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

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

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

OR

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: 1-13240

EMPRESA NACIONAL DE ELECTRICIDAD S.A.

(Exact name of Registrant as specified in its charter)

EMPRESA NACIONAL DE ELECTRICIDAD 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)

Fernando Gardeweg, phone: (56-22) 2353-4639, fax: (56-2) 2378-4789, fgr@endesa.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

Common Stock, no par value *

New York Stock Exchange

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:

US$ 200,000,000 8.625% Notes due August 1, 2015
US$ 205,881,000 7.875% Notes due February 1, 2027
US$ 70,780,000 7.325% Notes due February 1, 2037
US$ 40,416,000 8.125% Notes due February 1, 2097

(Title of Class)

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: 8,201,754,580

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


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Endesa Chile’s 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 Endesa Chile’s economic interest in such subsidiary.
(2) Through Endesa Brasil, we carry out our participation in the Brazilian electricity business, which consolidates operations of two generation companies (Endesa Fortaleza and Cachoeira Dourada), one transmission company (CIEN), and two distribution companies (Ampla and Coelce). Endesa Brasil is a subsidiary of our parent company, Enersis.

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TABLE OF CONTENTS

Page

Glossary

4

Introduction

9

Technical Terms

10

Calculation of Economic Interest

10

Forward-Looking Statements

10

PART I

13

Item 1.

Identity of Directors, Senior Management and Advisers

13

Item 2.

Offer Statistics and Expected Timetable

13

Item 3.

Key Information

13

Item 4.

Information on the Company

26

Item 4A.

Unresolved Staff Comments

101

Item 5.

Operating and Financial Review and Prospects

101

Item 6.

Directors, Senior Management and Employees

126

Item 7.

Major Shareholders and Related Party Transactions

137

Item 8.

Financial Information

139

Item 9.

The Offer and Listing

140

Item 10.

Additional Information

143

Item 11.

Quantitative and Qualitative Disclosures About Market Risk

159

Item 12.

Description of Securities Other Than Equity Securities

163

Item 13.

Defaults, Dividend Arrearages and Delinquencies

165

Item 14.

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

165

Item 15.

Controls and Procedures

165

Item 16.

Reserved

166

Item 16A.

Audit Committee Financial Expert

166

Item 16B.

Code of Ethics

166

Item 16C.

Principal Accountant Fees and Services

167

Item 16D.

Exemptions from the Listing Standards for Audit Committees

168

Item 16E.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

168

Item 16F.

Change in Registrant’s Certifying Accountant

168

Item 16G.

Corporate Governance

168

Item 16H.

Mine Safety Disclosure

168

PART III

169

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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 our parent company, 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 our parent company, Enersis.
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 our parent company, Enersis.
Chilectra Chilectra S.A. Chilean electricity distribution company operating in the Santiago metropolitan area and owned by our parent company, Enersis.
CIEN Companhia de Interconexão Energética S.A. Brazilian transmission company, wholly-owned by Endesa Brasil, a subsidiary of our parent company, Enersis.
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 controlled by our parent company, Enersis, which operates mainly in Bogotá.
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 our parent company, Enersis.

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COES Comité de Operación Económica del Sistema Peruvian entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.
CREG Comisión de Regulación de Energía y Gas Colombian Commission for the Regulation of Energy and Gas.
CTM Compañía de Transmisión del Mercosur S.A. Argentine transmission company and a subsidiary of Endesa Brasil.
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 our parent company, Enersis.
Edesur Empresa Distribuidora Sur S.A. Argentine distribution company with a concession area in the south of the Buenos Aires greater metropolitan area and a subsidiary of our parent company, Enersis.
El Chocón Hidroeléctrica El Chocón S.A. Argentine generation company and a subsidiary of Endesa Chile, with two hydroelectric plants, El Chocón and Arroyito, both located in the Limay River.
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 our parent company, Enersis.
Endesa Chile Empresa Nacional de Electricidad S.A. Our company, a publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, with operations in Chile, Colombia, Peru and Argentina and an equity interest in Brazil. Registrant of this Report.
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 was merged with Celta in November 2013.
Endesa Fortaleza Central Geradora Termelétrica Fortaleza S.A. Brazilian generation company that operates a combined cycle plant, located in the state of Ceará. Endesa Fortaleza is wholly-owned by Endesa Brasil, a subsidiary of our parent company, Enersis.

