Annual and transition report of foreign private issuers [Sections 13 or 15(d)]


BGCOLOR="WHITE">

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

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

OR

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013

OR

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

OR

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

Date of event requiring this shell company report

For the transition period from       to

Commission file number: 001-12440

ENERSIS S.A.

(Exact name of Registrant as specified in its charter)

ENERSIS 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) 2353-4639, fax: (56-2) 2378-4789, nbe@enersis.cl, 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$ 249,734,000 7.40% Notes due December 1, 2016 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 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:

49,092,772,762

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

x Yes ¨ No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

¨ Yes 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 ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

¨ Yes ¨ No

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP ¨

International Financial Reporting Standards as issued

by the International Accounting Standards Board x

Other ¨

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

¨ Item 17 ¨ Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

¨ Yes x No


Table of Contents

Enersis’ Simplified Organizational Structure (1)

As of December 31, 2013

LOGO

(1) Only principal operating subsidiaries are presented here. The percentage listed for each of our subsidiaries represents Enersis’ economic interest in such subsidiary.

2


Table of Contents

TABLE OF CONTENTS

Page

Glossary

4

Introduction

10

Financial Information

10

Technical Terms

11

Calculation of Economic Interest

11

Forward-Looking Statements

11

PART I

14

Item 1.

Identity of Directors, Senior Management and Advisers 14

Item 2.

Offer Statistics and Expected Timetable 14

Item 3.

Key Information 14

Item 4.

Information on the Company 28

Item 4A.

Unresolved Staff Comments 131

Item 5.

Operating and Financial Review and Prospects 131

Item 6.

Directors, Senior Management and Employees 165

Item 7.

Major Shareholders and Related Party Transactions 177

Item 8.

Financial Information 179

Item 9.

The Offer and Listing 181

Item 10.

Additional Information 183

Item 11.

Quantitative and Qualitative Disclosures About Market Risk 200

Item 12.

Description of Securities Other Than Equity Securities 204

PART II

206

Item 13.

Defaults, Dividend Arrearages and Delinquencies 206

Item 14.

Material Modifications to the Rights of Security Holders and Use of Proceeds 206

Item 15.

Controls and Procedures 206

Item 16.

Reserved 207

Item 16A.

Audit Committee Financial Expert 207

Item 16B.

Code of Ethics 207

Item 16C.

Principal Accountant Fees and Services 208

Item 16D.

Exemptions from the Listing Standards for Audit Committees 209

Item 16E.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers 209

Item 16F.

Change in Registrant’s Certifying Accountant 209

Item 16G.

Corporate Governance 210

Item 16H.

Mine Safety Disclosure 210

PART III

211

Item 17.

Financial Statements 211

Item 18.

Financial Statements 211

Item 19.

Exhibits 212

3


Table of Contents

GLOSSARY

AFP Administradora de Fondos de Pensiones A legal entity that manages a Chilean pension fund.
Ampla Ampla Energia e Serviços S.A. A publicly held Brazilian distribution company operating in Rio de Janeiro, owned by Endesa Brasil, a subsidiary of Enersis.
ANEEL Agência Nacional de Energia Elétrica Brazilian governmental agency for electric energy.
Cachoeira Dourada Centrais Elétricas Cachoeira Dourada S.A. Brazilian generation company owned by Endesa Brasil, a subsidiary of Enersis.
CAM Compañía Americana de Multiservicios Ltda. A former Enersis’ subsidiary engaged in the electrical parts procurement business.
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.
CDEC Centro de Despacho Económico de Carga Autonomous entity in two Chilean electric systems in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.
Celta Compañía Eléctrica Tarapacá S.A. Chilean generation subsidiary of Endesa Chile that operates generation plants in the SING. Celta merged with Endesa Eco in November 2013. Endesa Eco merged with San Isidro in September 2013 and San Isidro merged with Pangue in May 2012.
Cemsa Endesa Cemsa S.A. Energy trading company with operations in Argentina, and a subsidiary of Enersis since April 1, 2013, as a result of the capital increase.
Chilectra Chilectra S.A. Chilean electricity distribution company operating in the Santiago metropolitan area and a subsidiary of Enersis.
CIEN Companhia de Interconexão Energética S.A. Brazilian transmission company, wholly-owned by Endesa Brasil, a subsidiary of Enersis.

4


Table of Contents
CNE Comisión Nacional de Energía Chilean National Energy Commission, governmental entity with responsibilities under the Chilean regulatory framework.
Codensa Codensa S.A. E.S.P. Colombian distribution company that operates mainly in Bogotá, and a subsidiary of Enersis.
Coelce Companhia Energética do Ceará S.A. A publicly held Brazilian distribution company operating in the state of Ceará. Coelce is controlled by Endesa Brasil, a subsidiary of Enersis.
COES Comité de Operación Económica del Sistema Peruvian entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.
Cono Sur Cono Sur Participaciones, S.L.U. A former subsidiary of Endesa Spain that held its interests in certain electricity generation, transmission, and holding companies, the shares of which were contributed to Enersis in the in-kind contribution. This company was dissolved in July 2013 after the transfer of assets to Enersis was completed.
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 Endesa Brasil.
DECSA Distribuidora Eléctrica de Cundinamarca S.A. Colombian distribution company and a subsidiary of Codensa.
Dock Sud Central Dock Sud S.A. Argentine generation company and subsidiary of Enersis since April 1, 2013, as a result of the capital increase.
Edegel Edegel S.A.A. A publicly held Peruvian generation company and a subsidiary of Endesa Chile.
Edelnor Empresa de Distribución Eléctrica de Lima Norte S.A.A. A publicly held Peruvian distribution company with a concession area in the northern part of Lima and a subsidiary of Enersis.
Edesur Empresa Distribuidora Sur S.A. Argentine distribution company with concession area in the south of the Buenos Aires greater metropolitan area, and a subsidiary of Enersis.

5


Table of Contents
EEB Empresa de Energía de Bogotá S.A. Colombian stated-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 company and a subsidiary of DECSA, in which Enersis holds 19.5% interest.
EEPSA Empresa Eléctrica de Piura S.A. A publicly traded Peruvian generation subsidiary of Enersis since April 1, 2013 as a result of the capital increase with natural gas thermal plants.
El Chocón Hidroeléctrica El Chocón S.A. Endesa Chile’s Argentine generation subsidiary with two hydroelectric plants, El Chocón and Arroyito, both located in the Limay River, Argentina.
Emgesa Emgesa S.A. E.S.P. Colombian generation company controlled by Endesa Chile.
Endesa Brasil Endesa Brasil S.A. Brazilian holding company and a subsidiary of Enersis.
Endesa Chile Empresa Nacional de Electricidad S.A. Our publicly held generation subsidiary with consolidated operations in four countries in Latin America.
Endesa Costanera Endesa Costanera S.A. A publicly held Argentine generation company controlled by Endesa Chile.
Endesa Eco Endesa Eco S.A. A former Chilean subsidiary of Endesa Chile and owner of Central Eólica Canela S.A. and Ojos de Agua mini hydroelectric plant. Endesa Eco merged with Celta in November 2013.
Endesa Fortaleza Central Geradora Termelétrica Fortaleza S.A. Brazilian generation company that operates in the state of Ceará. Endesa Fortaleza is wholly-owned by our subsidiary Endesa Brasil.
Endesa Latinoamérica Endesa Latinoamérica, S.A.U. A subsidiary of Endesa Spain and owner of 40.3% of Enersis. Endesa Latinoamérica was formerly known as Endesa Internacional, S.A.U.
Endesa Spain Endesa, S.A. A Spanish electricity generation and distribution company with a 60.6% beneficial interest in Enersis.

6


Table of Contents
Enel Enel S.p.A. Italian power company, with a 92.1% controlling ownership of Endesa Spain.
Enersis Enersis S.A. Our company, a publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, with subsidiaries engaged primarily in the generation, transmission and distribution of electricity in Chile, Argentina, Brazil, Colombia, and Peru. Registrant of this Report.
ENRE Ente Nacional Regulador de la Electricidad Argentine national regulatory authority for the energy sector.
ESM Extraordinary Shareholders’ Meeting Extraordinary Shareholders’ Meeting.
Etevensa Empresa de Generación Termoeléctrica Ventanilla S.A. Peruvian generation company that merged with Edegel in 2006.
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.
GasAtacama GasAtacama S.A. Company involved in gas transportation and electricity generation in northern Chile that is 50% owned by Endesa Chile.
Gener AES Gener S.A. Chilean generation company that competes with the Company in Chile, Argentina and Colombia.
GNL Quintero GNL Quintero S.A. Company created to develop, build, finance, own and operate a LNG regasification facility at Quintero Bay (Chile) in which LNG is unloaded, stored and regasified.
IDR Issuer Default Rating Reflects the relative vulnerability of an entity to default on its financial obligations.
IFRS International Financial Reporting Standards Accounting standards adopted by the Company on January 1, 2009.
IMV Inmobiliaria Manso de Velasco Ltda. Enersis’ wholly-owned subsidiary engaged in the real estate business.
LNG Liquefied Natural Gas. Liquefied natural gas.
MEM Mercado Eléctrico Mayorista Wholesale Electricity Market in Argentina, Colombia, and Peru.
MME Ministério de Minas e Energia Brazilian Ministry of Mines and Energy.

7


Table of Contents
NCRE Non Conventional Renewable Energy Energy sources which are continuously replenished by natural processes, such as wind, biomass, mini-hydro, geothermal, wave, or tidal energy.
NIS Sistema Interconectado Nacional National interconnected electric system. There are such systems in Chile, Argentina, Brazil, and Colombia.
ONS Operador Nacional do Sistema Elétrico Electric System National 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 Supervisory Authority, the Peruvian regulatory electricity authority.
OSM Ordinary Shareholders’ Meeting Ordinary Shareholders’ Meeting.
Pangue Empresa Eléctrica Pangue S.A. A former Chilean subsidiary of Endesa Chile and owner of the Pangue power station. San Isidro merged with Pangue in May 2012 and Endesa Eco merged with San Isidro in September 2013. Celta merged with Endesa Eco in November 2013.
Pehuenche Empresa Eléctrica Pehuenche S.A. A publicly held Chilean electricity company, and a subsidiary of Endesa Chile.
San Isidro Compañía Eléctrica San Isidro S.A. A former Chilean subsidiary of Endesa Chile. San Isidro merged with Pangue in May 2012 and Endesa Eco merged with San Isidro in September 2013. Celta merged with Endesa Eco in November 2013.
SEF Superintendencia de Electricidad y Combustible Chilean Superintendency of Electricity and Fuels, a governmental entity in charge of supervising the Chilean electricity industry.
SEIN Sistema Eléctrico Interconectado Nacional Peruvian interconnected electric system.
SIC Sistema Interconectado Central Chilean central interconnected electric system covering all of Chile except the north and the extreme south.
SING Sistema Interconectado del Norte Grande Electric interconnected system operating in northern Chile.

8


Table of Contents
SVS Superintendencia de Valores y Seguros Chilean authority in charge of supervising public companies, securities and the insurance business.
TESA Transportadora de Energía S.A. Endesa Brasil’s transmission company subsidiary with operations in Argentina.
UF Unidad de Fomento Chilean inflation-indexed, Chilean peso-denominated monetary unit.
UTA Unidad Tributaria Anual Chilean annual tax unit. One UTA equals 12 UTM.
UTM Unidad Tributaria Mensual Chilean inflation-indexed monthly tax unit used to define fines, among other purposes.
VAD Valor Agregado de Distribución Value added from distribution of electricity.
VNR Valor Nuevo de Reemplazo The net replacement value of electricity assets.
XM Expertos de Mercado S.A. E.S.P. Colombian company Interconexión Eléctrica S.A. (ISA)’s subsidiary that provides system management in real time services in electrical, financial and transportation sectors.
Yacylec Yacylec S.A. Argentine transmission company and an associate of Enersis since April 2013, as a result of the capital increase.

9


Table of Contents

INTRODUCTION

As used in this Report on Form 20-F, first person personal pronouns such as “we”, “us” or “our” refer to Enersis S.A. (Enersis or the Company) and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries, jointly —controlled entities and associates is expressed in terms of our economic interest as of December 31, 2013.

We are a Chilean company engaged through our subsidiaries and jointly-controlled entities in the electricity generation, transmission and distribution businesses in Chile, Brazil, Colombia, Peru and Argentina. As of the date of this Report, we own 60.0% of Empresa Nacional de Electricidad S.A. (“Endesa Chile”), a Chilean electricity generation company, and 99.1% of Chilectra S.A. (“Chilectra”), a Chilean electricity distribution company. As of the same date, Endesa, S.A. (“Endesa Spain”), a Spanish electricity generation and distribution company, owns 60.6% of Enersis directly and through Endesa Latinoamérica, S.A.U. (“Endesa Latinoamérica”). Enel S.p.A. (“Enel”), an Italian generation and distribution company, owns 92.1% of Endesa Spain through Enel Energy Europe, S.L.U.

Financial Information

In this Report on Form 20-F, unless otherwise specified, references to “U.S. dollars” or “US$”, are to dollars of the United States of America; references to “pesos” or “Ch$” are to Chilean pesos, the legal currency of Chile; 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 “soles” are to Peruvian Nuevo Sol, the legal currency of Peru; references to “CPs” or “Colombian pesos” are to the legal currency of Colombia; references to “€” or “Euros” are to the legal currency of the European Union; and references to “UF” are to Development Units ( Unidades de Fomento ).

The Unidad de Fomento 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 ). 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, 2013, one UF was equivalent to Ch$ 23,309.56. The U.S. dollar equivalent of one UF was US$ 44.43 as of December 31, 2013, using the Observed Exchange Rate reported by the Central Bank of Chile ( Banco Central de Chile ) as of December 31, 2013 of Ch$ 524.61 per US$ 1.00.

As of March 31, 2014, one UF was equivalent to Ch$ 23606.97. The U.S. dollar equivalent of one UF was US$ 42.83 on March 31, 2014, using the Observed Exchange Rate reported by the Central Bank of Chile as of such date of Ch$ 551.18 per US$ 1.00.

Our consolidated financial statements and, unless otherwise indicated, other financial information concerning Enersis included in this Report are presented in Chilean pesos. Since January 1, 2009, Enersis has prepared its financial statements in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standard Board (“IASB”).

Our subsidiaries are consolidated 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.

Until December 31, 2012, jointly-controlled companies were consolidated using the proportionate consolidation method. Commencing January 1, 2013, we began recording these jointly controlled companies using the equity method, as required by IFRS 11, “Joint Arrangements”. This change affected our accounting for Centrales Hidroeléctricas de Aysén S.A., Inversiones GasAtacama Holding Ltda., Distribuidora Eléctrica de Cundinamarca S.A. and their subsidiaries, and Transmisora Eléctrica de Quillota Ltda. Our audited consolidated financial statements as of and for the years ended December 31, 2012 and 2011 were restated to give retrospective effect to the application of IFRS 11. These changes do not have any effect on equity or net income, in both cases, attributable to the shareholders of Enersis. Our audited consolidated financial statements as of and for the years ended December 31, 2010 and 2009 are presented in the form in which they were originally prepared in accordance with IFRS, as issued by the IASB, and do not reflect the application of IFRS 11.

10


Table of Contents

Investments in associated companies over which the Company exercises significant influence, are recorded in our consolidated financial statements using the equity method. For detailed information regarding subsidiaries, jointly-controlled entities and associated companies, see Appendices 1, 2 and 3 to the consolidated financial statements.

For the convenience of the reader, this Report contains translations of certain Chilean peso amounts into U.S. dollars at specified rates. Unless otherwise indicated, the U.S. dollar equivalent for information in Chilean pesos is based on the Observed Exchange Rate for December 31, 2013, 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”.

Numbers in tables may not total exactly due to rounding.

Technical Terms

References to “TW” are to terawatts; references to “GW” and “GWh” are to gigawatts and gigawatt hours, respectively; references to “MW” and “MWh” are to megawatts and megawatt hours, respectively; references to “kW” and “kWh” are to kilowatts and kilowatt hours, respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. 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.

Statistics relating to aggregate annual electricity production are expressed in GWh and based on a year of 8,760 hours, except for leap years (such as 2012), 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. Statistics relating to our production do not include electricity consumed by us by our own generation units.

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 (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 Enersis in its related 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 own 60% of a directly held subsidiary and that subsidiary owns 40% of an associate, our economic interest in such associate would be 60% times 40%, or 24%.

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:

11


Table of Contents
• 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:

• changes in 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;
• political, economic and demographic developments in the markets in South America where we conduct our business; 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 public accountants have not examined or compiled the forward-looking statements and, accordingly, do 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.

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.

RECENT DEVELOPMENTS

Bocamina II’s Shutdown

On December 17, 2013, the Court of Concepción, in southern Chile, ordered the temporary shutdown of our 350 MW coal-fired thermal power plant, Bocamina II. The court granted an injunction in favor of local fishermen who claim our facility is harmful to marine life and causes pollution. The financial impact of Bocamina II’s shutdown had no material effect on our 2013 results because its operation ceased near the end of the fiscal year. However, as of the date of this Report, the plant remains shut down while we appeal the case. On December 23, 2013, we submitted all required documents and studies to the Chilean Environmental Superintendence. Our operating income is reduced between US$ 20 million and US$ 44 million each month the facility remains shut down.

Coelce Tender Offer

On February 17, 2014, in connection with a voluntary tender offer carried out over a 33-day period commencing on January 16, Enersis purchased an additional 15.1% interest in Coelce, our Brazilian distribution subsidiary, in an exchange auction conducted on the São Paulo stock exchange, the BM&F BOVESPA. As a result, our economic interest in Coelce increased from 49.2% as of December 31, 2013 to the current 64.3%. The shares purchased included 2,964,650 common shares, 8,818,006 Series A preferred shares and 424 Series B preferred shares, in each case at a fixed R$ 49 per share, which represented a 20.1% premium over the weighted average price

12


Table of Contents

of the Series A preferred shares for the 30 trading days prior to the public announcement of our offer. The aggregate amount paid for the shares was equivalent to Ch$ 133 billion. This acquisition has no effect on the statement of comprehensive income of Enersis in 2014, as it consists of an increase in the ownership interest in a subsidiary of Enersis. For the same reason, this transaction does not change the amounts of assets and liabilities contributed by Coelce in the consolidated financial statements of Enersis, since it is an equity transaction. The difference between the book value of non-controlling interests acquired and the amount paid for the ownership interests acquired, resulted in a charge of Ch$ 76.3 billion that was directly reflected in Other Reserves in the Equity Attributable to Shareholders of Enersis.

