Generation and Transmission	301,319		24,816		10,407		3,145		9,996		33,373		11,385		3,559		2,096		25,624		133,193		558,913		57,636
- Large Clients	70,039		24,111		8,111		177		398		44		73		393		929		3,023		—		107,298		—
- Institutional Clients	149,070		—		—		—		—		—		—		—		—		—		—		149,070		57,610
- Other	82,210		705		2,296		2,968		9,598		33,329		11,312		3,166		1,167		22,601		133,193		302,545		26
Impairment provision	(8,511	)	—		—		—		—		—		—		(450	)	(1	)	(3,137	)	(63,741	)	(75,840	)	—
Unbilled services	192,963		—		—		—		—		—		—		—		—		—		—		192,963		—
Billed services	108,356		24,816		10,407		3,145		9,996		33,373		11,385		3,559		2,096		25,624		133,193		365,950		57,636
Trade receivables, Distribution	1,256,518		297,636		100,847		53,210		48,377		35,662		34,475		38,780		28,954		97,831		466,266		2,458,556		113,877
- Mass-market Clients	814,204		199,935		70,102		35,646		30,400		26,350		25,444		29,435		12,870		49,043		312,576		1,606,005		29,211
- Large Clients	303,775		66,027		16,102		8,287		5,207		4,561		3,371		4,261		2,836		10,309		97,111		521,847		13,678
- Institutional Clients	138,539		31,674		14,643		9,277		12,770		4,751		5,660		5,084		13,248		38,479		56,579		330,704		70,988
Impairment provision	(32,502	)	(12,850	)	(13,486	)	(11,169	)	(13,552	)	(12,538	)	(13,862	)	(31,088	)	(21,767	)	(71,428	)	(442,518	)	(676,760	)	—
Unbilled services	613,168		—		—		—		—		—		—		—		—		—		—		613,168		—
Billed services	643,350		297,636		100,847		53,210		48,377		35,662		34,475		38,780		28,954		97,831		466,266		1,845,388		113,877
Total trade receivables, gross	1,557,837		322,452		111,254		56,355		58,373		69,035		45,860		42,339		31,050		123,455		599,459		3,017,469		171,513
Total impairment provision	(41,013	)	(12,850	)	(13,486	)	(11,169	)	(13,552	)	(12,538	)	(13,862	)	(31,538	)	(21,768	)	(74,565	)	(506,259	)	(752,600	)	—
Total trade receivables, net	1,516,824		309,602		97,768		45,186		44,821		56,497		31,998		10,801		9,282		48,890		93,200		2,264,869		171,513

Since not all of our commercial databases in our Group’s different subsidiaries distinguish whether the final electricity service consumer is a natural or legal person, the main management segmentation used by all the subsidiaries to monitor and follow up on trade receivables is the following:

·Mass-market clients

·Large clients

·Institutional clients

	12-31-2017
	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	ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$		ThUS$
Trade receivables, Generation and Transmission	345,289		19,151		14,403		12,829		14,063		7,594		4,296		8,186		2,913		8,152		108,791		545,667		36,053
- Large Clients	103,455		17,383		6,181		251		197		204		209		154		191		6,282		14,265		148,772		—
- Institutional Clients	119,003		—		—		—		—		—		—		—		—		—		—		119,003		34,855
- Other	122,831		1,768		8,222		12,578		13,866		7,390		4,087		8,032		2,722		1,870		94,526		277,892		1,198
Impairment provision	(77	)	(64	)	(166	)	(201	)	(197	)	(204	)	(209	)	(162	)	(362	)	(6,017	)	(89,094	)	(96,753	)	—
Unbilled services	204,520		1,518		7,922		12,244		13,315		7,333		3,968		7,941		2,373		1,083		20,735		282,952		31,703
Billed services	140,769		17,633		6,481		585		748		261		328		245		540		7,069		88,056		262,715		4,350
Trade receivables, Distribution	841,916		259,130		76,597		33,328		27,462		22,259		24,909		22,942		23,951		63,895		400,757		1,797,146		60,314
- Mass-market Clients	468,900		166,722		50,937		19,280		15,221		12,333		12,057		11,151		13,995		49,012		267,004		1,086,612		15,645
- Large Clients	244,794		66,377		11,410		4,221		2,553		2,772		5,149		5,231		3,062		6,366		58,940		410,875		16,216
- Institutional Clients	128,222		26,031		14,250		9,827		9,688		7,154		7,703		6,560		6,894		8,517		74,813		299,659		28,453
Impairment provision	(517	)	(2,685	)	(506	)	(909	)	(1,849	)	(1,389	)	(3,400	)	(12,947	)	(12,805	)	(49,642	)	(368,149	)	(454,798	)	—
Unbilled services	427,324		—		—		—		—		—		—		—		—		—		—		427,324		—
Billed services	414,592		259,130		76,597		33,328		27,462		22,259		24,909		22,942		23,951		63,895		400,757		1,369,822		60,314
Total trade receivables, gross	1,187,205		278,281		91,000		46,157		41,525		29,853		29,205		31,128		26,864		72,047		509,548		2,342,813		96,367
Total impairment provision	(594	)	(2,749	)	(672	)	(1,110	)	(2,046	)	(1,593	)	(3,609	)	(13,109	)	(13,167	)	(55,659	)	(457,243	)	(551,551	)	—
Total trade receivables, net	1,186,611		275,532		90,328		45,047		39,479		28,260		25,596		18,019		13,697		16,388		52,305		1,791,262		96,367