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Endesa Latinoamérica Endesa Latinoamérica S.A.U. A subsidiary of Endesa Spain and owner of 40.3% of our parent company, 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 20.3% direct interest and 60.6% beneficial interest in our parent company, Enersis.
Enel Enel S.p.A. Italian power company, with a 92.1% controlling ownership of Endesa Spain.
Enersis Enersis S.A. Our Chilean parent company, with a 60.0% controlling stake in Endesa Chile.
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 and it is accounted under the equity method (IRFS 11).
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.
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.

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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 Supervisor 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, owner of three power stations in the Maule River basin and a subsidiary of Endesa Chile.
San Isidro Compañía Eléctrica San Isidro S.A. A former Chilean subsidiary of Endesa Chile and owner of a thermal 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.
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.
SVS Superintendencia de Valores y Seguros Chilean authority in charge of supervising public companies, securities and the insurance business.
UF Unidad de Fomento Chilean inflation-indexed, Chilean peso-denominated monetary unit.

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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.

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INTRODUCTION

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

We are a Chilean company engaged directly and through our subsidiaries and jointly-controlled entities in the electricity generation business in Chile, Argentina, Colombia and Peru. We also have unconsolidated equity investments in companies engaged primarily in the electricity generation, transmission and distribution business in Brazil. As of the date of this Report, our direct controlling entity, Enersis S.A. (“Enersis”), owns a 60.0% stake in us. Endesa, S.A. (“Endesa Spain”), a Spanish electricity generation and distribution company, beneficially owns 60.6% of Enersis. 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,” “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. 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.

As of March 31, 2014, one UF was equivalent to Ch$ 23,606.97. 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 Endesa Chile included in this Report are presented in Chilean pesos. Since January 1, 2009, Endesa Chile 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

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Hidroeléctricas de Aysén S.A., Inversiones GasAtacama Holding Ltda. 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 Endesa Chile. 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.

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.

Calculation of Economic Interest

References are made in this Report to the “economic interest” of Endesa Chile 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:

— our capital investment program;

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— 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 margin is reduced between US$ 20 million and US$ 44 million each month the facility remains shut down.

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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 Acquisition

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

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PART I

Item 1.     Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.     Offer Statistics and Expected Timetable

Not applicable.

Item 3.     Key Information

A. Selected Financial Data.

The following 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. 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 Endesa Chile. 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. 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.

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The following tables set forth the selected consolidated financial data of Endesa Chile for the periods indicated and the operating data by country:

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

3,865 2,027,432 2,320,385 2,284,265 2,435,382 2,418,919

Operating expense (3)

(2,372) (1,244,593) (1,707,969) (1,517,575) (1,544,658) (1,401,988)

Operating income

1,493 782,839 612,416 766,690 890,724 1,016,931

Financial income (expense), net

(261) (137,130) (146,995) (119,091) (119,717) (170,796)

Total gain (loss) on sale of non-current assets not held for sale

5 2,564 765 973 1,621 65

Other non-operating income

229 120,140 135,670 139,893 91,947 98,368

Net income before tax

1,465 768,413 601,856 788,465 864,575 944,568

Income tax

(391) (204,907) (182,833) (207,330) (179,964) (172,468)

Net income

1,074 563,506 419,023 581,135 684,611 772,100

Net income attributable to shareholders of Endesa Chile

675 353,927 234,335 446,874 533,556 627,053

Net income attributable to non-controlling interests

399 209,579 184,688 134,261 151,055 145,047

Net income (loss) from continuing operations per share, basic and diluted (Ch$ / US$)

0.08 43.15 28.57 54.49 65.05 76.45

Net income (loss) from continuing operations per ADS (Ch$ / US$)

2.47 1,294.50 857.13 1,634.70 1,953.00 2,293.50

Net income (loss) per Share, basic and diluted (Ch$ / US$ per share)

0.08 43.15 28.57 54.49 65.05 76.45

Net income (loss) per ADS (Ch$ / US$ per ADS)