Pursuant to Brazilian regulations, because Enersis received tenders of more than two thirds of the outstanding free float of common shares, we were required to extend the tender offer for all outstanding common shares until May 16, 2014 at the same price of R$ 49 per common share, after adjustment for the Central Bank of Brazil’s overnight interest rate (SELIC) as of the February 20, 2014 settlement date. As of the date of this Report, we have purchased 17,253 additional common shares. Because we did not receive tender for more than two thirds of either series of the preferred shares, the tender offer for the two series of preferred shares was not extended. The purchase of the 15.1% interest in Coelce was financed with the proceeds from our capital increase concluded on March 28, 2013.

HidroAysén Hydroelectric Project

In August 2008, HidroAysén submitted an Environmental Impact Assessment Study to the Chilean environmental authority for its approval. On May 9, 2011, we received a favorable environmental qualification resolution, though it contained certain conditions. In June 2011, opponents to the project filed 34 requests for review, and HidroAysén filed one, with the Council of Ministers, consisting of six cabinet members chaired by the Minister of the Environment, all requesting the review of certain conditions established in the resolution. By law, the authority has 60 business days to review the submission. In our cause, the authority took over two years and requested additional studies. On January 30, 2014, toward the end of former Chilean President Sebastián Piñera’s term, the Council of Ministers met to review the appeals. The majority of the issues were resolved, but the Council requested additional background information and new studies on certain points. In March 2014, Chilean President Michelle Bachelet took office, and a new Council of Ministers was convened, which repealed the Council’s earlier decisions. The new Council stated it would review the matter once again and resolve all claims within the 60 business day timeframe established by law. We are awaiting the decision of the Council.

GasAtacama Acquistion

On March 31, 2014, the Board of Directors of Endesa Chile approved the acquisition from Southern Cross Latin American Private Equity Fund III, LP (“Southern Cross”) of all of its interest in Inversiones GasAtacama Holding Ltda. (“GasAtacama Holding”), which owns 50% of GasAtacama. Endesa Chile currently holds a 48.1% economic interest in GasAtacama, and Enersis beneficially owns the remaining 1.9%. An affiliate of Southern Cross will assign Endesa Chile a US$ 28,330,155 promissory note executed by an affiliate of GasAtacama Holding in favor of the Southern Cross affiliate. Endesa Chile will pay US$ 309 million for the shares and the assignment of the promissory note. The transaction is in settlement of an arbitral dispute between Southern Cross and Endesa Chile relating to the terms of a right of first refusal provision in a shareholders agreement entered into by the parties and relating to GasAtacama Holding. Completion of the transaction is subject to execution and delivery of definitive documentation by the parties on or before April 30, 2014.

Los Cóndores Hydroelectric Project

On March 27, 2014, our Board of Directors authorized the 150 MW Los Cóndores hydroelectric project, with a total investment, including the transmission line, of US$661.5 million. Los Cóndores is in Chile’s seventh region and will generate power from the Maule Lake reservoir. Commercial start-up is expected by the end of 2018.

13


Table of Contents

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 summary of consolidated financial data should be read in conjunction with our audited consolidated financial statements included in this Report. The consolidated financial data as of and for the years ended December 31, 2010 and 2009 are derived from our audited consolidated financial statements not included in this Report. Our audited consolidated financial statements as of and for the years ended December 31, 2013, 2012, and 2011 were prepared in accordance with IFRS, as issued by the IASB. Until December 31, 2012, jointly-controlled companies were consolidated using the proportionate consolidation method. Commencing January 1, 2013, we began recording these jointly controlled companies using the equity method, as required by IFRS 11, “Joint Arrangements”. This change affected our accounting for Centrales Hidroeléctricas de Aysén S.A., Inversiones GasAtacama Holding Ltda., Distribuidora Eléctrica de Cundinamarca S.A. and their subsidiaries, and Transmisora Eléctrica de Quillota Ltda. Our audited consolidated financial statements as of and for the year ended December 31, 2012 and 2011 were restated to give retrospective effect to the application of IFRS 11. These changes do not have any effect on equity or net income, in both cases, attributable to the shareholders of Enersis. Our audited consolidated financial statements as of and for the years ended December 31, 2010 and 2009 are presented in the form in which they were originally prepared in accordance with IFRS, as issued by the IASB, and do not reflect the application of IFRS 11.

Amounts are expressed in millions except for ratios, operating data, shares and ADS (American Depositary Shares) data. For the convenience of the reader, all data presented in U.S. dollars in the following summary, as of and for the year ended December 31, 2013, is translated at the Observed Exchange Rate for that date of Ch$ 524.61 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 web page, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Nevertheless, the Central Bank of Chile may intervene by buying or selling foreign currency on the Formal Exchange Market to attempt to maintain the Observed Exchange Rate within a desired range.

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, at such rate or at any other rate. For more information concerning historical exchange rates, see “ — Exchange Rates” below.

14


Table of Contents

The following tables set forth the selected consolidated financial data of Enersis for the periods indicated and the operating data of subsidiaries:

As of and for the year ended December 31,
2013 (1) 2013 2012 (2) 2011 (2) 2010 2009
(US$ millions) (Ch$ millions)
Consolidated Income Statement Data
Revenues and other operating income 11,941 6,264,446 6,495,953 6,386,600 6,563,581 6,472,056
Operating expenses (3) (8,622) (4,523,308) (5,025,190) (4,847,673) (4,859,280) (4,544,611)
Operating income 3,319 1,741,138 1,470,763 1,538,927 1,704,301 1,927,445
Financial income (expense), net (320) (168,029) (216,642) (233,666) (270,605) (309,256)
Total gain (loss) on sale of non-current assets not held for sale 37 19,170 15,186 (5,769) 11,711 50,502
Other non-operating income 48 25,289 30,382 27,929 1,288 2,374
Income before income tax 3,083 1,617,569 1,299,689 1,327,421 1,446,695 1,671,065
Income tax (961) (504,168) (406,676) (455,469) (346,006) (359,737)
Net income 2,122 1,113,401 893,013 871,952 1,100,689 1,311,328
Net income attributable to shareholders of Enersis 1,255 658,514 377,351 375,471 486,227 660,231

Net income attributable to non-controlling interests 867 454,887 515,662 496,481 614,462 651,097
Net income (loss) from continuing operations per average number of Share basic and diluted (Ch$/US$) 0.03 14.56 11.56 11.50 14.89 20.22
Net income (loss) from continuing operations per average number of ADS (Ch$ / US$) 1.39 728.14 577.85 574.97 744.58 1,011.04
Net income (loss) per average number of Share, basic and diluted (Ch$/US$ per share) 0.03 14.56 11.56 11.50 14.89 20.22
Net income (loss) per average number of ADS (Ch$/US$ per ADS) 1.39 728.14 577.85 574.97 744.58 1,011.04
Cash dividends per Share (Ch$/ US$ per share) 0.01 4.25 5.75 7.45 4.64 7.02
Cash dividends per ADS (Ch$/ US$ per ADS) 0.41 212.51 287.49 372.50 232.00 351.00
Weighted average number of shares of common stock (thousands) 45,218,860 32,651,166 32,651,166 32,651,166 32,651,166
Weighted average number of ADS (thousands) 97,829 73,894 82,456 82,320 81,303
Consolidated Balance Sheet Data
Total assets 28,931 15,177,664 13,246,492 13,649,087 13,005,845 13,210,140
Non-current liabilities 7,032 3,688,940 3,941,555 4,336,012 4,084,540 4,637,749
Equity attributable to shareholders of Enersis 11,758 6,168,554 3,893,799 3,895,729 3,735,545 3,518,480
Equity attributable to non-controlling interests 4,458 2,338,911 3,064,408 2,995,312 2,778,483 2,858,524
Total equity 16,216 8,507,464 6,958,207 6,891,041 6,514,028 6,377,004
Capital stock (4) 11,109 5,828,040 2,983,642 2,983,642 2,983,642 2,983,642
Other Consolidated Financial Data
Capital expenditures (CAPEX) (5) 1,477 774,820 707,291 673,673 701,341 736,474
Depreciation, amortization and impairment losses (6) 973 510,351 477,096 552,984 557,391 539,655

(1) Solely for the convenience of the reader, Chilean peso amounts have been translated into U.S. dollars at the exchange rate of Ch$ 524.61 per U.S. dollar, the Observed Exchange Rate for December 31, 2013.
(2) Restated as a result of the application of IFRS 11.
(3) Operating expenses includes selling and administration expense.
(4) Includes share premium.
(5) CAPEX figures represent actual payments for each year.
(6) For further detail, please refer to Notes 8C and 29 to the Consolidated Financial Statements.

15


Table of Contents
As of and for the year ended December 31,
2013 2012 2011 2010 2009

OPERATING DATA OF SUBSIDIARIES

Chilectra (Chile)

Electricity sold (GWh)

15,152 14,445 13,697 13,098 12,585

Number of customers (thousands)

1,694 1,659 1,638 1,610 1,579

Total energy losses (%) (1)

5.3% 5.4% 5.5% 5.8% 6.1%

Edesur (Argentina)

Electricity sold (GWh)

18,137 17,738 17,233 16,759 16,026

Number of customers (thousands)

2,444 2,389 2,389 2,353 2,305

Total energy losses (%) (1)

10.8% 10.6% 10.5% 10.5% 10.5%

Ampla (Brazil)

Electricity sold (GWh)

11,049 10,816 10,223 9,927 9,394

Number of customers (thousands)

2,801 2,712 2,644 2,571 2,522

Total energy losses (%) (1)

19.8% 19.6% 19,7% 20.5% 21.2%

Coelce (Brazil)

Electricity sold (GWh)

10,718 9,878 8,970 8,850 7,860

Number of customers (thousands)

3,500 3,338 3,224 3,095 2,965

Total energy losses (%) (1)

12.5% 12.6% 11.9% 12.1% 11.6%

Codensa (Colombia)

Electricity sold (GWh)

13,342 12,972 12,552 12,141 11,837

Number of customers (thousands)

2,687 2,588 2,496 2,429 2,361

Total energy losses (%) (1)

7.0% 7.3% 7.8% 8.2% 8.2%

Edelnor (Peru)

Electricity sold (GWh)

7,045 6,863 6,572 6,126 5,716

Number of customers (thousands)

1,255 1,203 1,144 1,098 1,061

Total energy losses (%) (1)

7.9% 8.2% 8.2% 8.3% 8.1%

Endesa Chile (Chile)

Installed capacity in Chile (MW) (2)

5,571 5,571 5,221 5,221 5,260

Installed capacity in Argentina (MW)

3,652 3,652 3,652 3,652 3,652

Installed capacity in Colombia (MW)

2,925 2,914 2,914 2,914 2,895

Installed capacity in Peru (MW)

1,540 1,657 1,668 1,668 1,667

Generation in Chile (GWh) (2) (3)

19,438 19,194 19,296 19,096 20,266

Generation in Argentina (GWh) (3)

10,840 11,207 10,713 10,862 11,877

Generation in Colombia (GWh) (3)

12,748 13,251 12,051 11,237 12,622

Generation in Peru (GWh) (3)

8,391 8,570 8,980 8,293 7,984

Endesa Brasil (Brazil)

Installed capacity in Brazil (MW)

987 987 987 987 987

Generation in Brazil (GWh) (3)

4,992 5,183 4,129 5,044 3,127

Dock Sud (Argentina) (4)

Installed capacity in Argentina (MW)

870 n.a n.a n.a n.a

Generation in Argentina (GWh)

3,582 n.a n.a n.a n.a

EEPSA (Peru) (4)

Installed capacity in Peru (MW)

302 n.a n.a n.a n.a

Generation in Peru (GWh)

98 n.a n.a n.a n.a

(1) Energy losses are calculated as the difference between total energy purchased (GWh of electricity demand, including own generation) and the energy sold (GWh), within a given period. Losses are expressed as a percentage of total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical failures.
(2) Excludes the proportional capacity and generation of GasAtacama, which was included in previous filings, because GasAtacama is now recorded under the equity method due to the application of IFRS 11.
(3) Beginning in 2013, we changed how we calculate our electricity generation. The impact of applying the new criteria on a cumulative basis for 2009 through 2012 is not material. We now report the energy effectively available for sales in all countries.
(4) As a result of our capital increase, Dock Sud in Argentina and EEPSA in Peru were contributed by Endesa Spain and their consolidation by Enersis began as of April 2013; therefore, 2013 data only includes the nine-month period from April through December 2013.

16


Table of Contents

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 ), the Chilean Electronic Stock Exchange ( Bolsa Electrónica de Chile ) and the Valparaíso Stock Exchange ( Bolsa de Corredores de Valparaíso ). These exchange rate fluctuations will likely affect the price of our ADSs and the conversion of cash dividends relating to the common shares represented by ADSs from Chilean pesos to U.S. dollars. In addition, to the extent that significant financial liabilities of the Company are denominated in foreign currencies, exchange rate fluctuations may have a significant impact on earnings.

In Chile, there are two currency markets, the Formal Exchange Market ( Mercado Cambiario Formal ) and the Informal Exchange Market ( Mercado Cambiario Informal ). The Formal Exchange Market is comprised of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market is comprised of entities that are not expressly authorized to operate in the Formal Exchange Market, such as certain foreign exchange houses and travel agencies, among others. The Central Bank of Chile has the authority to require that certain purchases and sales of foreign currencies be carried out on the Formal Exchange Market. Both the Formal and Informal Exchange Markets are driven by free market forces. Current regulations require that the Central Bank of Chile be informed of certain transactions and that they be effected through the Formal Exchange Market.

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 web page, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Nevertheless, the Central Bank of Chile may intervene by buying or selling foreign currency on the Formal Exchange Market to attempt to maintain the Observed Exchange Rate within a desired range.

The Informal Exchange Market reflects transactions carried out at an informal exchange rate (the “Informal Exchange Rate”). There are no limits imposed on the extent to which the rate of exchange in the Informal Exchange Market can fluctuate above or below the Observed Exchange Rate. Foreign currency for payments and distributions with respect to the ADSs may be purchased either in the Formal or the Informal Exchange Market, but such payments and distributions must be remitted through the Formal Exchange Market. The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. As of December 31, 2013, the U.S. dollar exchange rate used by us was Ch$ 524.61 per US$ 1.00.

The following table sets forth the low, high, average and period-end Observed Exchange Rate for U.S. dollars for the periods set forth below, as reported by the Central Bank of Chile:

Daily Observed Exchange Rate (Ch$ per US$) (1)

Year ended December 31,

Low (2) High (2) Average (3) Period-end

2013

466.50 533.95 498.83 524.61

2012

469.65 519.69 486.31 479.96

2011

455.91 533.74 483.45 519.20

2010

468.01 549.17 510.38 468.01

2009

491.09 643.87 554.22 507.10

Month ended

March 2014

550.53 573.24 n.a. 551.18

February 2014

546.94 563.32 n.a. 559.38

January 2014

527.53 553.84 n.a. 553.84

December 2013

523.76 533.95 n.a. 524.61

November 2013

512.53 529.64 n.a. 529.64

October 2013

493.96 508.58 n.a. 507.64

Source: Central Bank of Chile .

(1) Nominal figures.
(2) Exchange rates are the actual low and high, on a day-by-day basis for each period.
(3) The average of the exchange rates on the last day of each month during the period.

17


Table of Contents

As of March 31, 2014, the U.S. dollar exchange rate was Ch$ 551.18 per US$ 1.00.

Calculation of the appreciation or devaluation of the Chilean peso against the U.S. dollar in any given period is made by determining the percent change between the reciprocals of the Chilean peso equivalent of US$ 1.00 at the end of the preceding period and the end of the period for which the calculation is being made. For example, to calculate the appreciation of the year-end Chilean peso in 2013, one determines the percent change between the reciprocal of Ch$ 479.96 (the value of one U.S. dollar as of December 31, 2012) and the reciprocal of Ch$ 524.61(the value of one U.S. dollar as of December 31, 2013). In this example, the percentage change between 0.002084 (the reciprocal of Ch$ 479.96) and 0.001906 (the reciprocal of Ch$ 524.61) is negative 8.5 %, which represents the 2013 year-end devaluation of the Chilean peso against the 2012 year-end U.S. dollar. A positive percentage change means that the Chilean peso appreciated against the U.S. dollar, while a negative percentage change means that the Chilean peso devaluated against the U.S. dollar.

The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2009 through December 31, 2013 and through the date indicated in the table below, based on information published by the Central Bank of Chile.

Chilean Peso Equivalent of US$  1
Period End Appreciation (Devaluation) (1)
(in Ch$) (in %)

Year Ended December 31,

2013

524.61 (8.5)

2012

479.96 8.2

2011

519.20 (9.9)

2010

468.01 8.4

2009

507.10 25.5

Source: Central Bank of Chile .

(1) Calculated based on the variation of period-end exchange rates.

B. Capitalization and Indebtedness.

Not applicable.

C. Reasons for the Offer and Use of Proceeds.

Not applicable.

D. Risk Factors.

A financial or other crisis 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 five countries in which we operate are vulnerable to external shocks, including financial and political events, which could cause significant economic difficulties and affect their growth. If any of these economies experience lower than expected economic growth or a recession, it is likely that our customers will demand less electricity. Furthermore, 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 crisis in other parts of the world could also adversely affect our business. For example, the current crisis in Ukraine could result in higher fuel prices worldwide, which in turn could increase our cost of fuel for our thermal generation plants and adversely affect our results of operations and financial condition.