F-234

·By type of portfolio:

	12-31-2018
	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
Type of Portfolio	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	301,319	24,816	10,407	3,145	9,996	33,373	11,385	3,559	2,096	158,817	—	558,913	57,636
- Large Clients	70,039	24,111	8,111	178	397	44	73	393	929	3,023		107,298	—
- Institutional Clients	149,072											149,072	57,610
- Other	82,208	705	2,296	2,967	9,599	33,329	11,312	3,166	1,167	155,794		302,543	26
Renegotiated portfolio	—	—	—	—	—	—	—	—	—	—	—	—	—
- Large Clients												—	—
- Institutional Clients												—	—
- Other												—	—
DISTRIBUTION
Non-renegotiated portfolio	1,181,219	277,840	89,654	44,909	40,902	29,489	29,266	33,897	24,507	508,841	—	2,260,524	39,928
- Mass-market Clients	762,509	185,042	61,919	29,969	25,283	22,141	21,982	26,152	10,117	331,232		1,476,346	13,080
- Large Clients	291,925	63,756	15,124	7,678	4,579	4,100	2,924	3,838	2,429	98,340		494,693	6,716
- Institutional Clients	126,785	29,042	12,611	7,262	11,040	3,248	4,360	3,907	11,961	79,269		289,485	20,132
Renegotiated portfolio	75,299	19,796	11,193	8,301	7,475	6,173	5,209	4,883	4,447	55,256	—	198,032	73,949
- Mass-market Clients	51,696	14,894	8,183	5,677	5,119	4,208	3,462	3,282	2,754	30,384		129,659	16,132
- Large Clients	11,851	2,271	979	609	627	461	447	422	407	9,081		27,155	6,962
- Institutional Clients	11,752	2,631	2,031	2,015	1,729	1,504	1,300	1,179	1,286	15,791		41,218	50,855
Total gross portfolio	1,557,837	322,452	111,254	56,355	58,373	69,035	45,860	42,339	31,050	722,914	—	3,017,469	171,513

	12-31-2017
	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
Type of Portfolio	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	336,554	18,955	14,367	12,761	14,007	7,536	4,239	8,138	2,877	115,516	—	534,947	36,053
- Large Clients	103,455	17,384	6,182	251	196	204	209	154	192	20,548	—	148,775	—
- Institutional Clients	119,003	—	—	—	—	—	—	—	—	—	—	119,003	34,855
- Other	114,095	1,571	8,185	12,510	13,811	7,332	4,029	7,984	2,684	94,968	—	267,169	1,198
Renegotiated portfolio	8,736	196	36	68	56	58	58	48	37	1,427	—	10,720	—
- Large Clients	—	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—	—
- Other	8,736	196	36	68	56	58	58	48	37	1,427	—	10,720	—
DISTRIBUTION
Non-renegotiated portfolio	800,895	245,976	69,044	28,476	23,602	18,955	21,965	20,282	21,495	455,130	—	1,705,820	35,993
- Mass-market Clients	458,793	158,628	47,094	16,813	13,327	10,900	10,958	10,265	13,273	313,773	—	1,053,824	13,130
- Large Clients	236,993	64,603	9,837	3,650	2,285	2,551	4,888	5,018	2,893	64,326	—	397,044	6,613
- Institutional Clients	105,109	22,745	12,113	8,013	7,990	5,504	6,119	4,999	5,329	77,031	—	254,952	16,250
Renegotiated portfolio	41,021	13,154	7,553	4,852	3,860	3,304	2,944	2,660	2,456	9,522	—	91,326	24,321
- Mass-market Clients	10,109	8,093	3,844	2,467	1,893	1,432	1,098	887	722	2,243	—	32,788	2,513
- Large Clients	7,799	1,773	1,573	570	268	222	262	211	169	981	—	13,828	9,603
- Institutional Clients	23,113	3,288	2,136	1,815	1,699	1,650	1,584	1,562	1,565	6,298	—	44,710	12,205
Total gross portfolio	1,187,206	278,280	91,000	46,157	41,526	29,853	29,206	31,128	26,865	581,595	—	2,342,815	96,367