2.47 1,294.50 857.13 1,634.70 1,953.00 2,293.50

Cash dividends per share (Ch$ / US$ per share)

0.027 14.29 27.24 32.53 17.53 25.25

Cash dividends per ADS (Ch$ / US$ per ADS)

0.82 428.57 817.28 975.90 525.90 757.50

Number of shares of common stock (millions)

8,202 8,202 8,202 8,202 8,202 8,202

Number of ADS (millions)

— 12 14 13 11 13

Consolidated balance sheet data

Total assets

12,890 6,762,125 6,453,231 6,506,747 6,034,872 6,169,353

Non-current liabilities

3,690 1,935,919 1,952,720 2,159,729 1,969,055 2,233,249

Equity attributable to owners of parent

5,055 2,651,968 2,541,242 2,558,538 2,376,487 2,069,086

Equity attributable to non-controlling interests

1,784 935,846 893,251 882,460 728,340 885,916

Total equity

6,839 3,587,814 3,434,493 3,440,998 3,104,827 2,995,002

Capital stock (4)

2,931 1,537,723 1,537,723 1,537,723 1,537,723 1,537,723

Other consolidated financial data

Capital expenditures (CAPEX) (5)

557 292,017 257,483 263,608 258,790 316,002

Depreciation, amortization and impairment losses (6)

374 196,155 195,685 179,978 179,714 240,142

(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 expense 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 7C and 26 to the Consolidated Financial Statements.

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

Operating data by country

Endesa Chile

Installed capacity in Chile (MW) (1)

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) (1) (2)

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

Generation in Argentina (GWh) (2)

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

Generation in Colombia (GWh) (2)

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

Generation in Peru (GWh) (2)

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

(1) Excludes the 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.
(2) 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.

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.

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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.

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)

Year ended December 31,

(in Ch$) (in %)

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.

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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.

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 Chile and Colombia, and as a result our financial condition and results of operations are particularly dependent on Chilean and Colombian economic performance. 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. In 2013, Colombian GDP increased by 4.0%, as it did in 2012. In 2014, Colombian GDP is forecast to grow by 4.5% according to the Central Bank of Colombia. Future adverse developments in the Chilean and Colombian 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 Chile. Chilean financial and securities markets may be adversely affected by events in other countries, which could adversely affect the value of our securities.

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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.

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 any further devaluation in 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% during the last twelve months, 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 in September 2013. Further deterioration to Argentina’s economy could adversely affect our results of operations and financial condition.

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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$ 1,894 billion.

Our debt had the following maturity timetable:

— Ch$ 354 billion in 2014;

— Ch$ 254 billion from 2015 to 2016;

— Ch$ 163 billion from 2017 to 2018; and

— Ch$ 1,123 billion thereafter.

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

— Ch$ 130 billion for Argentina;

— Ch$ 127 billion for Chile;

— Ch$ 66 billion for Colombia; and

— Ch$ 31 billion for Peru.

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$ 143 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.

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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.

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 59% 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.

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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 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.

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.

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 September 2011, the Chilean Superintendency of Electricity and Fuels ( Superintendencia de Electricidad y Combustibles ) (“SEF”) imposed Ch$ 816 million in fines on Endesa Chile and Pehuenche due to a blackout that occurred in the Santiago metropolitan region in March 2010. For further information on fines, please refer to Note 34 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

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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 and El Chocón 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.

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 Endesa Chile’s total consolidated debt was Ch$ 1,894 billion (net of currency hedging instruments). Of this amount, Ch$ 637 billion, or 34%, was denominated in U.S. dollars and Ch$ 307 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$ 894 billion in Colombian pesos;

— Ch$ 32 billion in Argentine pesos; and

— Ch$ 24 billion in Peruvian soles.

These amounts total Ch$ 950 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$ 707 billion (before consolidation adjustments) of which:

— Ch$ 313 billion, or 44%, came from Chile;

— Ch$ 274 billion, or 39%, came from Colombia;

— Ch$ 96 billion, or 14%, came from Peru; and

— Ch$ 24 billion, or 3%, came from Argentina

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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.