18


Table of Contents

In addition, a 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. Our ability to tap the capital markets in the five countries in which we operate, as well as the international capital markets for other sources of liquidity, may also be diminished, or such financing may be available only at higher interest levels. 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 are likely to affect our results from operations and financial condition, as well as the value of our securities.

All of our operations are located in five South American countries. 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 five countries in which we have investments or operations, our financial condition and results from operations could be adversely affected. Moreover, we have investments in volatile countries, such as Argentina. Insufficient cash flows for our subsidiaries located in Argentina have, in some cases, resulted in their inability to meet debt obligations and the need to seek waivers to comply with restrictive debt covenants.

The majority of our operating income is generated in Brazil and Chile and 62% of our operating revenues in 2013 were derived from our operations in these countries, and as a result our financial condition and results of operations are particularly dependent on Brazilian and Chilean economic performance. In 2013, Brazilian GDP increased 2.3% compared to a 1.0% increase in 2012. In 2014, Brazilian GDP is forecast to grow by 2.3% according to the International Monetary Fund. In 2013, Chilean GDP increased by 4.2% compared to a 5.6% increase in 2012. In 2014, Chilean GDP is forecast to grow by 3.75% to 4.75% according to the Central Bank of Chile. Future adverse developments in these economies may impair our ability to execute our strategic plans, which could adversely affect our results of operations and financial condition.

In addition, South American financial and securities markets are, to varying degrees, influenced by economic and market conditions in other countries. Although economic conditions are different in each country, investor reaction to developments in one country may have a significant contagion effect on the securities of issuers in other countries, including Brazil and Chile. Brazilian and Chilean financial and securities markets may be adversely affected by events in other countries, which could adversely affect the value of our securities.

A continuing financial crisis in Argentina or a deeper devaluation of the Argentine peso could have an adverse effect on our debt.

The Argentine peso is under increasing devaluation pressure against the U.S. dollar. The Argentine government is actively intervening in the currency market in response to capital flight from the country. Currently, Argentina is making incremental adjustments to the Argentine peso and imposing tight restrictions on buying and selling foreign currencies in the country. Media reports from the country describe a robust informal parallel market (referred to as the blue dollar market) in which the Argentine peso appears to have depreciated more steeply than the “official” rate. Because there is no liquidity in the derivatives market in Argentina, our debt is exposed to further devaluation of the Argentine peso.

Argentina’s sovereign creditworthiness is deteriorating, based on market data and reports from credit ratings agencies. The insurance cost of sovereign bonds, as measured by credit default swaps, increased to 16.5% from 14.4% in 2013, which indicates an increased probability of a distressed credit event. Argentina’s sovereign debt rating is subject to downgrade actions over the coming months as reflected by the negative outlook established by the major rating agencies. For instance, Standard & Poor’s downgraded the country’s sovereign credit rating to “CCC+” and maintained a negative outlook as of September 2013. Further deterioration to Argentina’s economy could adversely affect our results of operations and financial condition.

19


Table of Contents

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 the economies of Argentina, Brazil, Colombia and Peru. To a lesser extent, the Chilean government has also exercised in the past and continues to exercise a substantial influence over many aspects of the private sector, which may result in changes to economic or other policies. These governmental actions, intended to control inflation and affect other policies, have often involved wage, price and tariff rate controls, as well as other interventionist measures, such as expropriation or nationalization. For example, Argentina froze bank accounts and imposed capital restrictions in 2001, nationalized the private sector pension funds in 2008, used its Central Bank reserves to pay down indebtedness maturing in 2010 and expropriated Repsol’s 51% stake in YPF in 2012. In 2010, Colombia imposed an equity tax to finance reconstruction and repair efforts related to severe flooding, which resulted in an extraordinary tax expense accrual booked in January 2011 for taxes payable in 2011 through 2014.

Changes in the policies of these governmental and monetary authorities with respect to 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. Any of these scenarios could adversely affect our results of operations and financial condition.

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, pipelines, LNG terminals and re-gasification plants, storage and chartered LNG tankers. Our facilities may be damaged by earthquakes, flooding, fires, other catastrophic disasters arising from natural or accidental human causes, as well as acts of terrorism. A catastrophic event could cause 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 maximums.

As an example, on February 27, 2010, Chile experienced a major earthquake in the Bío-Bío region, with a magnitude of 8.8 on the Richter scale, followed by a very destructive tsunami. Our Bocamina and Bocamina II thermal generation units, which are located near the epicenter, sustained significant damage as a result of the earthquake.

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, 2013, our debt totaled Ch$ 3,697 billion.

Our debt had the following maturity timetable:

• Ch$ 907 billion in 2014;
• Ch$ 773 billion from 2015 to 2016;
• Ch$ 597 billion from 2017 to 2018; and
• Ch$ 1,420 billion thereafter.

20


Table of Contents

Set forth below is a breakdown by country for debt maturing in 2014:

• Ch$ 447 billion for Chile;
• Ch$ 186 billion for Argentina;
• Ch$ 136 billion for Colombia
• Ch$ 71 billion for Peru; and
• Ch$ 67 billion for Brazil.

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 our subsidiaries breach any of these material contractual provisions, our creditors and bond holders 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, Argentina continues to be the country in which we operate with the highest refinancing risk. As of December 31, 2013, the third-party debt of our Argentine subsidiaries amounted to Ch$ 205 billion. As long as fundamental issues concerning the electricity sector remain unresolved, we will roll over our outstanding Argentine debt to the extent we are able to do so. If our creditors will not continue to roll over our debt when it becomes due and we are unable to refinance such obligations, we could default on such indebtedness.

Our Argentine subsidiary, Endesa Costanera, did not make any installment payments due in 2012 and 2013 under the terms of a 1996 supplier credit agreement with Mitsubishi Corporation (“MC”). As of December 31, 2013, Endesa Costanera has missed US$ 68.5 million in payments, including principal and interest. It has experienced difficulties in making timely payments under its agreement with MC on a recurring basis since the Argentine crisis began in 2002, but had received waivers from MC in the past expressing its willingness to renegotiate payments. Additionally, MC has liens over the Mitsubishi combined cycle power plant at Endesa Costanera.

As of the date of this Report, Endesa Costanera has not received any waivers for the past-due payments or any acceleration notices. We continue with active negotiations aimed at restructuring the debt. If MC were to declare an event of default and accelerate payment of the US$ 185 million principal and interest balance under the supplier credit agreement, all outstanding Endesa Costanera debt (Ch$ 117 billion) would be accelerated and Endesa Costanera would be required to enter into bankruptcy proceedings. For more information, see “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources”.

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.

21


Table of Contents

We may not be able to enter into suitable investments, alliances and acquisitions.

On an ongoing basis, we review acquisition prospects that would augment our market coverage or supplement 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 or companies that we do not control is generally a complex, costly and time-consuming process and requires significant efforts and expenditures. If we consummate an acquisition, it could result in the incurrence of substantial debt and assumption of unknown liabilities, the potential loss of key employees from the acquired company, amortization expenses related to tangible assets and the diversion of our management’s attention from other business concerns. In addition, any delays or difficulties encountered in connection with acquisitions and the integration of multiple operations could have a material adverse effect on our business, financial condition or results of operations.

Since our generation business depends heavily on hydrological conditions, drought conditions may adversely affect our profitability.

Approximately 55% of our consolidated installed generation capacity in 2013 was hydroelectric. Accordingly, extreme hydrological conditions could adversely affect our business, results of operations and financial condition. In the last few years, regional hydrology has been affected by two climactic phenomena — El Niño and La Niña — that influence rainfall regularity and may lead to droughts. The effects of El Niño or La Niña can unevenly affect the hydrology of the countries where we operate.

During periods of drought, thermal plants, including our facilities that use natural gas, fuel oil or coal as fuel, are used more frequently. Operating costs of thermal plants can be considerably higher than those of hydroelectric plants. Our operating expenses increase during these periods, and, depending on our commercial obligations, we may have to buy electricity at spot prices in order to meet our contractual supply obligations. The cost of these electricity purchases may exceed the price at which we sell contracted electricity, thus producing losses from those contracts.

Governmental regulations may adversely affect our business

We are subject to extensive regulation of the tariffs we charge our customers and other aspects of our business and these regulations may adversely affect our profitability. For example, the Chilean government can impose electricity rationing during drought conditions or prolonged failures of power facilities. If, during rationing, we are unable to generate enough electricity to comply with our contractual obligations, we may be forced to buy electricity at the spot price, as even a severe drought does not release us from our contractual obligations as a force majeure event. The spot price may be significantly higher than our costs to generate the electricity and can be as high as the “cost of failure” set by the Chilean National Energy Commission (the “CNE”). This “cost of failure”, which is updated semiannually by the CNE, is a measurement of how much final users would pay for one extra MWh under rationing conditions. If we were unable to buy enough electricity at the spot price to comply with our contractual obligations, then we would have to compensate our regulated customers for the electricity we failed to provide at the rationed price. Rationing periods may occur in the future, and consequently our generation subsidiaries may be required to pay regulatory penalties if they fail to provide adequate service under their contractual obligations. Material rationing policies imposed by regulatory authorities in any of the countries in which we operate could adversely affect our business, results of operations and financial condition.

Governmental authorities may also delay the distribution tariff review process, or tariff adjustments determined by governmental authorities may not be sufficient to pass through our costs (as has been the case with Edesur, our Argentine distribution subsidiary). Similarly, electricity regulations issued by governmental authorities in the countries in which we operate may affect the ability of our generation companies (such as Endesa Costanera and Dock Sud in Argentina) to collect revenues sufficient to offset their operating costs.

The inability of any company in our consolidated group to collect revenues sufficient to cover operating costs may affect the ability of the affected company to operate as a going concern and may otherwise have an adverse effect on our business, assets, financial results and operations.

In addition, changes in the regulatory framework are often submitted to the legislators and administrative authorities in the countries in which we operate and, if approved, could have a material adverse impact on our business. For instance, in 2005 there was a change in the water rights’ law in Chile that requires us to pay for unused water rights.

22


Table of Contents

Regulatory authorities may impose fines on our subsidiaries, which could adversely affect our results of operations and financial condition.

Our electricity businesses may be subject to regulatory fines for any breach of current regulations, including energy supply failures, in the five countries in which we operate. In Chile, such fines may be imposed for a maximum of 10,000 Annual Tax Units ( Unidades Tributarias Anuales ) (“UTA”), or Ch$ 4.9 billion, using the UTA and foreign exchange rate as of December 31, 2013. In Peru, fines may be imposed for a maximum of 1,400 Treasury Tax Units ( Unidad Impositiva Tributaria ) (“UIT”) or Ch$ 972 million using the rates as of December 31, 2013. In Colombia, fines may be imposed for a maximum of 2,000 Minimum Monthly Salaries ( Salarios Mínimos Mensuales ) or Ch$ 315 million. In Argentina, there is no maximum limit for the fines. In Brazil, fines may be imposed for up to 2.0% of an electricity company’s revenues.

Our electricity generation subsidiaries, supervised by their local regulatory entities, may be subject to these fines in cases where, in the opinion of the regulatory entity, operational failures affecting the regular energy supply to the system are the fault of the company; for instance, when the agents are not coordinated with the system operator. In addition, our subsidiaries may be required to pay fines or to compensate customers if those subsidiaries are unable to deliver electricity, even if such failure is due to forces outside of the subsidiaries’ control.

For example, in 2013, ANEEL imposed fines of Ch$ 6.8 billion on Ampla and Ch$ 8 billion on Coelce due to technical and commercial operation failures. In 2013, ENRE imposed fines on Edesur for a total of Ch$ 4.9 billion. In 2011, the Chilean Superintendency of Electricity and Fuels ( Superintendencia de Electricidad y Combustibles ) (“SEF”) imposed Ch$ 953 million in fines on Endesa Chile, Pehuenche and Chilectra due to a blackout that occurred in the Santiago metropolitan region in March 2010. For further information on fines, please refer to Note 37 to our Consolidated Financial Statements.

We depend in part on payments from our subsidiaries, jointly-controlled entities and associates to meet our payment obligations.

In order to pay our obligations, we rely partly on cash from dividends, loans, interest payments, capital reductions, and other distributions from our subsidiaries and equity affiliates. The ability of our subsidiaries and equity affiliates to pay dividends, interest payments, loans, and other distributions to us is subject to legal constraints such as dividend restrictions, fiduciary duties, contractual limitations, and foreign exchange controls that may be imposed in any of the five countries where they operate.

Historically, we have been able to access the cash flows of our Chilean subsidiaries, but we have not been similarly able to access at all times the cash flows of our non-Chilean operating subsidiaries due to government regulations, strategic considerations, economic conditions, and credit restrictions.

Our future results from operations outside Chile may continue to be subject to greater economic and political uncertainties than what we have experienced in Chile, thereby reducing the likelihood that we will 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 non-Chilean 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 non-Chilean 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 fiduciary duties of the directors of such subsidiaries to their minority shareholders. Furthermore, some of our subsidiaries may be forced by local authorities, in accordance with applicable regulation, to diminish or eliminate dividend payments. As a consequence of such restrictions, our subsidiaries could, under certain circumstances, be prevented from distributing cash to us.

Contractual Constraints . Distribution restrictions included in certain credit agreements of our subsidiaries Endesa Costanera, El Chocón and Endesa Fortaleza, may prevent dividends and other distributions to shareholders if they are not in compliance with certain financial ratios. Generally, our credit agreements prohibit any type of distribution if there is an ongoing default.

23


Table of Contents

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, the subsidiary will not be able to make cash available to us.

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

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

The currencies of South American countries in which we and our subsidiaries operate have been subject to large devaluations and appreciations against the U.S. dollar and may be subject to significant fluctuations in the future. Historically, a significant portion of our consolidated indebtedness has been denominated in U.S. dollars. Although a substantial portion of our operating cash flows is linked to U.S. dollars, 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.

In countries where operating cash flows are denominated in the local currency, we seek to maintain debt in the same currency, but due to market conditions it may not be possible to do so. The most material example is in Argentina, where most of our debt is denominated in U.S. dollars while our revenues are mostly in Argentine pesos.

Because of this exposure, the cash generated by our subsidiaries can decrease substantially when local currencies devalue against the U.S. dollar. Future volatility in the exchange rate of the currencies in which we receive revenues or incur expenditures may affect our financial condition and results from operations.

As of December 31, 2013, the amount of Enersis’ total consolidated debt was Ch$ 3,697 billion (net of currency hedging instruments). Of this amount, Ch$ 1,309 billion, or 35%, was denominated in U.S. dollars and Ch$ 335 billion in Chilean pesos. As of December 31, 2013, our consolidated foreign currency-denominated indebtedness (other than U.S. dollars or Chilean pesos) included the equivalent of:

• Ch$ 1,233 billion in Colombian pesos;
• Ch$ 551 billion in Brazilian reais;
• Ch$ 222 billion in Peruvian soles; and
• Ch$ 47 billion in Argentine pesos.

These amounts total Ch$ 2,053 billion in currencies other than U.S. dollars or Chilean pesos.

For the twelve-month period ended December 31, 2013, our operating cash flows were Ch$ 1,737 billion (before consolidation adjustments) of which:

• Ch$ 479 billion, or 28%, came from Colombia;
• Ch$ 463 billion, or 27%, came from Brazil;
• Ch$ 447 billion, or 26%, came from Chile;
• Ch$ 175 billion, or 10%, came from Peru; and
• Ch$ 173 billion, or 10%, came from Argentina

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, and we will continue to be subject to future litigation proceedings, which could cause material adverse consequences to our business.

For example, in December 2013, a court granted an injunction in favor of local fishermen ordering a temporary shutdown of our Bocamina II facility. While we are appealing the case, the plant remains shut down and our operating income is reduced between US$ 20 million and US$ 44 million each month the facility is shut down. Our financial condition or results from operations could be adversely affected if we are unsuccessful in defending this litigation or other lawsuits and proceedings against us.

24


Table of Contents

The values of our generation subsidiaries’ long-term energy supply contracts are subject to fluctuations in the market prices of certain commodities 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. We and our subsidiaries have material obligations as selling parties under long-term fixed-price electricity sales contracts. Prices in these contracts are indexed according to 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 results of operations and financial condition.

Our controlling shareholders may have conflicts of interest relating to our business.

Enel owns 92.1% of Endesa Spain, which in turn beneficially owns 60.6% of Enersis’ share capital. Our controlling shareholders have the power to determine the outcome of most material matters that require shareholders’ votes, such as the election of the majority of our board members and, subject to contractual and legal restrictions, the distribution of dividends. Our controlling shareholders also can exercise influence over our business strategy and operations. Their interests may in some cases differ from those of the other shareholders. Enel and Endesa Spain conduct their business operations in the field of renewable energies in South America through Enel Green Power S.p.A., in which we do not have an equity interest.

Environmental regulations in the countries in which we operate and other factors may cause delays, impede the development of new projects or increase the costs of operations and capital expenditures.

Our operating subsidiaries are subject to environmental regulations which, among other things, require us to perform environmental impact studies for future projects and obtain permits from both local and national regulators. The approval of these environmental impact studies may take longer than planned and may be withheld by governmental authorities. Local communities and ethnic and environmental activists, among others, may intervene in the approval process to delay or prevent a project’s development. They may also seek injunctive or other relief, which could negatively impact us if they are successful.

Environmental regulations for existing and future generation capacity may become stricter, requiring increased capital investments. For example, Decree 13 of the Chilean Ministry of the Environment promulgated in January 2011, and published in June 2011, defined stricter emission standards for thermoelectric plants that must be met between 2014 and 2016 and stricter standards for new facilities or additional capacity.

In 2009, we presented our 740 MW coal fueled Punta Alcalde project for environmental approval in Chile. In 2012, the regional environmental authority rejected the project. We appealed to the Council of Ministers. Even though the Council unanimously reversed the decision of the environmental authority, the Court of Appeals accepted four injunctions against us in early 2013. Ultimately, the Chilean Supreme Court ruled that the project could proceed in January 2014.