F-235

APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY:

This appendix forms an integral part of these consolidated financial statements.

	COLOMBIA				PERU				ARGENTINA				BRAZIL				TOTAL
	12-31-2018		12-31-2017		12-31-2018		12-31-2017		12-31-2018		12-31-2017		12-31-2018		12-31-2017		12-31-2018		12-31-2017
	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
BALANCE	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Current accounts receivable from related parties	—	—	—	—	—	—	—	—	—	—	—	—	2,371	18	1,100	95	2,371	18	1,100	95
Trade and other current receivables	146,658	8,102	113,228	7,884	57,805	9,113	46,218	8,045	194,943	11	141,385	—	606,356	8,090	235,410	9,066	1,005,762	25,316	536,241	24,995
Total Asset Estimate	146,658	8,102	113,228	7,884	57,805	9,113	46,218	8,045	194,943	11	141,385	—	608,727	8,108	236,510	9,161	1,008,133	25,334	537,341	25,090
Current accounts payable to related parties	—	—	—	—			—	—			—	—	11,614	123	5,696	179	11,614	123	5,696	179
Trade and other current payables	42,348	10,560	35,171	10,429	1,705	8,197	36,419	11,673	52,548	—	60,713	—	597,734	109,496	333,242	9,108	694,335	128,253	465,545	31,210
Total Liability Estimate	42,348	10,560	35,171	10,429	1,705	8,197	36,419	11,673	52,548	—	60,713	—	609,348	109,619	338,938	9,287	705,949	128,376	471,241	31,389

	COLOMBIA				PERU				ARGENTINA				BRAZIL				TOTAL
	12-31-2018		12-31-2017		12-31-2018		12-31-2017		12-31-2018		12-31-2017		12-31-2018		12-31-2017		12-31-2018		12-31-2017
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 sales	161,317	8,911	118,069	8,221	59,474	9,375	45,874	7,986	212,807	11	150,296	—	646,671	8,602	243,074	9,549	1,080,269	26,899	557,313	25,756
Energy purchases	46,581	11,615	36,675	10,875	1,755	8,435	36,139	11,582	52,548	—	63,941	—	647,326	116,450	346,809	9,625	748,210	136,500	483,564	32,082

F-236

APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS:

This appendix forms an integral part of the Group’s financial statements.

	Balance as of				Balance as of
	12-31-2018				12-31-2017
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers with Payments Up-to-Date	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Up to 30 days	155,973	434,459	1,026,490	1,616,922	—	382,428	1,327,693	1,710,121
From 31 to 60 days	52,423	182,756	143,397	378,576	—	18,421	290,477	308,898
From 61 to 90 days	13,428	32,421	26,195	72,044	—	—	6,286	6,286
From 91 to 120 days	4,111	6,679	10,815	21,605	—	—	1,592	1,592
From 121 to 365 days	469	5,715	82,893	89,077	—	—	15,932	15,932
More than 365 days	4,606	11,889	205,251	221,746	—	—	278,427	278,427
Total	231,010	673,919	1,495,041	2,399,970	—	400,849	1,920,407	2,321,256

	Balance as of				Balance as of
	12-31-2018				12-31-2017
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers with Payments Overdue	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$	ThUS$
Up to 30 days	3,089	34,104		37,193	—	—	—	—
From 31 to 60 days				—	—	—	—	—
From 61 to 90 days				—	—	—	—	—
From 91 to 120 days				—	—	—	—	—
From 121 to 365 days				—	—	—	—	—
More than 365 days		433	148,585	149,018	—	—	94,718	94,718
Total	3,089	34,537	148,585	186,211	—	—	94,718	94,718

F-237