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, and Enersis owns 60.0% of Endesa Chile’s outstanding capital stock. 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.

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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.

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 authority. 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 during this month a new Council of Ministers was convened, and it 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.

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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. 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.

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Any such failure could interrupt our business, which could adversely affect our results of operations and financial condition.

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 except one 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.

Incorporation and Contact Information of the Company

Empresa Nacional de Electricidad S.A. is a publicly held limited liability stock corporation organized under the laws of the Republic of Chile on December 1, 1943. Since 1943, the Company has been registered in Santiago with the SVS under Registration No. 0114. The Company is legally referred to by its full name as well as by the shorter “Endesa Chile.” In Chile, it is also known as “Endesa,” a term that is avoided in this Report because of potential ambiguity when referring to Endesa, S.A., a parent company in Spain.

The Company’s contact information in Chile is:

Street Address: Santa Rosa 76, Santiago, Código Postal 8330099, Chile

Telephone:

(56-2) 2353-4639

Fax:

(56-2) 2378-4689

Web site:

www.endesa.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, directly and through our subsidiaries and affiliates, in the generation and transmission of electricity businesses in Chile, Argentina, Brazil, Colombia and Peru. In May 1992, we began our international expansion program with the following developments:

— We acquired a stake in Endesa Costanera in 1992 and later, in August 1993, we acquired a controlling equity interest in El Chocón, both in Argentina. As of December 31, 2013, our equity interest in El Chocón is 65.4% and in Endesa Costanera 75.7%.

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— We acquired Edegel in Peru in October 1995. In June 2006, Edegel and Etevensa merged, after which Endesa Chile’s equity interest in Edegel increased to 33.1%. In October 2009, we purchased an additional 29.4% of Edegel from Generalima, a Peruvian indirect subsidiary of Endesa Spain. With this transaction, we increased our economic interest in Edegel to 62.5%.

— We acquired Betania and Emgesa, both in Colombia, in December 1996 and in October 1997, respectively. In September 2007, these subsidiaries were merged into Betania, which then adopted the name of “Emgesa S.A. E.S.P.” As of December 2011, Endesa Chile’s equity interest in Emgesa was 26.9%. Due to a transfer of rights from Enersis, Endesa Chile controls and therefore consolidates Emgesa.

— We acquired Cachoeira Dourada in Brazil in September 1997, and in 1998 we and Endesa Spain invested in CIEN, which operates an international transmission line connecting Brazil and Argentina. Since October 2005, Cachoeira Dourada and CIEN have been subsidiaries of our affiliate, Endesa Brasil, which we account for based on the equity method.

Since June 2009, Enel S.p.A. has been the ultimate controller of Enersis by virtue of its 92.1% equity interest in Endesa Spain. Endesa Spain beneficially owns 60.6% of the share capital of Enersis, which in turn holds 60% of the share capital of Endesa Chile. Enel publicly trades on the Milan Stock Exchange, is headquartered in Italy and is 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.

As of December 31, 2013, we had 13,688 MW of installed capacity, with 178 generation units in the four countries in which we operate, consolidated assets of Ch$ 6,762 billion and operating revenues of Ch$ 2,027 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 Endesa Chile as a group and seeking to provide services group-wide, we aim to reduce investments at the individual subsidiary level for 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 $1,921 billion on a consolidated basis relating to investments currently in progress, maintenance of existing installed capacity 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.”

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

Chile

905,733 85,169 73,673 122,723

Abroad

1,015,116 206,848 183,810 140,885

Total

1,920,849 292,017 257,483 263,608

(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 (i) the 350 MW Bocamina II project in Chile, (ii) the 400 MW El Quimbo project in Colombia and (iii) maintenance of existing installed capacity. Bocamina II began commercial operations in October 2012, with 350 MW of installed capacity. The El Quimbo project is still under construction. In addition, in November 2013, the first of Salaco project’s hydro plants began its operation in Colombia. The project will add 144 MW of capacity to the system when completed.

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.

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, Colombia, and Peru, and an equity interest in a Brazilian company. Our core business is electricity generation. Less than 1.0% of our 2013 revenues came from non-generation activities, and we do not break down our revenues by businesses in this Report or in our consolidated financial statements.