In addition to environmental matters, there are other factors that may adversely affect our ability to build new facilities or to complete projects currently under development on time, including delays in obtaining regulatory approvals, shortages or increases in the price of equipment, materials or labor, strikes, adverse weather conditions, natural disasters, civil unrest, accidents, or other unforeseen events.

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 for companies in which we hold investments, which could adversely affect our results of operations and financial condition.

25


Table of Contents

Our business may be adversely affected by judicial decisions on environmental qualification resolutions for electricity projects in Chile.

The environmental qualification resolutions term for electricity generation or transmission projects in Chile has more than doubled, due primarily to judicial decisions against such projects, environmental opposition, social criticism and government delays. This can cast doubt on the ability of a project to obtain such approval, and increase the uncertainty for investing in electricity generation and transmission projects in Chile. The uncertainty is forcing companies to reassess their business strategies as the delay in the construction of electricity generation and transmission projects may result in a supply constraints over the next five or six years. If any plant within the system ceases operation unexpectedly, we could experience supply shortages in our system, which could lead to power cuts.

For example, in August 2008, the HidroAysén environmental impact assessment study was submitted for approval. In May 2011, a favorable environmental qualification resolution was reached. In June 2011, HidroAysén filed an appeal with the Council of Ministers requesting its review of certain conditions established by the environmental authorities. On January 30, 2014, the Council of Ministers met to review the appeals and the majority of them were resolved. The Council of Ministers requested new background information and studies in order for the Council to perform a new evaluation and issue its decision regarding the project.

In March 2014, Chilean President Michelle Bachelet took office and a new Council of Ministers was convened, which repealed the decisions taken in January 2014. The new Council stated it would study the issue again and resolve all claims within the 60 business day timeframe established by law.

Our power plant projects may encounter significant opposition from groups that may ultimately damage our reputation and could result in impairment of goodwill with stakeholders.

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, which could negatively impact sentiments toward us, our ability to operate could be impaired and our financial results could suffer.

The development of new power plants may face opposition from several stakeholders, such as ethnic groups, environmental groups, land owners, farmers, local communities and political parties, among others, all of which may impact the sponsoring company’s reputation and goodwill. For example, our HidroAysén project has encountered substantial opposition by environmental activists. Such groups are sometimes financed internationally and may receive global attention. Similarly, the El Quimbo hydroelectric project in Colombia faced constant social demands that have delayed construction and increased costs. Between August 16, 2013 and September 9, 2013, a national agricultural strike involving communities near the project blocked roads and occupied neighboring lands.

The operation of our current thermal power plants may also affect our goodwill with stakeholders, due to emissions such as particulate matter, sulfur dioxide and nitrogen oxides, which could adversely affect the environment.

Damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders, and ultimately lead to projects and operations that may not be optimal, cause our share prices to drop and hinder our ability to attract or retain valuable employees, all of which could result in an impairment of goodwill with stakeholders.

26


Table of Contents

Our business may experience adverse consequences if we are unable to reach satisfactory collective bargaining agreements with our unionized 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 agreement if the parties are unable to come to an agreement, which may increase our costs beyond what we have budgeted.

In addition, we employ many highly-specialized employees, and certain actions such as strikes, walk-outs or work stoppages by these employees could negatively impact our operating and financial performance, as well as our reputation.

Interruption or failure of our information technology and communications systems or external attacks to or invasions of these systems could have an adverse effect on our operations and results.

We depend on information technology, communication and processing systems (“IT Systems”) to operate our businesses, the failure of which could adversely affect our financial condition and results of operations.

IT Systems are all vital to our generation subsidiaries’ ability to monitor our power plants’ operations, maintain generation and network performance, adequately generate invoices to customers, achieve operating efficiencies and meet our service targets and standards. Our distribution subsidiaries could also be affected adversely since they rely heavily on IT systems to monitor their grids, billing processes for millions of customers and customer service platforms, among others. Temporary or long-lasting operational failures of any of these IT Systems could have a material adverse effect on our results of operations. Additionally, cyber attacks can have an adverse effect on the company’s image and its relationship with the community.

In the last few years, global cyber attacks on security systems, treasury operations, and IT Systems have intensified. We are exposed to cyber-terrorist attacks aimed at damaging our assets through computer networks, cyber spying involving strategic information that may be beneficial for third parties and cyber-theft of proprietary and confidential information, including information of our customers. During 2013, we suffered a cyber attack organized by a group known as “Operation Green Rights” to protest the construction of proposed hydroelectric power plants in the Chilean Patagonia as well as other cyber attacks related to the operation of thermal power plants in the north and south of Chile.

We rely on electricity transmission facilities that we do not own or control. If these facilities do not provide us with an adequate transmission 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 unaffiliated power 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 financial results. On February 27, 2010, due to the 8.8 magnitude earthquake on the Richter scale in Chile, Transelec, a transmission company unrelated to us, experienced damage to its high voltage transmission network that prevented us from delivering our electricity to final consumers.

On September 24, 2011, nearly 10 million people located in central Chile experienced a blackout (affecting more than half of all Chileans), due to the failure of Transelec’s 220 kV Ancoa substation. The failure led to the disruption of two 500 kV transmission lines in the SIC (the Chilean Central Interconnected System) and the subsequent failure of the remote recovery computer software used by CDEC to operate the grid. This blackout, which lasted two hours, exposed weaknesses in the transmission grid and its need for expansion and technological improvements to increase the reliability of the transmission grid. Any such failure could interrupt our business, which could adversely affect our results of operations and financial condition.

27


Table of Contents

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

Chilean securities markets are substantially smaller and less liquid than the major securities markets in the United States. In addition, Chilean securities markets may be affected materially by developments in other emerging markets. The low liquidity of the Chilean market may impair the ability of holders of ADS 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.

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 assets are located outside of the United States. All of our directors and all of our officers reside outside of the United States and most of their assets are located outside the United States as well. If any investor were to bring a lawsuit against our directors, officers, or experts 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 against them, in United States or Chilean courts, judgments obtained in United States courts based upon the civil liability provisions of the federal securities laws of the United States. 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.

Item 4. Information on the Company

A.     History and Development of the Company.

History

Enersis S.A. (“Enersis”) is a publicly held limited liability stock corporation organized under the laws of the Republic of Chile. The existence of our company under its current name dates back to August 1, 1988.

The Company’s contact information in Chile is:

Street Address: Santa Rosa 76, Santiago, Código Postal 8330099, Chile
Telephone: (56-2) 2353-4639
Web site: www.enersis.cl

The Company’s authorized representative in the United States of America is Puglisi & Associates, whose contact information is:

Street Address: 850 Library Avenue, Suite 204, Newark, Delaware 19711
Telephone: 1 (302) 738-6680

We are an electricity utility company engaged, through our subsidiaries and affiliates, in the generation, transmission and distribution of electricity businesses in Chile, Argentina, Brazil, Colombia, and Peru.

We are one of the largest publicly listed companies in the electricity sector in South America. We trace our origins to Compañía Chilena de Electricidad Ltda. (“CCE”), 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”), with operations dating back to 1919. In 1970, the Chilean government nationalized CCE. During the 1980s, the sector was reorganized through the Chilean Electricity Law, known as the Decree with Force of Law Number 1 (“DFL 1”), CCE’s operations were divided into one generation company, the current AES Gener S.A. (“Gener”), a currently unrelated company, and two distribution companies, one with a concession in the Valparaíso

28


Table of Contents

Region, the current Chilquinta S.A., a currently 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. and became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A. In the 1990s, we diversified into electricity generation and transmission through our increasing equity stakes in Endesa Chile.

We began our international operations in 1992 with our investment in Edesur, an Argentine electricity distribution company. That same year, Endesa Chile, which at that time was an affiliated company, also started its international operations with its investment in Endesa Costanera, an electricity generation company. We then expanded primarily into electricity generation, transmission and distribution businesses in four South American countries: Argentina, Brazil, Colombia and Peru. We remain focused on the electricity sector, although we have small operations in other businesses that represent less than 1.0% of our consolidated assets, in the aggregate.

In 2005, Endesa Brasil was formed as a company to manage all generation, transmission and distribution assets that Endesa Latinoamérica, S.A.U., (“Endesa Latinoamérica”,) (a subsidiary of Endesa Spain formerly known as Endesa Internacional), Enersis, Endesa Chile and Chilectra held in Brazil; namely, through Ampla, Endesa Fortaleza, CIEN, Cachoeira Dourada and Coelce. As of December 31, 2013, Enersis had a 83.5% beneficial economic interest in Endesa Brasil.

In order to achieve synergies in Peru, in 2006, Edegel and Etevensa (60% of which was owned by Endesa Spain at the time) merged, creating a 457 MW thermoelectric generation company .

In September 2007, we merged our generation subsidiaries in Colombia to form Emgesa. As of December 31, 2013, Enersis had a 37.7% beneficial economic interest in Emgesa. Pursuant to the terms of a shareholders’ agreement, we control and therefore consolidate Emgesa through Endesa Chile.

In February 2009, Codensa, our Colombian distribution subsidiary, acquired approximately 49% of DECSA, an investment vehicle. The remaining 51% was acquired by Empresa de Energía de Bogotá (“EEB”). Codensa and EEB jointly control DECSA. In March 2009, DECSA acquired 82.3% of Empresa de Energía de Cundinamarca S.A. (“EEC”), a formerly state-owned company that was privatized that year. EEC is a Colombian company primarily engaged in trading of electricity in Cundinamarca province.

Since June 2009, Enel has ultimately controlled Enersis by virtue of its 92.1% equity interest in Endesa Spain. Endesa Spain beneficially owns 60.6% of the share capital of Enersis. Enel publicly trades on the Milan Stock Exchange, is headquartered in Italy and primarily engaged in the energy sector, with a presence in 40 countries worldwide, and approximately 99 GW of net installed capacity. It provides service to more than 61 million customers through its electricity and gas businesses.

In October 2009, Endesa Chile purchased an additional 29.4% of Edegel from Generalima, a Peruvian indirect subsidiary of Endesa Spain. With this transaction, Endesa Chile increased its economic interest in Edegel from 33.1% to 62.5% and in turn, our economic interest at the Enersis level increased to 37.5%. In the same month, we acquired additional share capital of our Peruvian subsidiary, Edelnor, increasing our direct and indirect ownership stake in Edelnor to 75.5%.

In March 2012, Endesa Latinoamérica announced a public offer to purchase the remaining shares representing 0.36% of the capital of Ampla and Ampla Investimentos e Serviços S.A. (“Ampla Investimentos”), from the minority shareholders. As a result of the public offer to purchase, Endesa Latinoamérica acquired 10,354,610 shares of Ampla, representing 0.0003% of its share capital and 361,569 shares of Ampla Investimentos, representing 0.003% of its share capital. The delisting of the securities of Ampla Investimentos was completed on May 25, 2012. In March 2013, as part of the 2013 capital increase, Endesa Latinoamérica contributed its interests in Ampla and Ampla Investmentos to Enersis.

29


Table of Contents

In June 2012, Endesa Spain proposed a capital increase in which it would carry out an in-kind contribution (the “In-Kind Contribution”) of all of its equity interests in 25 companies in the five South American countries in which Enersis operates. The rest of the shareholders would contribute their proportional participation in cash. The capital increase would involve 16,441,606,297 common shares to be issued at a subscription price of Ch$ 173 per common share (or the net dollar equivalent of Ch$ 8,650 per ADS) during the preemptive rights period. The value of Endesa Spain’s In-Kind Contribution would be US$ 3,615 million for which it would receive 9,967,630,058 common shares. The capital increase was approved by the shareholders at an Extraordinary Shareholders’ Meeting (“ESM”) held on December 20, 2012.

In February 2013, Enersis began preemptive rights offerings in Chile, the United States and Spain, in which shareholders (including Endesa Spain) subscribed for an aggregate of 99% of the capital increase by the expiration of the rights offering on March 26, 2013. On March 28, 2013, the remaining 1% was auctioned off in the Santiago Stock Exchange at Ch$ 182.3 per common share, 5.4% higher than the rights offering subscription price. The total US$ 6 billion capital increase consisted of approximately US$ 3.6 billion of In-Kind Contribution from Endesa Spain and US$ 2.4 billion in cash from minority shareholders. We began consolidating the companies contributed pursuant to the In-Kind Contribution on April 1, 2013.

In January 2014, as part of its initial use of proceeds from the capital increase, Enersis, launched a voluntary public offer for the shares of Coelce it did not already own, which ended on February 17, 2014. As a result, Enersis increased its economic interest in Coelce from 49.2% to 64.3%. For further detail, please see “Item 4. Information on the Company – Recent Developments”.

As of December 31, 2013, we had 15,848 MW of installed capacity with 199 power units in the five countries in which we operate, 14.2 million distribution customers covering approximately 50 million inhabitants, consolidated assets of Ch$ 15,178 billion and operating revenues of Ch$ 6,264 billion.

Capital Investments, Capital Expenditures and Divestitures

We coordinate our overall financing strategy including the terms and conditions of loans or intercompany advances entered into by our subsidiaries, in order to optimize debt and liquidity management. Our operating subsidiaries generally independently plan capital expenditures financed by internally generated funds or with direct financing. One of our goals is to focus on investments that will provide long-term benefits, such as energy loss reduction projects. Additionally, by focusing on Enersis as a group, and seeking to provide services groupwide, we aim to reduce investments at the individual subsidiary level in items such as procurement, telecommunication and information systems. Although we have considered how these investments will be financed as part of the Company’s budget process, we have not committed to any particular financing structure. Our 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 its profitability and strategic fit. Our current investment priorities include developing new, environmentally responsible hydroelectric and thermal projects in Chile and Colombia in order to guarantee adequate levels of reliable supply.

From 2014 through 2018, we expect to make capital expenditures of Ch$ 4,609 billion on a consolidated basis in our controlled subsidiaries, related to investments currently in progress, maintenance of our distribution network, maintenance of existing generation plants, and studies required to develop other potential generation projects. For further detail regarding these projects, please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Development”.

30


Table of Contents

The table below sets forth the expected capital expenditures from 2014 through 2018 and the capital expenditures incurred by our subsidiaries in 2013, 2012 and 2011:

Capital Expenditures (1)
2014-2018 2013 (1) 2012 (1) 2011 (1)
(in millions of Ch$)

Chile

1,259,408 128,240 125,601 145,758

Abroad

3,349,610 646,580 581,690 527,915

Total

4,609,018 774,820 707,291 673,673

(1) CAPEX figures represent actual payments for each year net of contributions, except for future projections.

Capital Expenditures 2013, 2012 and 2011

Our capital expenditures in the last three years were related principally to the 350 MW Bocamina II project in Chile and the 400 MW El Quimbo project in Colombia. Bocamina II began commercial operations in October 2012, with 350 MW of installed capacity. The El Quimbo project is still under construction. In July 2013, the “Reserva Fría” plant, a 183 MW gas turbine that serves as a backup for Peruvian system, began its operation in the Talara region. In November 2013, the first of the Salaco project’s hydro plants began its operation in Colombia. The project will add 144 MW of capacity to the system when completed. In addition, we also invested to: (i) expand distribution services in response to increasing demand for energy, (ii) improve service quality, (iii) improve safety and (iv) reduce energy losses, especially in Brazil.

For additional information regarding Bocamina II, which currently is not operating due to an environmental restriction, please see “Introduction — Recent Developments”.

Investments Currently in Progress

Our material plans in progress include completion of the El Quimbo project, which is expected to be finished by July 2015 and will add 400 MW of capacity to our Colombian operations. El Quimbo is being constructed in response to increased demand in that market. Additionally, we plan to continue to expand distribution services, reduce energy losses, and in turn, improve the efficiency and the profitability of our distribution operations, in Chile and abroad.

In general terms, projects in progress are expected to be financed with external and internal funds for each of the projects described.

B.     Business Overview.

We are a publicly held limited liability stock corporation with consolidated operations in Chile, Argentina, Brazil, Colombia, and Peru. Our core businesses are electricity generation, transmission and distribution. We also participate in other activities which are not part of our core business. Since these non-core activities represent less than 1% of our 2013 revenues, we do not report them as a separate business for purposes of this discussion, or under IFRS.

31


Table of Contents

The table below presents our revenues by business segment.

Year ended December 31,
2013 2012 2011 Change 2013 vs.
2012
(in millions of Ch$) (in %)

Generation and Transmission Business

Endesa Chile and subsidiaries (Chile) (1)

955,702 1,104,776 1,135,176 (13.5)

Endesa Costanera (Argentina)

94,888 295,140 341,824 (67.8)

El Chocón (Argentina)

36,687 49,193 48,341 (25.4)

Cachoeira Dourada (Brazil)

117,445 155,195 126,646 (24.3)

Endesa Fortaleza (Brazil)

168,871 139,186 129,485 21.3

CIEN (Brazil)

67,689 72,523 59,918 (6.7)

Emgesa (Colombia)

639,503 580,125 498,569 10.2

Edegel (Peru)

283,806 282,124 239,842 0.6

Cemsa (Argentina)

1,591 — — n.a

Dock Sud (Argentina)

41,186 — — n.a

EEPSA (Peru)

33,752 — — n.a.

Total

2,441,120 2,678,262 2,579,801 (8.9)

Distribution Business

Chilectra and subsidiaries (Chile)

975,024 984,738 1,046,191 (1.0)

Edesur (Argentina)

528,653 321,242 279,725 64.6

Edelnor (Peru)

413,911 385,014 329,309 7.5

Ampla (Brazil)

945,131 1,074,237 1,117,269 (12.0)

Coelce (Brazil)

688,981 806,428 859,446 (14.6)

Codensa (Colombia) (1)

852,780 851,622 783,050 0.1

Total

4,404,480 4,423,281 4,414,990 (0.4)

Less: Consolidation adjustments and non-core activities

(581,154) (605,590) (608,191) (4.0)

Total

6,264,446 6,495,953 6,386,600 (3.6)

(1) Restated in accordance with IFRS 11.