The table below presents our revenues by country:

Year ended December 31, Change
2013 vs. 2012

Revenues

2013 2012 2011
(in millions of Ch$) (in %)

Generation (Chile) (1)

962,879 1,107,117 1,137,770 (13.0)

Other businesses and intercompany transaction adjustments (Chile)

10,261 7,503 18,699 36.8

Argentina

131,443 344,178 390,136 (61.8)

Colombia

639,504 580,125 498,544 10.2

Peru

283,806 282,124 239,841 0.6

Consolidated adjustments to foreign subsidiaries

(461) (662) (725) (30.4)

Total revenues

2,027,432 2,320,385 2,284,265 (12.6)

(1) Restated in accordance with IFRS 11

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For further information related to operating revenue and total income by business segment, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 31 to our Consolidated Financial Statements.

The operating figures presented in this Report differs from previously reported figures, 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 consolidated installed capacity as of December 31, 2013 was 13,688 MW, of which 58.6% was hydroelectric capacity, 40.8% was thermal electric and 0.6% 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.

We own and operate 178 generation units in the four countries in which we consolidate results, comprised principally of 105 generation units in Chile with an aggregate installed capacity, as of December 31, 2013, of 5,571 MW. This excludes the three units with 390 MW of capacity at GasAtacama.

Additionally, as of December 31, 2013, we had an interest in 73 generation units outside of Chile with an aggregate installed capacity of 8,118 MW compared to 8,224 MW of aggregate installed capacity as of December 31, 2012. This decrease was due to the decomissioning of Edegel’s 121 MW Santa Rosa TG 7 unit and Emgesa’s 39 MW La Tinta and La Junca plants. This decrease was partially offset by a 50 MW increase in Emgesa’s Darío Valencia 2 unit and a 4.2 MW increase in Edegel’s Matucana unit.

We accounted for 30% of Chile’s total generation capacity as of December 31, 2013, measured by the installed capacity published by CDEC-SIC. Hydroelectric installed capacity represents 62.2% of Endesa Chile’s total installed capacity in Chile, thermoelectric installed capacity represents 36.4% and wind power represents 1.4%. The CDEC manages Chile’s electricity distribution. See “Item 4. Information on the Company — B. Business Overview — Electricity Industry and Regulatory Framework.” Hydroelectric installed capacity outside Chile represents 56.2% of Endesa Chile’s total installed capacity outside Chile. Based on 2013 data, the Company’s installed generation capacity in Argentina, Colombia and Peru represents approximately 12%, 20% and 20% of total capacity in each country, respectively.

For additional detail on capacity increase of these units see “Item 4. Information on the Company — D. Property, Plant and Equipment.”

ENDESA CHILE’S CONSOLIDATED GENERATION BY TYPE (GWh) (1)

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

Hydroelectric generation

28,465 55.4 30,732 58.8 30,213 59.2

Thermal generation (2)

22,808 44.4 21,336 40.9 20,695 40.5

Other generation (3)

145 0.3 153 0.3 132 0.3

Total generation

51,417 100.0 52.222 100.0 51,040 100.0

(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 Canela and Canela II wind farms.

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Our consolidated electricity production reached 51,417 GWh in 2013, 1.5% lower than the 52,222 GWh produced in 2012, mainly due to a decrease in hydro generation in Chile and Colombia, to conditioned dispatch by CAMMESA in Argentina, and to lower thermal generation in Peru. We increased our generation in Chile from 19,194 GWh to 19,438 GWh, an increase of 1.3%. Our generation decreased by 3.8% in Colombia, 3.3% in Argentina and 2,1% in Peru. Hydroelectric generation in 2013 in the four countries in which we consolidate results from operations was 7.4% lower than in 2012 and thermal generation in 2013 was 6.9% higher than in 2012.

Our consolidated electricity energy sales for 2013 were 57,754 GWh, 1.5% lower than our consolidated electricity energy sales of 58,621 GWh in 2012 as result of less contracts in Chile, Peru and Colombia. We increased our sales in Argentina from 11,852 GWh to 12,354 GWh, an increase of 4.2%. In the other countries our sales decreased compared with 2012, mainly in Peru and Chile with decreases of 7.1% and 2.3% respectively, as set forth in the following table:

ENDESA CHILE ELECTRICITY DATA PER COUNTRY

As of and for the 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

Number of generating units (2)

20 20 20

Installed capacity (MW) (4)

3,652 3,652 3,652

Electricity generation (GWh) (5)

10,840 11,207 10,713

Energy sales (GWh)

12,354 11,852 11,381

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

Number of generating units (2)

24 25 25

Installed capacity (MW) (3)(4)

1,540 1,657 1,668

Electricity generation (GWh) (5)

8,391 8,570 8,980

Energy sales (GWh)

8,903 9,587 9,450

Total (5)

Number of generating units (2)

178 180 179

Installed capacity (MW) (4)

13,688 13,794 13,455

Electricity generation (GWh) (5)

51,417 52.222 51,040

Energy sales (GWh)

57,754 58,621 56,257

(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.”
(3) The Bocamina II TV2 generation unit in Chile has been consolidated since April 2012, and the Darío Valencia hydro plant in Colombia has been consolidated since November 2013. Unit 2 of Matucana hydro plant in Peru increased its installed capacity in June 2013. In October 2013, Edegel’s 121 MW Santa Rosa TG 7 unit in Peru and Emgesa’s 39 MW La Tinta and La Junca plants in Colombia were retired.
(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 tests performed by equipment suppliers. Data 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.

We segment our sales to customers using two different categories. First, we distinguish between regulated and unregulated customers. Regulated customers are distribution companies that mainly serve residential customers.

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Unregulated customers, on the other hand, may freely negotiate the price of electricity with generators or they may purchase electricity in the pool market at the spot price. The second criterion we use to segment our customer sales is by contracted sales and non-contracted sales. This method is useful because it provides a uniform way for us to compare our customers from country to country. The countries in which we operate have varying classifications for what constitutes a regulated customer. In contrast, contracted sales are defined uniformly throughout.

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 Endesa Chile’s consolidated sales of electricity by type of customer for each of the periods indicated:

ENDESA CHILE CONSOLIDATED ELECTRICITY SALES BY CUSTOMER TYPE (GWh) (1)

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

Regulated customers

27,786 48.1 28,863 49.2 26,377 46.9

Unregulated customers

12,392 21.5 14,070 24.0 13,441 23.9

Total contracted sales (2)

40,178 69.6 42,933 73.2 39,818 70.8

Electricity pool market sales

17,576 30.4 15,688 26.8 16,439 29.2

Total electricity sales

57,754 100.0 58,621 100.0 56,257 100.0

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

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 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.

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The following table contains information regarding our electricity generation and purchases:

CONSOLIDATED GENERATION AND PURCHASES (GWh) (1) (2)

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

Electricity generation

51,417 88.8 52.222 88.9 51,040 90.6

Electricity purchases

6,455 11.2 6,499 11.1 5,320 9.4

Total (3)

57,872 100.0 58.720 100.0 56,360 100.0

(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.
(3) Total energy generation (GWh) plus purchases differs from GWh sales due to energy losses at the pumps for the Muña reservoir in Colombia.

We have a 48.1% beneficial interest in GasAtacama Chile S.A., through which we participate in the gas transportation and thermal generation business in northern Chile. Since March 2008, we have held a 51% beneficial interest in HidroAysén, through which we participate in a hydroelectric project in the Aysén Region. We also participate in the gas transportation business in Chile through our related company, Electrogas S.A. (“Electrogas”), in which we have a 42.5% beneficial interest. Electrogas owns a pipeline in the Valparaíso Region and supplies natural gas to the power plants of San Isidro and Nehuenco. The other shareholders of Electrogas are Colbún S.A. and ENAP.

Since September 2005, our participation in the Brazilian electricity business has been carried out through our equity investment in Endesa Brasil S.A., in which we have a beneficial ownership interest of 37.1%. Endesa Brasil consolidates operations of (i) two generation companies, Central Geradora Termeléctrica Endesa Fortaleza S.A. (“Endesa Fortaleza”) and Cachoeira Dourada, (ii) CIEN, which owns two transmission lines between Argentina and Brazil, (iii) CTM and TESA, subsidiaries of CIEN which own the Argentine side of the lines and (iv) two distribution companies, Ampla Energia e Serviços S.A., (“Ampla”), which is the second largest electricity distribution company in the State of Rio de Janeiro, and Companhia Energética do Ceará S.A. (“Coelce”), which is the sole electricity distributor in the State of Ceará.