For further information related to operating revenues and total income by business segment, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 34.2 to our Consolidated Financial Statements.

Electricity Generation Business Segment

As of December 31, 2013, electricity generation represented 36% of our operating revenues and 64% of our operating income before consolidation adjustments.

Operating and financial data presented in this Report differs from those previously reported, due to:

• application of IFRS 11, “Joint Arrangements” pursuant to which jointly controlled companies as of January 1, 2013 are now recorded using the equity method. Until December 31, 2012, they were consolidated using the proportionate consolidation method. With respect to our generation business, the application of IFRS 11 requires us to exclude GasAtacama figures from 2012 and 2011; and

•

changes to what we define as “electricity generation”, which we now define as total generation output minus (i) the electricity consumed by the facilities themselves, (ii) consumption by external auxiliary facilities, (iii) losses in transmission and (iv) technical losses, which definition is uniformly applied to all countries. We have recalculated the operating data for 2009 through 2012, however we believe the differences in calculation methods are not material. Our

32


Table of Contents

consolidated installed capacity as of December 31, 2013 was 15,846 MW, of which 54.8% was hydroelectric capacity, 44.7% was thermal electric and 0.5% was wind power generation capacity. Total installed capacity is defined as the maximum power capacity (measured in MW generation units) under specific technical conditions and characteristics.

• Consolidation of companies contributed by Endesa Spain as part of our capital increase, as of April 1, 2013. This only impacts 2013 and has no effect on prior years presented.

Our consolidated electricity sales for 2013 were 69,369 GWh and our production was 60,089 GWh, 5.2% and 4.7% higher than in 2012, respectively. Since April 2013, Enersis also consolidates Dock Sud in Argentina and EEPSA in Peru, which were contributed as part of our capital increase as of April 1, 2013, partly explaining the increases in 2013 when compared with 2012.

Our total installed capacity in 2013 was 15,846 MW, 1,065 MW higher than in December 31, 2012, due to the following changes: the incorporation of 869 MW of Dock Sud and 302 MW of EEPSA, 50 MW increase in Emgesa’s Darío Valencia 2 unit; 4.2 MW increase in Edegel’s Matucana unit, partially offset by the decommissioning of Edegel’s 121 MW Santa Rosa TG 7 unit, and Emgesa’s 39 MW La Tinta and La Junca. Our electricity generation business is conducted primarily through Endesa Chile, which has consolidated operations in Chile, Colombia, Peru and Argentina. We also have separate consolidated operations in Brazil through Endesa Brasil, in Argentina through Dock Sud and in Peru through EEPSA.

33


Table of Contents

The following tables summarize the information relating to Enersis’ electricity generation:

ENERSIS ELECTRICITY DATA PER COUNTRY

Year ended December 31,
2013 2012 2011

Chile (1)

Number of generating units (2) (3)

105 105 104

Installed capacity (MW) (3) (4)

5,571 5,571 5,221

Electricity generation (GWh) (5)

19,438 19,194 19,296

Energy sales (GWh)

20,406 20,878 20,315

Argentina (6)

Number of generating units (2)

25 20 20

Installed capacity (MW) (4)

4,522 3,652 3,652

Electricity generation (GWh) (5)

14,422 11,207 10,713

Energy sales (GWh)

16,549 11,852 11,381

Brazil

Number of generating units (2)

13 13 13

Installed capacity (MW) (4)

987 987 987

Electricity generation (GWh) (5)

4,992 5,183 4,129

Energy sales (GWh)

6,826 7,291 6,828

Colombia

Number of generating units (2) (3)

29 30 30

Installed capacity (MW) (3) (4)

2,925 2,914 2,914

Electricity generation (GWh) (5)

12,748 13,251 12,051

Energy sales (GWh)

16,090 16,304 15,112

Peru (7)

Number of generating units (2)

27 25 25

Installed capacity (MW) (3)(4)

1,842 1,657 1,668

Electricity generation (GWh) (5)

8,489 8,570 8,980

Energy sales (GWh)

9,497 9,587 9,450

Total

Number of generating units (2)

199 193 192

Installed capacity (MW) (4)

15,846 14,781 14,442

Electricity generation (GWh) (5)

60,089 57,405 55,169

Energy sales (GWh)

69,369 65,913 63,086

(1) Excludes GasAtacama, which was included in previous reports.
(2) For details on generation facilities, see “Item 4. Information on the Company — D. Property, Plant and Equipment — Property, Plant and Equipment of Generating Companies”.
(3) The Bocamina II TV2 generation unit in Chile has been consolidated since April 2012; the Darío Valencia hydro plant in Colombia has been consolidated since November 2013 and Unit 2 of Matucana hydro plant in Peru increased its installed capacity in June 2013. In October 2013, La Junca and La Tinta Unit 5, both mini hydro plants in Colombia, and the TG 7 unit of Santa Rosa in Peru, were decommissioned.
(4) Total installed capacity is defined as the maximum MW capacity in generation units, 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.
(5) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(6) The 2013 data for Argentina includes the data of subsidiaries of Endesa Chile in Argentina (Endesa Costanera and El Chocón) and, since April 1, 2013, Dock Sud, which became a subsidiary in connection with our capital increase.
(7) The 2013 data for Peru includes the data of a subsidiary of Endesa Chile in Peru (Edegel) and, since April 1, 2013, EEPSA, which became a subsidiary in connection with our capital increase.

34


Table of Contents

In the electricity industry, it is common to segment the business into hydroelectric and thermoelectric generation, because each type of generation has significantly different variable costs. Thermoelectric generation requires the purchase of fuel, thereby leading to high variable costs as compared with hydro generation from reservoirs or rivers with no marginal costs. Of our total consolidated generation in 2013, 51.4% was from hydroelectric sources, 48.4% came from thermal sources, and wind energy represented less than 1%.

The following table summarizes Enersis’ consolidated generation by type of energy:

ENERSIS CONSOLIDATED GENERATION BY TYPE OF ENERGY (GWh) (1)

Year ended December 31,
2013 2012 (3) 2011 (3)
Generation % Generation % Generation %

Hydroelectric

30,869 51.4 34,499 60.1 33,325 60.4

Thermal (2)

29,076 48.4 22,752 39.6 21,712 39.4

Other generation (3)

145 0.2 153 0.3 132 0.2

Total generation

60,089 100.0 57,405 100.0 55,169 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(2) Excludes GasAtacama, which was included in previous reports.
(3) Other generation refers to the generation from the Canela and Canela II wind farms.

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, such as residential customers subject to government regulated electricity tariffs, 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 price of energy with generators based on the characteristics of the service required. Finally, the pool market, where energy is normally sold at the spot price, is not carried out through contracted pricing.

The following table contains information regarding Enersis’ consolidated sales of electricity by type of customer for each of the periods indicated:

ENERSIS CONSOLIDATED ELECTRICITY SALES BY CUSTOMER TYPE (GWh) (1)

Year ended December 31,
2013 2012 2011
Sales % Sales % Sales %

Regulated customers

32,140 46.3 32,679 49.6 30,226 47.9

Unregulated customers

15,178 21.9 16,745 25.4 15,590 24.7

Total contracted sales (2)

47,318 68.2 49,425 75.0 45,816 72.6

Electricity pool market sales

22,051 31.8 16,488 25.0 17,270 27.4

Total electricity sales

69,369 100.0 65,913 100.0 63,086 100.0

(1) Excludes GasAtacama, which was included in previous reports.
(2) Includes sales to distribution companies not backed by contracts in Chile and Peru.

The specific energy consumption limit (measured in GWh) for regulated and unregulated customers is 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.

35


Table of Contents

In terms of expenses, 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 conditions, the amount of our thermal generation increases. This not only involves increasing the total cost of fuel but also the cost of transporting that 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, requiring us to purchase electricity in the pool market at 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 result in a loss. We attempt to minimize the effect of poor hydrological conditions on our operations in any year primarily by limiting contractual sales requirements to an amount that does not exceed the estimated production in a “dry year”. In determining estimated production in a dry year, we take into account the available statistical information concerning rainfall and water flows, and the capacity of key reservoirs. In addition to limiting contracted sales, we may adopt other strategies such as 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.

Operations in Chile

We own and operate a total of 105 generation units in Chile directly and through our subsidiaries Pehuenche, and Celta. Of these generation facilities, 38 are hydroelectric, with a total installed capacity of 3,465 MW. This represents 62.2% of our total installed capacity in Chile. There are 16 thermal units that operate with gas, coal or oil with a total installed capacity of 2,028 MW, representing 36.4% of our total installed capacity in Chile. There are 51 wind power units with 78 MW in the aggregate, representing 1.4% of our total installed capacity in Chile. All of our generation units are connected to the country’s Central Interconnected Electricity Systems (Sistema Interconectado Central) (“SIC”), except for two Celta thermoelectric units which are connected to the Sistema Interconectado del Norte Grande (“SING”) in the north.

For information on the installed generation capacity for each of the Company’s Chilean subsidiaries, see “Item 4. Information on the Company — D. Property, Plant and Equipment”.

Our total electricity generation in Chile (including the SIC and the SING) accounted for 29.4% of total gross electricity production in Chile during 2013.

The following table sets forth the electricity generation for each of our Chilean generation subsidiaries:

ELECTRICITY GENERATION BY SUBSIDIARY IN CHILE (GWh) (1)

Year ended December 31,
2013 2012 2011

Endesa

11,967 11,723 11,076

Pehuenche

2,565 2,615 2,975

Pangue (2)

— 325 1,713

San Isidro (2)

2,546 3,529 2,460

Celta (2)

1,564 798 899

Endesa Eco (2)

796 204 173

Total

19,438 19,194 19,296

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(2) The electricity generation difference from 2011 to 2012 was primarily due to the incorporation of Pangue’s electricity generation into San Isidro’s from May 1, 2012 following the merger of the two entities. The electricity generation difference from 2012 to 2013 was primarily due to the incorporation of San Isidro’s electricity generation into Endesa Eco from September 1, 2013 following the merger of the two entities, and the further consolidation into Endesa Eco following its merger with Celta on November 1, 2013.

36


Table of Contents

The potential energy in Chilean reservoirs reached 2,870 GWh in 2013, an increase of 480 GWh, or 20%, compared to 2,391 GWh in 2012 and 3,844GWh in 2011.

Generation by type in Chile is shown in the following table:

ELECTRICITY GENERATION BY TYPE IN CHILE (GWh) (1)

Year ended December 31,
2013 2012 2011
Generation % Generation % Generation %

Hydroelectric generation

9,617 49.5 10,578 56.5 11,403 59.1

Thermal generation (2)

9,404 48.4 8,188 42.7 7,497 38.9

Wind generation – NCRE (3)

145 0.7 153 0.8 132 0.7

Mini-hydro generation – NCRE (4)

272 1.4 275 1.4 264 1.4

Total generation

19,438 100.0 19,194 100.0 19,296 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(2) Excludes GasAtacama, which was included in previous reports.
(3) Refers to the generation of the Canela and Canela II wind farms.
(4) Refers to the generation of Palmucho and the Ojos de Agua mini-hydroelectric plants.

Our thermal electric generation facilities use natural gas, LNG, coal or oil as fuel. In order to satisfy our natural gas and transportation requirements, we enter into long-term gas contracts with suppliers who establish maximum supply amounts and prices and long-term gas transportation agreements with the pipeline companies. We currently use Gas Andes (which is not related to us) and Electrogas (an Endesa Chile related company) as our suppliers. Since March 2008, all of our natural gas units can operate using natural gas or diesel, and since December 2009, San Isidro, San Isidro 2 and Quintero can operate using LNG.

In July 2013, Endesa Chile and British Gas successfully ended a renegotiation of its LNG sale and purchase agreement. This renegotiation modified some conditions of the original contract, allowing Endesa Chile to secure its long term LNG supply at competitive prices, with significant flexibility and new capacity sufficient for its current power plants and future projects.

Endesa Chile also exercised a priority option to purchase capacity as part of an expansion at the Quintero LNG Terminal. This will allow us to increase our regasification capacity from 3.2 million cubic meters per day to 5.4 million cubic meters per day, starting late 2014. This expansion will allow our Quintero facility to bring additional thermal electricity generation online, expand our gas commercialization business and develop new power plants. Because Chile has experienced prolonged droughts, we believe LNG is becoming a strategic business for us and for Chile.

In 2013, we signed a new 1,600 kiloton coal supply agreement with Endesa Energía S.A.U., which we believe is sufficient to supply Tarapacá and Bocamina with coal through until December 2014.

Under Chilean law, power generation companies must demonstrate that certain minimum amounts of their energy sales come from non-conventional renewable sources, known as NCRE. Currently our Canela wind farm, Ojos de Agua mini-hydroelectric plant and 40% of the installed capacity of our Palmucho mini-hydroelectric plant qualify as NCRE facilities. We fully complied with this obligation during 2013. The additional cost of generating electricity using NCRE facilities is being charged as a pass-through in our new contracts, which mitigates the impact to our operating income.

37


Table of Contents

Electricity sales industry-wide in Chile increased 3.5% during 2013, with sales in the SIC increasing by 3.3% and in the SING by 3.8%, as detailed in the following table:

ELECTRICITY SALES PER SYSTEM IN CHILE (GWh) (1)

Year ended December 31,
2013 2012 2011

Electricity sales in the SIC

47,831 46,282 43,805

Electricity sales in the SING

15,399 14,831 14,263

Total electricity sales

63,230 61,113 58,068

(1) Figures may differ from those previously reported as a result of their update in the CDEC-SIC and CDEC-SING yearly reports.

Our electricity sales in Chile reached 20,406 GWh in 2013 and 20,878 GWh in 2012, which represented a 32.3% and 34.2% market share, respectively. The percentage of the energy purchases to satisfy our contractual obligations to third parties has decreased from 7.8% in 2012 to 4.7% in 2013 as a result of the increase in our generation.

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

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

Year ended December 31,
2013 2012 (2) 2011 (2)
(GWh) %
of Volume
(GWh) %
of Volume
(GWh) %
of Volume

Electricity generation (2)

19,438 95.3 19,194 91.9 19,296 95.0

Electricity purchases

968 4.7 1,684 8.1 1,019 5.0

Total (1)

20,406 100.0 20,878 100.0 20,315 100.0

(1) Excludes GasAtacama, which was included in previous reports.
(2) Figures may differ from those previously reported, as the current figures are shown net of all losses.

We supply electricity to the major regulated electricity distribution companies, large unregulated industrial firms (primarily in the mining, pulp and steel sectors) and the pool market. Commercial relationships with our customers are usually governed by contracts. Supply contracts with distribution companies must be auctioned, are generally standardized and have an average term of ten years.

Supply contracts with unregulated customers (large industrial customers) are specific to the needs of each customer and the conditions are agreed between both parties, reflecting competitive market conditions.

In 2013, 2012 and 2011, Endesa Chile had 50, 49 and 47 customers, respectively. In 2013, our customers included 21 distribution companies in the SIC and 29 unregulated customers.

38


Table of Contents

The following table sets forth information regarding our sales of electricity in Chile by type of customer:

ELECTRICITY SALES PER CUSTOMER SEGMENT IN CHILE (GWh) (1)

Year ended December 31,
2013 2012 2011
Sales % of
Sales
Volume
Sales % of
Sales
Volume
Sales % of
Sales
Volume

Regulated customers

14,796 72.5 13,971 66.9 12,700 62.5

Unregulated customers

4,185 20.5 5,996 28.7 5,798 28.5

Total contract sales

18,981 93.0 19,967 95.6 18,498 91.1

Electricity pool market sales

1,425 7.0 911 4.4 1,817 8.9

Total electricity sales

20,406 100.0 20,878 100.0 20,315 100.0

(1) Excludes GasAtacama, which was included in previous reports.

Our most significant supply contracts with regulated customers are with Chilectra S.A. (Chilectra, subsidiary of Enersis) and with Compañía General de Electricidad S.A. (“CGE”), which is not related to us. These are the two largest distribution companies in Chile in terms of sales.

The following table sets forth Endesa Chile’s public contracts with electricity distribution companies in the SIC for their regulated customers:

Year ended December 31,
(in GWh)

Company

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Chilectra

7,160 7,393 7,375 7,528 7,621 7,624 7,624 6,574 4,874 3,524 3,524 2,850 1,350 1,350

CGE

4,964 5,953 6,258 6,119 6,034 6,078 5,201 5,201 3,801 3,801 3,801 0 0 0

Chilquinta

1,331 1,637 1,639 1,701 1,742 1,755 1,755 1,755 1,755 1,755 1,095 350 350 0

Saesa

2,540 2,524 2,266 2,190 2,140 2,081 581 581 581 581 581 0 0 0

Total Endesa Chile

15,996 17,507 17,538 17,538 17,538 17,538 15,161 14,111 11,011 9,661 9,001 3,200 1,700 1,350

For 2013, 2012 and 2011, Endesa Chile and its Chilean subsidiaries held 46%, 46% and 45% respectively of the total publicly tendered supply regulated contracts with the distribution companies in the SIC for their regulated customers. The rest of the contracts are distributed among eight companies.

Our generation contracts with unregulated customers are generally on a long-term basis and typically range from five to fifteen years. Such contracts are usually automatically extended at the end of the applicable term, unless terminated by either party upon prior notice. Some of them include a price adjustment mechanism in the case of high marginal costs, which also reduces the hydrological risk. Contracts with unregulated customers may also include specifications regarding power sources and equipment, which may be provided at special rates, as well as provisions for technical assistance to the customer. We have not experienced any supply interruptions under our contracts. If we experience a force majeure event, as contractually defined, we are allowed to reject purchases and we are not required to supply electricity to our unregulated customers. Disputes are typically subject to binding arbitration between the parties, subject to limited exceptions.