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, Central Interconnected System ( Sistema Interconectado Central ) (“SIC”), except for two Celta thermoelectric units which are connected to the Northern Interconnected System ( 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.

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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.

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 (which is not related to us) 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.

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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, 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 (“NCRE”) other than large traditional hydro plants. 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.

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

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.

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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.

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, a 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,

Company

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
(in GWh)

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 — — —

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 —

Saesa

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

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.

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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 (6) 2011 (6)
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 includes 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.

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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.

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 our subsidiaries Endesa Costanera and El Chocón, with a total of twenty power units. El Chocón owns nine hydroelectric units, with total installed capacity of 1,328 MW and Endesa Costanera owns eleven thermal units, with a total installed capacity of 2,324 MW. Our hydro and thermal generation units in Argentina represented 11.6% 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, Termoelélectrica Manuel Belgrano S.A., Termoelélectrica 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, since 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 in the fuel markets through 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 m 3 /sec, for a total of 3,750 m 3 /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”).

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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.”

Our total generation in Argentina reached 10,840 GWh in 2013. Our generation market share was approximately 8.4% of total electricity production in Argentina during 2013, according to CAMMESA.

Hydroelectric generation in Argentina accounted for nearly 21.4% of our total generation in 2013. This was due to the restrictions of the operation of our El Chocón facility that were imposed by CAMMESA and the dry conditions for the Limay River and for 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 21.4 2,801 24.8 2,404 22.4

Thermal generation (Endesa Costanera

8,523 78.6 8,406 75.2 8,308 77.6

Total generation

10,840 100.0 11,207 100.0 10,713 100.0

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

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

ELECTRICITY GENERATION AND PURCHASES IN ARGENTINA (GWh)

2013 2012(1) 2011(1)
(GWh) % (GWh) % (GWh) %

Electricity generation (1)

10,840 87.7 11,207 94.6 10,713 94.1

Electricity purchases

1,514 12.3 645 5.4 668 5.9

Total

12,354 100.0 11,852 100.0 11,381 100.0

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

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

ELECTRICITY SALES PER CUSTOMER SEGMENT IN ARGENTINA (GWh)

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

Contracted sales

1,737 14.1 2,155 18.2 2,145 18.8

Non-contracted sales

10,617 85.9 9,696 81.8 9,236 81.2

Total electricity sales

12,354 100.0 11,852 100.0 11,381 100.0

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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

Total

12,354 11,852 11,381

In March 2013, the government intervened in the commercial market for energy, except with respect to the “Energy Plus” program through the 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, which is a related company.

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

In January 2013, El Chocón had contracts with 17 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.

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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, which is a related company.

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.

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.

Operations in Colombia

Our generation operations in Colombia are carried out through Emgesa. We hold a 26.9% stake in Emgesa as of December 31, 2013, which we control and consolidate pursuant to a shareholder’s agreement with Enersis. Enersis owns an additional 21.6% of Emgesa. 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.”

Approximately 85% of our installed capacity in Colombia is hydroelectric. As a result, our electricity generation depends on the reservoir levels and rainfalls. 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

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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 a more favorable 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 2011
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.

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

ELECTRICITY GENERATION AND PURCHASES IN COLOMBIA (GWh)

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

Electricity generation (1)

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 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 generator sold 662 GWh of electricity to Ecuadorian customers.

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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 were for 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.

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 — — 416 3.9

Electrificadora del Meta (Meta)

— — — — 82 0.8

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).

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Operations in Peru

Through our subsidiary Edegel, we operate a total of 24 generation units in Peru, with a total installed capacity of 1,540 MW. As of December 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. During October 2013, the TG 7 unit of Santa Rosa in Peru was decommissioned. Our hydroelectric and thermal generation plants in Peru represent 19.7% 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.”