39


Table of Contents

The following table sets forth our sales by volume to our five largest distribution and unregulated customers in Chile for each of the periods indicated:

MAIN CUSTOMERS IN CHILE (GWh) (1)

Year ended December 31,
2013 2012 2011
Sales % of
Sales
Volume
Sales % of
Sales
Volume
Sales % of
Sales
Volume

Distribution companies:

Chilectra

5,296 27.9 5,008 24.0 4,679 22.4

CGE

4,208 22.2 4,152 19.9 3,887 18.6

Chilquinta

1,588 8.4 1,407 6.7 1,332 6.4

Saesa group (2)

2,076 10.9 1,312 6.3 1,066 5.1

Emel group (3)

1,056 5.6 968 4.6 1,018 4.9

Total sales to the largest distribution companies

14,224 74.9 12,848 61.5 11,981 57.4

Unregulated customers:

Cía. Minera Collahuasi

927 4.9 894 4.3 903 4.3

Grupo CAP-CMP (4)

960 5.1 1,027 4.9 1,076 5.2

Cía. Minera Carmen de Andacollo

479 2.5 443 2.1 423 2.1

CMPC (5)

271 1.4 584 2.8 683 3.3

Codelco (6)

129 0.7 538 2.6 557 2.7

Cía. Minera Los Pelambres (7)

— — 1,165 5.6 1,155 5.5

Total sales to the largest unregulated customers

2,766 14.6 4,650 22.3 4,797 23.1

(1) Excludes GasAtacama, which was included in previous reports.
(2) The values of the Saesa group include the consumption of the distributors Saesa and Empresa Eléctrica de la Frontera S.A.
(3) The data for the Emel group include the consumption of Empresa Eléctrica de Melipilla, Colchagua y Maule (Emelectric), Empresa Eléctrica de Talca (Emetal) and Empresa Eléctrica de Atacama (Emelat), customers of Endesa Chile. The Emel group is a subsidiary of the CGE group.
(4) Consumption of Grupo CAP and Compañía Minera del Pacífico S.A. (CMP) includes the contracts with CAP Huachipato, CMP Algarrobo, CMP Hierro Atacama, CMP Los Colorados, CMP Pellets and CMP Romeral.
(5) CMPC reduced its consumption from the Laja plant
(6) The contract with Codelco ended in March 2013.
(7) The contract with Compañía Minera Los Pelambres ended in December 2012.

We compete in the SIC primarily with two generation companies, Gener and Colbún S.A. (“Colbún”). According to the CDEC-SIC in 2013, in the SIC, Gener and its subsidiaries had an installed capacity of 2,579 MW, of which 89.5% was thermoelectric, and Colbún had an installed capacity of 2,957 MW, of which 57.4% was thermoelectric. In addition to these two large competitors, there are a number of smaller entities with an aggregate installed capacity of 2,973 MW that generate electricity in the SIC.

Our primary competitors in the SING are E-CL (GDF Suez Group) and Gener, which have 2,147 MW and 1,465 MW of installed capacity, respectively. Our direct participation in the SING includes our 182 MW Tarapacá thermal plant, owned by our subsidiary Celta.

Electricity generation companies compete largely on the basis of price, technical experience and reliability. In addition, because 64.3% of our installed capacity in the SIC comes from hydroelectric power plants, we have lower marginal production costs than companies generating electricity through thermal plants. Our thermal installed capacity benefits from access to gas from the Quintero LNG terminal. During periods of extended droughts, however, we may be forced to buy more expensive electricity from thermoelectric generators at spot prices in order to satisfy our contractual obligations.

40


Table of Contents

Directly and through our subsidiaries, we are the principal generation operator in the SIC, with 38.3% of the total installed capacity and 40.5% of the electricity energy sales of this system in 2013.

In the SING, our subsidiary Celta accounted for 4.0% of the total installed capacity in 2013 and 6.6% of the electricity energy sales of this system in 2013.

Operations in Argentina

We participate in electricity generation in Argentina through subsidiaries of Endesa Chile (Endesa Costanera and El Chocón) and since April 2013, our subsidiary Dock Sud, with an aggregate of 25 power units with a total installed capacity of 4,522 MW. El Chocón owns nine hydroelectric units, with total installed capacity of 1,328 MW, Endesa Costanera owns eleven thermal units, with a total installed capacity of 2,324 MW and Dock Sud owns five thermal units with a total installed capacity of 870 MW. Our hydro and thermal generation units in Argentina represented 14.4% of the Argentine National Interconnection system ( Sistema Interconectado Nacional , the “Argentine NIS”) installed capacity in 2013.

Our Argentine subsidiaries have holdings in three additional companies, Termoeléctrica Manuel Belgrano S.A., Termoeléctrica San Martín S.A. and Central Vuelta de Obligado S.A. These companies were formed to undertake the construction of three new generation facilities for FONINVEMEM. The first two plants started operations using gas turbines in 2008, with 1,125 MW of aggregate capacity, and combined cycles as of March 2010, with an additional 572 MW. The total aggregate capacity of these units is 1,697 MW (848 MW for Manuel Belgrano and 849 MW for San Martín). We expect that the third plant will start open cycle operations in mid-2015 (with an installed capacity of 550 MW) and in combined cycle in the beginning of 2016 (with a total installed capacity of 800 MW).

Since 2002, government intervention and energy industry authority actions, including limiting the spot price of electricity by considering the variable cost of generating electricity with natural gas and without considering the hydrological conditions of rivers and reservoirs or the use of more expensive fuels, have led to the lack of investment in the electric power sector. (See “Item 4. Operation of the Company— B. Business Overview — Electricity Industry Regulatory Framework” for further detail). In addition, from 2002, the Argentine government has taken an active role in controlling the supply of fuel to the electricity generation sector.

In March 2013, the government intervened with the fuel markets through the Resolution 95/2013. CAMMESA (the electric market operator) is now responsible of the supply and commercial management of fuels for electric generation purposes.

As of December 31, 2013, Endesa Costanera’s installed capacity accounted for 7.4% of the total installed capacity in the Argentine NIS. Endesa Costanera’s second combined-cycle plant can operate with either natural gas or diesel. Our 1,138 MW steam turbine power plant also can operate with either natural gas or fuel oil.

El Chocón accounted for 4.2% of the installed capacity in the Argentine NIS as of December 31, 2013. El Chocón has a 30-year concession, ending in 2023, for two hydroelectric generation facilities with an aggregate of 1,328 MW of installed capacity. The larger of the two facilities for which El Chocón has a concession of 1,200 MW of 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 installed capacity. In November 2008, we finished construction work on the Arroyito dam, and increased the elevation of the reservoir water level, that allows releasing water at an additional 1,150 m3/sec, for a total of 3,750 m3/sec. The additional energy (69 GWh per year) was sold on the spot market until April 2009 and under the “Energy Plus” program thereafter. The Energy Plus program is the offer of new electricity capacity to supply the electricity demand growth, on top of the demand level for electricity in 2005. (For details on Energy Plus, see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Argentina”).

41


Table of Contents

We began including Dock Sud’s installed capacity as of April 1, 2013, which accounted for 2.8% of the total installed capacity in the Argentine NIS. Dock Sud was contributed to us on March 28, 2013 as part of our capital increase. Dock Sud’s combined-cycle plant is composed of three generation units with a total installed capacity of 798 MW and can use either natural gas or diesel as fuel. Dock Sud’s two gas turbine units have 72 MW of installed capacity.

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

Our total generation in Argentina reached 14,422 GWh in 2013. Our generation market share was approximately 11.1% of total electricity production in Argentina during 2013, according to CAMMESA.

Hydroelectric generation in Argentina accounted for nearly 16.1% of our total generation in 2013. This was due to the restrictions of the operation of El Chocón that were imposed by CAMMESA and the dry conditions for the Limay River andfor the Collón Curá River, which are the main tributaries of El Chocón. Due to the drought in 2013, the region received around 83% of its historic average rainfall.

Generation by type and subsidiary is shown in the following table:

ELECTRICITY GENERATION IN ARGENTINA (GWh) (1)

Year ended December 31,
2013 2012 2011
Generation % Generation % Generation %

Hydroelectric generation (El Chocón)

2,317 16.1 2,801 24.8 2,404 22.4

Thermal generation (Endesa Costanera and Dock Sud) (2)

12,105 83.9 8,406 75.2 8,308 77.6

Total generation

14,422 100.0 11,207 100.0 10,713 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(2) Since April 2013, includes Dock Sud’s thermal generation in addition to Endesa Costanera’ thermal generation.

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

ELECTRICITY GENERATION AND PURCHASES IN ARGENTINA (GWh)

Year ended December 31,
2013 2012 2011
(GWh) % (GWh) % (GWh) %

Electricity generation (2)

14,422 87.2 11,207 94.6 10,713 94.1

Electricity purchases

2,126 12.8 645 5.4 668 5.9

Total

16,549 100.0 11,852 100.0 11,381 100.0

(1) Includes Dock Sud’s electricity generation and purchases since April 2013.
(2) Figures may differ from those previously reported, as the current figures are shown net of all losses.

42


Table of Contents

The distribution of electricity sales in Argentina by customer segment and per subsidiary is shown in the following tables:

ELECTRICITY SALES PER CUSTOMER SEGMENT IN ARGENTINA (GWh)

Year ended December 31,
2013(1) 2012 2011
Sales % of
Sales
Volume
Sales % of
Sales
Volume
Sales % of
Sales
Volume

Contracted sales

2,225 13.4 2,155 18.2 2,145 18.8

Non-contracted sales

14,324 86.6 9,696 81.8 9,236 81.2

Total electricity sales

16,549 100.0 11,852 100.0 11,381 100.0

(1) Includes Dock Sud’s sales since April 2013.

ELECTRICITY SALES PER SUBSIDIARY IN ARGENTINA (GWh)

Year ended December 31,
2013 2012 2011

Endesa Costanera

8,962 8,655 8,493

El Chocón

3,392 3,197 2,888

Dock Sud (1)

4,195 — —

Total

16,549 11,852 11,381

(1) Includes Dock Sud’s sales since April 2013.

In March 2013, the government intervened in the commercial market for energy, except with respect to the “Energy Plus” program through the one-time application of Resolution 95/2013. CAMMESA (the electric market operator) is now responsible for the administration of contracts with end customers, except for contracts under the “Energy Plus” program. The resolution defined a transition period in which the electricity generating companies will continue managing the contracts until their expiration date.

At the end of 2013, Endesa Costanera was serving customers under 24 contracts. Endesa Costanera has no contracts with distribution companies.

The following table sets forth Endesa Costanera’s sales to its largest unregulated customers for each of the periods indicated:

ENDESA COSTANERA’S MAIN CUSTOMERS (GWh)

Year ended December 31,
2013 2012 2011
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales

Cencosud (Cemsa) (1)

42 7.2 78 9.2 73 9.9

Transclor (Cemsa) (1)

41 7.0 67 8.0 61 8.3

Peugeot (Cemsa) (1)

24 4.1 42 5.0 31 4.2

Hipermercado Libertad

40 6.9 23 2.7 — —

Rasic Hnos.

25 4.2 41 4.8 39 5.3

YPF (Cemsa) (1)

— — 145 17.1 152 20.6

Solvay

— — — — 23 3.1

Total sales to our largest unregulated customers

173 29.3 395 46.8 379 51.4

(1) These customers do not have contracts with Endesa Costanera, but are served through Cemsa, our subsidary.

Sales to the pool market amounted to 8,373 GWh in 2013.

43


Table of Contents

In January 2013, El Chocón had 17 contracts with unregulated customers. Some of these contracts expired during the year and were not renewed. As a result, El Chocón had eight unregulated customers at the end of 2013. El Chocón has two contracts under the “Energy Plus” program; however, it has no contracts with distribution companies.

The following table sets forth sales by volume to El Chocón’s largest unregulated customers for each of the periods indicated:

EL CHOCÓN’S MAIN CUSTOMERS (GWh)

Year ended December 31,
2013 2012 2011
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales

Minera Alumbrera

496 43.1 499 38.1 500 35.5

Air Liquide

152 13.2 161 12.3 161 11.4

Profertil (Cemsa) (1)

96 8.3 105 8.0 113 8.0

Praxair

55 4.8 98 7.5 91 6.4

Chevron

92 8.0 87 6.6 83 5.9

Acindar (Cemsa) (1)

82 7.1 81 6.2 80 5.7

Total sales to our largest unregulated customers

972 84.6 1,031 78.6 1,028 72.9

(1) Profertil and Acindar do not have contracts with El Chocón, but are served through Cemsa, our subsidary.

El Chocón does not have the right to terminate its operating agreement with Endesa Chile, unless Endesa Chile fails to perform its obligations under the agreement. Under the terms of the operating agreement, Endesa Chile is entitled to a fee payable in U.S. dollars based on El Chocón’s annual gross revenues, payable in monthly installments.

Beginning in April 2013, Dock Sud had 37 contracts with unregulated customers that were expiring during the year. By the end of 2013, Dock Sud had 13 contracts. Dock Sud has no contract with distribution companies.

The following table sets forth Dock Sud’s sales to its largest unregulated customers for each of the periods indicated:

DOCK SUD’S MAIN CUSTOMERS (GWh)(1)

Year ended December 31,
2013 2012 2011
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales

YPF

256 52.6 — — — —

Total Austral S.A.

28 5.7 — — — —

Transclor

21 4.2 — — — —

Cencosud

20 4.2 — — — —

Peugeot

18 3.8 — — — —

Total sales to our largest unregulated customers

343 70.5 — — — —

(1) Consumption from April 2013 to December 2013.

Sales to the pool market amounted to 3,708 GWh in 2013.

44


Table of Contents

Electricity demand throughout the Argentine NIS increased 3.2% during 2013, according to CAMMESA. Total electricity demand was 125,167 GWh in 2013, 121,237 GWh in 2012 and 116,446 GWh in 2011. Our Argentine subsidiaries compete with all the major power plants connected to the Argentine NIS. According to the installed capacity reported by CAMMESA, in the monthly report for December 2013, our major competitors in Argentina are the state controlled company Enarsa (with an installed capacity of 2,155 MW), a nuclear unit “NASA” (with an installed capacity of 1,010 MW) and the hydroelectric units Yacyretá and Salto Grande (with an aggregate installed capacity of 3,690 MW). The main private competitors are: AES Group, Sociedad Argentina de Energía S.A. (“Sadesa”), and Pampa Energía. The AES Group has eight power plants connected to the Argentine NIS with a total installed capacity of 3,224 MW (37% of which is hydroelectric). Sadesa owns a total of approximately 3,858 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 2,184 MW, competes against us with six power plants, of which 630 MW is hydroelectric and 1,554 MW is thermal.

Generation in Brazil

Endesa Brasil consolidates operations of Endesa Fortaleza and Cachoeira Dourada, two generation companies; CIEN, which transmits electricity from two transmission lines between Argentina and Brazil; CTM and TESA, subsidiaries of CIEN, which are owners of the Argentine side of the lines; Ampla, the second largest electricity distribution company in the State of Rio de Janeiro; and Coelce, which is the sole electricity distributor in the State of Ceará.

As of December 2013, we had a total installed capacity of 987 MW in Brazil. Of this amount, 665 MW corresponds to Cachoeira Dourada and 322 MW to Endesa Fortaleza.

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

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

ELECTRICITY GENERATION IN BRAZIL (GWh) (1)

Year ended December 31,
2013 2012 2011
Generation % Generation % Generation %

Hydroelectric generation (Cachoeira Dourada)

2,404 48.2 3,767 71.1 3,113 75.4

Thermal generation (Endesa Fortaleza)

2,588 51.8 1,416 28.9 1,017 24.6

Total

4,992 100.0 5,183 100.0 4,129 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.

During 2013, thermal generation represented 51.8% of total generation and hydroelectric generation represented the remaining 48.2% of our generation in Brazil. During 2013, hydrological conditions were below the historical average in the Paranaiba basin, where Cachoeira Dourada is located, with rainfall at approximately 81% of the historical average.

The portion of electricity supplied by Brazil’s own generation was 73.1% of total electricity sales, requiring 26.9% of purchases to satisfy contractual obligations to customers.

45


Table of Contents

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

ELECTRICITY GENERATION AND PURCHASES IN BRAZIL (GWh)

Year ended December 31,
2013 2012 2011
(GWh) % (GWh) % (GWh) %

Electricity generation

4,992 73.1 5,183 71.1 4,129 60.5

Electricity purchases

1,835 26.9 2,108 28.9 2,699 39.5

Total (1)

6,826 100.0 7,291 100.0 6,828 100.0

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

Cachoeira Dourada is a hydroelectric company with ten generation units with a total installed capacity of 665 MW located in southern Brazil. Cachoeira Dourada’s market share is 0.5% of the total installed capacity of the Brazilian system. It has long-term contracts (originally seven-year terms, expiring in 2015) with 34 distribution companies due to the bids carried out for regulated customers by the Contratos de Comercialização de Energia no Ambiente Regulado (“CCEAR”). The contract sales with regulated customers in 2013 were for 1,109 GWh. Additionally, during 2013, Cachoeira had medium-term contracts (originally three to five year terms, expiring in 2014 and 2015) with 27 unregulated customers with an average duration of three years and short term contracts with 27 unregulated customers. Cachoeira’s sales to unregulated customers were 2,260 GWh.

The following table sets forth certain statistical information regarding Cachoeira Dourada’s electricity sales:

CACHOEIRA DOURADA’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,
2013 2012 2011
Sales % of Sales
Volume
Sales % of Sales
Volume
Sales % of Sales
Volume

Contracted sales

3,369 94.5 3,801 87.5 3,307 83.0

Non-contracted sales

195 5.5 544 12.5 679 17.0

Total electricity sales

3,564 100.0 4,344 100.0 3,986 100.0

Endesa Fortaleza is wholly-owned by Endesa Brasil. Endesa Fortaleza owns a combined-cycle plant with three generation units which use natural gas. The plant is located 50 kilometers from the capital of the Brazilian state of Ceará, and it began commercial operations in 2003. Since January 2010, Endesa Fortaleza has received natural gas from the Pecem regasification terminal.

Endesa Fortaleza’s market share is 0.3% of the total installed capacity of the Brazilian system and 1.0% of the thermoelectric generators. Fortaleza has a long-term contract with Coelce which expires in 2023.

The following table sets forth certain statistical information regarding Endesa Fortaleza’s electricity sales:

ENDESA FORTALEZA’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,
2013 2012 2011
Sales % of Sales
Volume
Sales % of Sales
Volume
Sales % of Sales
Volume

Contracted sales

2,690 82.5 2,690 91.3 2,690 94.7

Non-contracted sales

572 17.5 257 8.7 152 5.3

Total electricity sales

3,262 100.0 2,947 100.0 2,842 100.0

46


Table of Contents

Operations in Colombia

Our generation operations in Colombia are carried out through Emgesa. We hold a 37.7% stake in Emgesa as of December 31, 2013, which we control and consolidate through Endesa Chile pursuant to a shareholder’s agreement. As of December 31, 2013, our Colombian subsidiary operated 29 generation units in Colombia, with a total installed capacity of 2,925 MW. Emgesa has 2,482 MW in hydroelectric plants and 444 MW in thermoelectric plants. Our hydroelectric and thermal generation plants in Colombia represent 20.0% of the country’s total electricity generation capacity as of December 2013, according to XM.

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

Approximately 85% of our installed capacity in Colombia is hydroelectric. As a result, our electricity generation depends on the reservoir levels and rainfall. Our generation market share in Colombia was 20.5% in 2013, 22.2% in 2012 and 20.6% in 2011, according to XM. In addition to hydrological conditions, the amount of generation depends on our commercial strategy. Companies are free to offer their electricity at prices driven by market conditions and are dispatched by a centralized operating entity to generate according to the prices offered, as opposed to being dispatched according to the operating costs, as in other countries in which we operate.

During 2013, thermal generation represented 7.6% of total generation and hydroelectric generation represented the remaining 92.4% of our generation in Colombia. During 2013, hydrological conditions were below the historical average in Colombia, with rainfall around 91% of the historical average. For Emgesa, the flows in the Guavio River Basin were 84% of average and the flows in the Magdalena River (Betania) were 89% of average while the flows in the and Bogotá River (Cadena Nueva) were 132% of average according to XM. The poor hydrological condition affected Emgesa’s generation which was lower by 6.8% compared to 2012.

Generation by type in Colombia is shown in the following table:

ELECTRICITY GENERATION IN COLOMBIA (GWh) (1)

Year ended December 31,
2013 2012 (1) 2011 (1)
Generation % Generation % Generation %

Hydroelectric generation

11,784 92.4 12,649 95.5 11,613 96.4

Thermal generation

964 7.6 602 4.5 438 3.6

Total generation

12,748 100.0 13,251 100.0 12,051 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.

During 2013, Emgesa used 465 kilotons of coal for its coal-fired plants, which were obtained from over 20 local suppliers. The local coal price has remained below the export price as high transport costs make it difficult for domestic coal to compete in the export market. This trend is expected to continue in the Colombian coal market.

During 2013, Emgesa also entered into a fuel oil supply agreement with Esapetrol, which complemented the existing oil supply contracts with Petromil and Biomax. We believe this will ensure Emgesa has access to a reliable supply of fuel oil for the Cartagena power plant.

47


Table of Contents

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

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

Year ended December 31,
2013 2012 (1) 2011 (1)
(GWh) % (GWh) % (GWh) %

Electricity generation

12,748 78.6, 13,251 80.8 12,051 79.2

Electricity purchases

3,461 21.4 3,153 19.2 3,163 20.8

Total (2)

16,209 100.0 16,404 100.0 15,215 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(2) Electricity generation plus electricity purchases differ from electricity sales because of consumption by the pumps for the Muña reservoir.

The only interconnected electricity system in Colombia is the National Interconnected System ( Sistema Interconectado Nacional , the “Colombian NIS”). Electricity demand in the Colombian NIS increased 2.6% during 2013. Total electricity consumption was: 60,890 GWh in 2013, 59,370 in 2012 and 57,150 GWh in 2011.

The generation in Colombia’s electricity market has been affected by an agreement with Ecuador to provide an interconnection between the electricity systems of Colombia and Ecuador. During 2013, Colombian electricity generators sold 662 GWh of electricity to Ecuadorian customers.

In addition, Colombia has interconnection links with Venezuela that operate under exceptional circumstances as needed by either of the two countries. In early April 2011, Colombia and Venezuela signed an agreement to supply energy to Venezuela as part of the normalization of commercial relations. The agreement also includes the import of gasoline and diesel from Venezuela. The total energy exported was 715 GWh in 2013.

The distribution of our electricity sales in Colombia by customer segment is shown in the following table:

ELECTRICITY SALES PER CUSTOMER SEGMENT IN COLOMBIA (GWh)

Year ended December 31,
2013 2012 2011
Sales % of Sales
Volume
Sales % of Sales
Volume
Sales % of Sales
Volume

Contracted sales

11,567 71.9 11,719 71.9 10,544 69.8

Non-contracted sales

4,523 28.1 4,585 28.1 4,568 30.2

Total electricity sales

16,090 100.0 16,304 100.0 15,112 100.0

During 2013, Emgesa served customers under an average of 798 contracts, serving 440 unregulated customers and 13 distribution and trading companies. Emgesa’s sales to our distribution company, Codensa, accounted for 36.7% of our total contracted sales in 2013. Electricity sales to the five largest unregulated customers represented 5.9% of total contracted sales.

48


Table of Contents

The following table sets forth our sales by volume to our largest distribution customers in Colombia for the last three years:

MAIN DISTRIBUTION AND TRADING CUSTOMERS IN COLOMBIA (GWh)

Year ended December 31,
2013 2012 2011
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales

Codensa (Enersis)

4,236 36.7 5,016 42.8 5,035 47.8

Electrificadora del Caribe (Electrocaribe)

2,262 19.6 371 3.2 360 3.4

Cía. Energética del Tolima (Enertolima)

498 4.3 — — — —

Electrificadora de Boyacá (EBSA)

320 2.8 — — — —

Empresas Públicas de Medellín (EPM)

249 2.1 806 6.9 760 7.2

Empresa de Energía de Cundinamarca (EEC) (Enersis)

241 2.1 235 2.0 266 2.5

Centrales Eléctricas del Norte de Santander (CENS)

125 1.1 573 4.9 152 1.4

Electrificadora de Santander

39 0.3 373 3.2 47 0.4

Electrificadora del Huila

80 0.7 — — — —

Electrificadora del Meta (Meta)

0 0 — — — —

Total sales to our largest distribution customers

8,050 69.7 7,375 62.9 7,118 67.4

Our most important competitors in Colombia include the following state-owned companies: Empresas Públicas de Medellín (with an installed capacity of 3,251 MW) and Isagen (with an installed capacity of 2,182 MW). We also compete with the following private sector companies in Colombia: Chivor (with an installed capacity of 1,000 MW), which is owned by Gener; Colinversiones (with an installed capacity of 1,982 MW), which includes Termoflores and Epsa; and Gecelca (with an installed capacity of 1,207 MW).

Operations in Peru

Through our subsidiaries Edegel and EEPSA (since April 2013), we operate a total of 27 generation units in Peru, with a total installed capacity of 1,842 MW. As of December 31, 2013. Edegel owns 18 hydroelectric units, with a total installed capacity of 750 MW. The company has six thermal units, which represent the remaining 790 MW of total installed capacity of Edegel. EEPSA owns three thermal units with a total installed capacity of 302 MW. During October 2013, the TG 7 unit of Santa Rosa in Peru was decommissioned. Our hydroelectric and thermal generation plants in Peru represent 23.6% of the country’s total electricity generation capacity according to the information reported in December 2013 by Osinergmin.

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

49


Table of Contents

Generation by type in Peru is shown in the following table:

ELECTRICITY GENERATION IN PERU (GWh) (1)

Year ended December 31,
2013 2012 2011
Generation % Generation % Generation %

Hydroelectric generation (Edegel)

4,474 52.7 4,428 51.7 4,528 50.4

Thermal generation (Edegel and EEPSA) (2)

4,014 47.3 4,141 48.3 4,452 49.6

Total generation

8,489 100.0 8,570 100.0 8,980 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(2) Includes EEPSA’s generation since April 1, 2013. Before April 1, 2013, the thermal generation refers only to Edegel.

In 2013, we generated 22.2% of total electricity production in Peru according to COES.

Hydroelectric generation represented 52.7% of our Peruvian generation subsidiaries total production in 2013. For Edegel, all hydrological contributions were above their historical average in 2013. In the Rimac River Basin (Huinco, Matucana, Callahuanca, Moyopampa, Huampaní) hydrological contributions were 114%; in the Tulumayo River (Yanango) hydrological contributions were 112%; and in the Tarma River (Chimay) hydrological contributions were 118% according to COES, the operator of the Peruvian system.

The portion of electricity supplied by our Peruvian generation subsidiaries’ own generation was 89.4% of total electricity sales, requiring 10.6% of purchases to satisfy contractual obligations to customers.

Edegel has long-term gas supply, transportation and distribution contracts for its Ventanilla and Santa Rosa facilities. It has also signed firm transport capacity transfer agreements with other generators, which allows them to trade firm transport capacity to operate as indicated for the COES (the electric market operator) and optimize the use of the natural gas transport system.

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

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

Year ended December 31,
2013(2) 2012(1) 2011(1)
(GWh) % (GWh) % (GWh) %

Electricity generation

8,489 89.4 8,570 89.4 8,980 95.0

Electricity purchases

1,009 10.6 1,018 10.6 469 5.0

Total

9,497 100.0 9,587 100.0 9,450 100.0

(1) Figures may differ from those previously reported, as the current figures are shown net of all losses.
(2) Includes EEPSA’s electricity generation and purchases since April 2013.

The Peruvian National Interconnected Electric System ( Sistema Eléctrico Interconectado Nacional , “SEIN”) is the only interconnected system in Peru. Electricity sales in the SEIN increased 5.9% during 2013 compared to 2012, reaching total annual sales of 35,632 GWh.

50


Table of Contents

The distribution of Edegel’s electricity sales by customer segment is shown in the following table:

EDEGEL’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,
2013 2012 2011
Sales % of Sales
Volume
Sales % of Sales
Volume
Sales % of Sales
Volume

Contracted sales (1)

7,892 88.6 9,092 94.8 8,632 91.3

Non-contracted sales

1,011 11.4 495 5.2 818 8.7

Total electricity sales

8,903 100.0 9,587 100.0 9,450 100.0

(1) Includes sales to distributors without contracts.

Edegel’s electricity sales in 2013 decreased 7.1% compared with 2012 mainly due the expiration of contracts, which is reflected in the lower contracted sales. During 2013, Edegel had nine regulated customers and 14 unregulated customers. Sales to unregulated customers represented 42.2% of Edegel’s total contracted sales in 2013.

During 2011, Luz del Sur carried out a long-term tender process for 2018-2027, with an energy requirement of approximately 2,500 GWh per year. An amount of 2,245 GWh was granted to Cerro del Águila, Celepsa, Egesur, Enersur and Fenix. The remaining unallocated amount of 255 GWh was declared void.

During 2012, Edelnor carried out a long-term tender process for 2016-2027, with an energy requirement of approximately 990 GWh per year. The contracts were granted to EEPSA (12.5%), Egejunin (1.8%), Edegel (42.3%), Fenix (24.9%) and Kallpa (18.5%).

In 2013, there were no long-term tenders in Peru.

51


Table of Contents

The following table sets forth our sales by volume to our largest customers of Edegel for each of the periods indicated:

EDEGEL’S MAIN CUSTOMERS (GWh)

Year ended December 31,
2013 2012 2011
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales

Distribution companies:

Edelnor
(Regulated) (1) (2)

2,455 31.1 3,130 34.4 4,173 48.3

Luz del Sur

(Regulated) (1)

1.250 15.8 1,917 21.1 1,539 17.8

ElectroSur (3)

367 4.7 362 4.0 — —

Seal

237 3.0 — — 99 1.1

Hidrandina (3)

92 1.2 573 6.3 — —

Total sales to our largest distribution companies

4,401 55.8 5,981 65.8 5,811 67.2

Unregulated customers:

Refinería Cajamarquilla

1,341 17.0 1,332 14.6 1,320 15.3

Antamina

912 11.6 889 9.8 708 8.2

SN Power

349 4.4 — — — —

Siderúrgica del Peru

322 4.1 3.9 3.4 288 3.3

Creditex

83 1.0 72 0.8 78 0.9

Total sales to our largest unregulated companies

3,006 38.1 2,601 28.6 2,394 27.7

Total sales to our largest customers

7,407 93.9 8,583 94.4 8,205 94.9

(1) The figures for Edelnor and Luz del Sur represent sales under bilateral contracts with Edegel only, and not withdrawals of these companies assigned to Edegel for non contract-related consumption. The energy sold to these distributors includes the amount granted to Edegel in the bids realized since 2006.
(2) Edelnor reduced its consumption in 2013 compared to 2012 due to the reduction in the dispatch of two contracts.
(3) Hidrandina and ElectroSur have been customers since 2012. Edegel entered into bilateral contracts with each customer at the bar price between January 2012 and December 2012 and between January 2012 and December 2013, respectively.

EEPSA has five long term “wet” gas sale and purchase agreements, under which EEPSA purchases “wet” gas which is used for electric generation purposes at its Malacas Power Plant and sells “dry” gas to Talara refinery (owned by Petroperu, the Peruvian NOC) through a supply agreement. To satisfy those needs of “dry” gas, EEPSA has an agreement with Pariñas Processing Plant, which allows EEPSA to convert wet gas into dry gas and also recover natural gas liquids, which are shared with Pariñas Processing Plant.

EEPSA’s electricity sales between April and December 2013, where all contracted. EEPSA had contracts with three regulated customers and three unregulated customers. Sales to unregulated customers represented 93.5% of EEPSA’s total contracted sales.

52


Table of Contents

EEPSA’s ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,
2013(1) 2012 2011
Sales % of Sales
Volume
Sales % of Sales
Volume
Sales % of Sales
Volume

Contracted sales (2)

594 100 — — — —

Non-contracted sales

— — — — — —

Total electricity sales

594 100.0 — — — —

(1) From April to December 2013.
(2) Includes sales to distributors without contracts.

The following table sets forth EEPSA’s largest customers:

EEPSA’S MAIN CUSTOMERS (GWh)

Year ended December 31,
2013(1) 2012 2011
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales
Contracted
Sales
% of
Contracted
Sales

Distribution companies:

Luz del Sur

436 73.4 — — — —

Edelnor

113 19.0 — — — —

Total sales to our largest distribution companies

548 92.3 — — — —

(1) From April to December 2013

Our most important competitors in Peru are Enersur (GDF-Suez group, with an installed capacity of 1,264 MW); Electroperú (a state-owned competitor, with an installed capacity of 902 MW); Kallpa (Inkia Energy group, with an installed capacity of 861 MW); and Egenor (Duke Energy group, with an installed capacity of 622 MW).

Electricity Transmission Business Segment

CIEN

CIEN is wholly-owned by Endesa Brasil, and we hold an 83.5% economic interest in CIEN. CIEN consolidates CTM and TESA, which operate the Argentine side of the interconnection line between Argentina and Brazil. In 2013, CIEN represented 1.1% of our operating revenues and 1.9% of our operating income, both before consolidation adjustments. Since April 2011, CIEN has been recognized by the local authority as a “regulatory asset” and therefore is a participant in the basic Brazilian grid. Therefore, it is entitled to receive fixed payments called Permitted Annual Compensation (RAP).

CIEN allows for the energy integration of Mercosur and the import and export of electricity between Argentina, Uruguay and Brazil. It has two transmission lines covering a distance of 500 kilometers between Rincón in Argentina and the Santa Catarina substation in Brazil, and 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 respectively. Its subsidaries, CTM and TESA, have concessions for 87 and 85 years, respectively, and both expire in 2087.

53


Table of Contents

Electricity Distribution Business Segment

Our electricity distribution business is conducted in Chile through Chilectra, in Argentina through Edesur, in Brazil through Ampla and Coelce, in Colombia through Codensa, and in Peru through Edelnor. For the year ended December 31, 2013 electricity sales increased by 4% compared to 2012 , totaling 75,443 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”. Currently, Chilectra is the technical operator of Edesur, Edelnor, Ampla and Coelce, but does not receive operator fees.

Until December 31, 2012, jointly controlled companies were consolidated using the proportionate consolidation method. Commencing January 1, 2013, we began recording these jointly controlled companies using the equity method, as required by IFRS 11, Joint Arrangements. In the distribution business, the application of IFRS 11 requires the retrospective exclusion of EEC from our 2012 and 2011 consolidated financial statements. As a result, the data presented in this Report excludes the proportional data for EEC that was previously reported.

Chilectra

Chilectra is one of the largest electricity distribution companies in Chile in terms of the number of the regulated customers, distribution assets and energy sales. Our economic interest in Chilectra is 99.1%. Chilectra operates in a concession area of 2,118 square kilometers, under an indefinite concession granted by the Chilean government. Chilectra transmits and distributes electricity in 33 municipalities of the Santiago metropolitan region. Its service area is defined primarily as a high density area under the Chilean tariff regulations governing electricity distribution companies and includes all residential, commercial, industrial, governmental, and toll customers. The Santiago metropolitan region, which is the capital of Chile, is the country’s most densely populated area and has the highest concentration of industries, industrial parks and office facilities in the country. As of December 31, 2013, Chilectra distributed electricity to approximately 1.7 million customers. Chilectra also has direct equity stakes in foreign distribution subsidiaries controlled by us. Chilectra’s energy losses were 5.3% in 2013, compared to 5.4 % in 2012. This decrease in energy losses is due to the effectiveness of energy loss plans focused on technical inspections and loss management, among other initiatives.

For the fiscal year ended December 31, 2013, residential, commercial, industrial and other customers, who are primarily public and municipal, represented 27%, 31%, 19% and 24%, respectively, of Chilectra’s total energy sales of 15,152 GWh, which is an increase of 4.9% in comparison with 2012.

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

Year ended December 31,
2013 2012 2011

Electricity sales (GWh)

15,152 14,445 13,697

Residential

4,048 3,778 3,520

Commercial

4,639 4,212 3,683

Industrial

2,903 3,061 3,091

Other customers (1)

3,562 3,394 3,402

Number of customers (thousands)

1,694 1,659 1,638

Residential

1,516 1,489 1,471

Commercial

132 127 126

Industrial

12 12 11

Other customers

34 31 30

Energy purchased (GWh) (2)

16,002 15,264 14,488

Total energy losses (%) (3)

5.3% 5.4% 5.5%

(1) The data for other customers includes tolls.
(2) During 2013, 29.4% of electricity purchased was acquired from Endesa Chile, 33% in 2012, and 37% in 2011.
(3) Electricity losses are calculated as the percent difference between electricity purchased and electricity sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical failures.

As of December 31, 2013, Chilectra’s principal unregulated customers are (ordered alphabetically): Aguas Andinas S.A., Cencosud, CGE Distribución S.A., El Mercurio S.A, Empresa Eléctrica de Colina Limitada (a related company), Esco Elecmetal, Etp Metro S.A., Gerdau Aza S.A., Goodyear Chile S.A.C.I., Linde Gas Chile S.A. (formerly Aga S.A.), Mall Plaza S.A., Nestlé Chile S.A, Praxair Chile S.A., Sca Chile S.A. (formerly Papeles Industriales S.A.), Telefónica Chile S.A. and Walmart Chile S.A.

54


Table of Contents

Chilectra’s 2013 collection rate was 99.85%, compared to 101.20% in 2012, principally due to a deterioration in the residential customer segment. Chilectra’s 2012 collection rate was over 100% due to the collection of unpaid bills from previous years.

For the supply to regulated distribution customers, Chilectra submitted bids in November 2006, July 2007 and March 2008, allocating 100% of the power requirements tendered from 2010 to 2025. Prices obtained by Chilectra as part of these tenders are consistent with the system’s long-term expansion technology and prices are indexed to the CPI and the price of coal and LNG. During 2010, Chilectra submitted bids allocating 75% of the power requirements tendered from 2014 to 2029. A bidding process was held in 2013 and Chilectra was allocated 78% of its energy requirements, allowing Chilectra to meet the expected demand of its regulated customers through 2015. In 2014, a new bidding process is expected. If Chilectra is successful in being awarded this 2014 bid, Chilectra expects to meet the demand of its regulated customers from 2016 through 2018.

On April 2, 2013, lower distribution tariffs for Chilectra were published due primarily to efficiency gains. The tariffs have decreased by 4.5%, with retroactive application from November 2012.

Edesur

Edesur is the second largest electricity distribution company in Argentina in terms of energy purchases after Edenor, an unrelated company. Our economic interest in Edesur is 71.6% . Edesur operates in a concession area of 3,309 square kilometers. Edesur distributes electricity in the south-central part of the greater Buenos Aires metropolitan area, under a 95-year concession granted by the Argentine government that will be in force until 2087. Its service area comprises the major business district of Buenos Aires and several residential areas of the southern part of Buenos Aires. As of December 31, 2013, Edesur distributed electricity to 2.4 million customers. Residential, commercial, industrial and other customers, primarily public and municipal, represented 43%, 24%, 8% and 24%, respectively, of Edesur’s total energy sales. It had energy losses of 10.8% in 2013, compared to 10.6% in 2012.

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

Year ended December 31,
2013 2012 2011

Electricity sales (GWh)

18,137 17,738 17,233

Residential

7,845 7,570 7.274

Commercial

4,432 4,540 4.437

Industrial

1,420 1,370 1.364

Other customers (1)

4,440 4,258 4.158

Number of customers (thousands)

2,444 2,389 2.389

Residential

2,140 2,086 2,088

Commercial

270 269 266

Industrial

23 23 25

Other customers

11 11 10

Energy purchased (GWh) (2)

20,334 19,842 9,255

Total energy losses (%) (3)

10.8% 10.6% 10.5%

(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 (GWh) within a given period. Losses in distribution arise from illegally tapped energy as well as technical failures.

As of December 31, 2013, Edesur’s principal unregulated customers are (ordered alphabetically): Abbott Laboratories ARG. S.A, American Express, Arcor, Cencosud S.A, Gas Lanus S.A, Jumbo Retail S.A, Metalcris S.A, Nextel Communications Arg. S.R.L, Petrobras Energía S.A, Pfizer S.R.L, Pluspetrol S.A, Praxair Arg. S.R.L, Telefónica Argentina S.A. and Walmart Arg.

55


Table of Contents

Edesur’s 2013 collection rate was 100.36%, compared to 99.32%, in 2012, principally as a result of improvements in the residential customers segment. The 2013 collection rate was more than 100% due to the collection of unpaid bills from previous years.

As result of the applications of the Resolution ENRE 347/2012, Edesur has a trust that amounts Ar$ 440 million annually.

Secretariat of Energy Resolution 250/2013 requires that Edesur desist from all legal actions against the government for not implementing Mecanismo de Monitoreo de Costos (“MMC” in its Spanish acronym) and the Integral Tariff Revision. On November 6, 2013, the Secretariat of Energy published Note 6852, which authorizes Edesur to be compensated by the MMC for debt generated as a result of the Energy Efficiency Program (“Puree” in its Spanish acronym) for the period of March through September 2013. Total compensation for the period ended September 30, 2013 amounted Ar$ 2,902 million. ENRE published Resolution 336/2012 on November 19, 2012 to impose extraordinary penalties on Edesur for the blackouts in Edesur’s concession area between October 29, 2012 and November 14, 2012 (including the blackouts in Buenos Aires on November 7, 2012 and outages caused by storms on October 29 and November 9, 2012). As part of the penalties, Edesur must provide credits to the customers affected by the blackouts. These penalties are estimated to be approximately Ar$ 51.4 million for Edesur. Due to the supply cuts that affected Buenos Aires from December 16, 2013 through January 2014, ENRE issued the Resolution ENRE 1/2014, that defines the extraordinary penalties that Edesur must pay to the affected customers during the blackout. As of December 2013, Edesur recorded Ar$ 238.8 lower income for this reason, although the final amount of penalties is under revision. For more details, please refer to “Electricity Industry Regulatory Framework — Argentina — Regulation of Distribution Companies — Incentives and penalties”, below.

Ampla

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. As of December 31, 2013, we owned a 91.6% economic interest in Ampla. Ampla is engaged mainly in the distribution of electricity to 66 municipalities of the State of Rio de Janeiro and serves 2.7 million customers in a concession area of 32,615 square kilometers, with an estimated population of 8.0 million. Ampla operates under a 30-year concession granted by the Brazilian government and it will remain in force until December 2026. As of December 31, 2013, residential, commercial, industrial and other customers represented 41%, 19%, 8% and 32%, respectively, of Ampla’s total sales of 11,049 GWh. As of December 31, 2013, Ampla’s energy losses were 19.8%, compared to 19.6% in 2012.

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

Year ended December 31,
2013 2012 2011

Electricity sales (GWh)

11,049 10,816 10,223

Residential

4,512 4,359 3,908

Commercial

2,133 2,133 1,861

Industrial

918 1,011 1,177

Other customers (1)

3,486 3,313 3,277

Number of customers (thousands)

2,801 2,712 2,644

Residential

2,536 2,451 2,385

Commercial

171 168 168

Industrial

5 5 5

Other customers

89 88 86

Energy purchased (GWh) (2)

13,770 13,458 12,725

Total energy losses (%) (3)

19.8% 19.6% 19.7%

(1) The data for other customers includes tolls.
(2) During 2013, 0.4% of the electricity purchased was acquired from Endesa Fortaleza and/or Cachoeira Dourada, 0.5% in 2012 and 0.6% in 2011.
(3) Electricity losses are calculated as the percent difference between electricity purchased and electricity sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical failures.

56


Table of Contents

Ampla’s 2013 collection rate was 99.43%, compared to 97.80% in 2012, due principally to the significant improvement in the municipal and residential segments.

As of December 31, 2013, Ampla’s main unregulated customers are (ordered alphabetically): Lafarge Brasil, Michelin, Petrobras, Peugeot, Quattor Petroquimica, Rio Polimeros S.A, Volkswagen and Votorantim. Ampla’s 2013 collection rate was 99.43%, compared to 97.80% in 2012. This is due principally to significant improvements in the municipal and residential segments.

On January 24, 2013, ANEEL’s extraordinary tariff review under Law 12,783/2013 led to a 20% tariff reduction for Ampla’s regulated customers.

On March 8, 2013, Presidential Decree 7.945/2013 authorized the pass-through of federal resources to distributors, through the CDE or an energetic development account, in order to partially offset costs of electricity generation due to the drought. During 2013, Ampla received Ch$ 82 billion. On March 7, 2014, Presidential Decree 8.203/2014, as did the previous Decree 7.945/2013, permitted the CDE to reimburse additional costs that distribution companies incurred. The decree allows the Brazilian Treasury to allocate funds to the CDE. For January 2014, Ampla received Ch$ 14.1 billion pursuant to the decree.

Under its concession, Ampla is subject to comprehensive tariff reviews every four years and yearly tariff reviews. Ampla’s last applicable annual tariff adjustment was on April 15, 2013, which applied retroactively from March 15, 2013, and led to an average increase of 12.1% as a result of a change in inflation and energy costs, in addition to the sector charges and subsidies. The last comprehensive tariff review was in 2009, and Ampla is currently undergoing a comprehensive review, which is expected to conclude on April 8, 2014, with retroactive effect to March 15, 2014.

Coelce

As of December 31, 2013, we held a 49.2% economic interest in Coelce, the sole electricity distributor in the State of Ceará in northeastern Brazil. Coelce serves over 3.5 million customers within a concession area of 148,825 square kilometers, under a 30-year concession granted by the Brazilian government, which will remain in force until May 2028. Residential, commercial, industrial and other customers represented 35%, 18%, 11% and 36%, respectively, of Coelce’s total energy sales. As of such date, Coelce’s energy losses were 12.5%, compared to 12.6% in 2012.

57


Table of Contents

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

Year ended December 31,
2013 2012 2011

Electricity sales (GWh)

10,718 9,878 8,970

Residential

3,703 3,327 3,053

Commercial

1,951 1,834 1,679

Industrial

1,169 1,188 1,278

Other customers (1)

3,895 3,527 2,960

Number of customers (thousands)

3,500 3,338 3,224

Residential

2,720 2,426 2,360

Commercial

223 169 164

Industrial

7 6 6

Other customers

550 737 694

Energy purchased (GWh)

12,246 11,300 10,183

Total energy losses (%) (2)

12.5% 12.6% 11.9%

(1) The data for other customers includes tolls. During 2013, 22.0% of the electricity purchased was acquired from Endesa Fortaleza, 24% in 2012 and 26% in 2011.
(2) Electricity losses are calculated as the percent difference between electricity purchased and electricity sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical failures.

As of December 31, 2013, Coelce’s main unregulated customers are (ordered alphabetically): Ancora, Carrefour, Companhia Brasilera Distribuição, Durametal, Gerdau, Lojas, Mecesa, Petrobras, Telemar Norte e Leste, Vicunha Textil and Votorantim.

Coelce’s 2013 collection rate was 100.74% compared to 99.48% in 2012, and was due principally to improvements in all customer segments. The 2013 collection rate was more than 100% due to the collection of unpaid bills from previous years.

Under its concession, Coelce is subject to tariff reviews every four years. Coelce’s ordinary tariff reviews should have been introduced in 2011. However, rates remained unchanged due to the uncertainty of the new methodology to be applied. With the publication of the new methodology, on April 22, 2012, Coelce received both the annual adjustment and a tariff review retroactive to April 2011. The ordinary tariff review stated that Coelce should return the additional income that was received between April 2011 and April 2012, a period in which the reviewed tariff was not applied, through a lower annual tariff adjustment in 2013 and 2014.

After the ruling of the Brazilian court, in June 2012, ANEEL was forced to accept the new tariffs, including the application of fiscal incentives granted to companies in the area of SUDENE (Superintendency of the Development of Northeast).This led to a 0.85% increase in customers’ tariffs.

On January 24, 2013, ANEEL’s extraordinary tariff review under Law 12,783/2013 led to a 20% tariff reduction for Coelce’s regulated customers.

On March 8, 2013, Presidential Decree 7.945/2013 authorized the pass-through of federal resources to distributors, through the CDE or an energetic development account, in order to partially offset costs of electricity generation due to the drought. During 2013, Coelce received an additional Ch$ 39 billion. On March 7, 2014, Presidential Decree 8.203/2014, as did the previous Decree 7.945/2013, permitted the CDE to reimburse additional costs that distribution companies. The decree allows the Brazilian Treasury to allocate funds to the CDE. For January 2014, Coelce received Ch$ 4.5 billion pursuant to the decree.

Under its concession, Coelce is subject to comprehensive tariff reviews every four years and yearly tariff reviews. Coelce’s last applicable annual tariff adjustment was on April 22, 2013, and led to an average increase of 3.5% as a result of a change in inflation and energy costs, among others, which includes the returned revenues from the delayed application of the 2011 comprehensive tariff review.

58


Table of Contents

As of the date of this Report, Enersis owns 74.0% of Coelce after a voluntary tender offer in which we acquired an additional 15.1% of the shares. See “Item 4A – Recent Developments”.

Codensa

As of December 31, 2013, we held a 48.4% economic interest in Codensa. Codensa is an electricity distribution company that serves a concession area of 14,087 square kilometers in Bogotá and 103 other municipalities in the provinces of Cundinamarca, Tolima and Boyacá. More than 9.6 million people live in Codensa’s service area, where it serves approximately 2.7 million customers. According to Colombian law, since no concessions are granted, an administrative authorization is required to provide the distribution service. In the case of Codensa, the authorization is of indefinite duration.

Since 2001, Codensa only services regulated customers. The unregulated market is serviced directly by our generation company, Emgesa, with the exception of the public lighting in Bogotá. In 2013, Codensa had energy losses of 7.0%, compared to 7.3% in 2012. On September 25, 2012, CREG established the energy losses target of 9.61% that will be recognized in Codensa´s distribution tariff for the next five years.

The following table sets forth the primary indicators of Codensa for each of the periods indicated.

Year ended December 31,
2013 2012 2011

Electricity sales (GWh)

13,342 12,972 12,552

Residential

4,491 4,423 4,367

Commercial

2,152 2.114 2,045

Industrial

862 897 886

Other customers (1)

5,837 5,538 5,254

Number of customers (thousands)

2,687 2,588 2,496

Residential

2,381 2,289 2,207

Commercial

259 252 244

Industrial

44 43 41

Other customers

3 4 4

Energy purchased (GWh) (2)

14,351 13,995 13,612

Total energy losses (%) (3)

7.0% 7.3% 7.8%

(1) The data for other customers includes tolls.
(2) During 2013, 41.3% of the electricity purchased was acquired from Emgesa, 41% in 2012 and 57% in 2011.
(3) Electricity losses are calculated as the percent difference between electricity purchased and electricity sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical failures.

As of December 31, 2013, Codensa’s only unregulated customer was Alumbrado Público Distrito Capital Bogotá.

Codensa’s 2013 collection rate was 99.90% compared to 101.29% in 2012, due principally to decreases in collection in the government segment. The 2012 collection rate was more than 100% due to the collection of unpaid bills from previous years.

Codensa’s ordinary tariff review is currently in progress and it is expected to conclude during 2014.

59


Table of Contents

Edelnor

As of December 31, 2013, we owned a 75.5% economic interest in Edelnor, our Peruvian electricity distribution company. Edelnor operates in a concession area of 1,517 square kilometers under an indefinite concession granted by the Peruvian government. Edelnor has an exclusive concession to distribute electricity in the northern part of the Lima metropolitan area, some provinces of the Lima region, such as Huaral, Huaura, Barranca and Oyón, and in the adjacent province of Callao. As of December 31, 2013, Edelnor distributed electricity to approximately 1.3 million customers, an increase of 4.3% over 2012.

For the year ended December 31, 2013, Edelnor had total energy sales of 7,045 GWh, an increase of 2.7% over 2012. Edelnor had energy losses of 7.9% in 2013, a significant improvement when compared to 8.2% in 2012.

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

Year ended December 31,
2013 2012 2011

Electricity sales (GWh)

7,045 6,863 6,572

Residential

2,634 2,530 2,402

Commercial

1,582 1,501 1,419

Industrial

1,239 1,288 1,271

Other customers (1)

1,590 1,544 1,480

Number of customers (thousands)

1,255 1,203 1,144

Residential

1,185 1,136 1,077

Commercial

41 41 41

Industrial

1 1 1

Other customers

28 25 25

Energy purchased (GWh) (2)

7,653 7,475 7,155

Total energy losses (%) (3)

7.9% 8.2% 8.2%

(1) The data for other customers includes tolls.
(2) During 2013, 37% of the electricity purchased was acquired from Edegel and EEPSA, 46% in 2012, and 70% in 2011.
(3) Electricity losses are calculated as the percent difference between electricity purchased and electricity sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical failures.

As of December 31, 2013, Edelnor’s primary unregulated customers are (ordered alphabetically): Alicorp, Celima, Corp., Lindley, Filamentos Industriales, Goodyear Peru, Indeco, Lima Airport Partners, Molitalia, Peruana de Moldeados, Saga Falabella and Tecnofil.

Edelnor’s 2013 collection rate was 100.29% compared to 99.55%, principally due to improvements in the government and corporate segments. The 2013 collection rate was more than 100% due to the collection of unpaid bills from previous years.

In 2012, Edelnor had two auctions to secure short–term energy supply for the period from 2013 through 2017 and other to secure long–term energy supply from 2016 until 2027 for 160.8 MW. In all three auctions, the entire amounts tendered were awarded.

On October 16, 2013, Osinergmin set Edelnor’s distribution tariffs for the four-year period of November 2013 through October 2017. The new tariff increased by 1.2% compared to the tariff in place in October 2013, but represented a reduction of 0.7% when compared to the tariff in place in December 2012.

60