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

4,474 53.3 4,428 51.7 4,528 50.4

Thermal generation

3,917 46.7 4,141 48.3 4,452 49.6

Total generation

8,391 100.0 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.

In 2013, we generated 21.9% of total electricity production in Peru according to COES.

Hydroelectric generation represented 53.3% of Edegel’s total production in 2013. For Edegel, all hydrological contributions were above their historical average in 2012: 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 Edegel’s own generation was 94.2% of total electricity sales, requiring 5.8% 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.

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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 2012 2011
GWh % GWh % GWh %

Electricity generation

8,391 94.2 8,570 89.4 8,980 95.0

Electricity purchases

512 5.8 1,018 10.6 469 5.0

Total (1)

8,903 100.0 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.

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.

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

ELECTRICITY SALES PER CUSTOMER SEGMENT IN PERU (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/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/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.

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

MAIN CUSTOMERS IN PERU (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 4.1 309 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.

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).

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ELECTRICITY INDUSTRY REGULATORY FRAMEWORK

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

Argentina Brazil Chile Peru Colombia
Unregulated Market


Regulated
remuneration

scheme
Resolution 95/2013




Spot markets with costs audited by the regulator Spot market
with
auctioned
cost (Price-
offered)
Gx Regulated Seasonal Price Auction 20 years
for Thermal / 30
years for Hydro

Node Price
auction 15 years

Node Price
auction 20 years

Auction 3/5
years
Capacity

Contribution

peak demand


— Income based on contributions during peak demand Firm energy
contribution
(energy
auctions for
at least 20
years)

Tx Features Public - Open Access - Regulated Tariff –

Monopoly Regime for Transmission System Operators (“TSOs”)

Law Concession contract Administrative Concession

(indefinite)

Authorization
Operation
Zone
Dx Expansion 95 years 30 years Undefined

4 years

5 years

Tariff review

5 years

4/5 years

Cx Unregulated Agents

> 0.03 MW

> 0.5 MW

> 0.5 MW

> 0.2 MW

> 0.1 MW
Liberalized (%)

≈ 20%

≈25%

≈30%

≈45%

≈30%

Gx: Generation

Tx: Transmission Dx: Distribution Cx: Trading

Chile

Industry Overview

Industry Structure

The Chilean electricity industry is divided into three business segments: generation, transmission and distribution. These business segments are carried out by publicly-owned private sector companies. The state’s role is circumscribed to regulation, supervision and indicative investment planning through non-binding recommendations in the case of the generation and transmission businesses, with the exception of the main transmission system in which indicative planning is binding as well as part of the bidding processes for its construction.

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The following chart shows the relationships among the various participants in the Chilean market:

LOGO

The generation segment comprises a group of electricity companies that own generating plants, whose energy is transmitted and distributed to end customers. This segment is characterized by being a competitive market which operates under market-driven conditions. Generating plants sell their production to distribution companies, unregulated customers, other generation companies, and their surpluses on the spot market.

The transmission system comprises a combination of lines, substations and equipment for the transmission of electricity from the production points (generators) to the centers of consumption or distribution. Transmission in Chile is defined as lines or substations with a voltage or tension higher than 23 kV. The transmission system is open access, and transmission companies may impose rights of way over the available transmission capacity through the payment of tolls.

The distribution segment is defined for regulatory purposes as all electricity supplies to end customers at a voltage no higher than 23 kV. Distribution companies operate under a distribution public utility concession regime, with service obligations and regulated tariffs for supplying regulated customers.

Customers are classified according to their amount of demand, as follows: (i) unregulated customers with a connected capacity over 2,000 kW; (ii) regulated customers with connected capacity of no more than 500 kW; and (iii) customers that choose for either a regulated-tariff or an unregulated regime, for a minimum period of four years in each regime, available to customers whose connected capacity falls in the range of 500 kW to 2,000 kW.

The distribution companies supply regulated customers, a segment for which the price and supply conditions are the result of tender processes regulated by the CNE, and unregulated customers, with bilateral agreements between generators, whose conditions are freely negotiated and agreed.

In Chile, there are four separate interconnected electricity systems. The main systems that cover the most populated Chilean areas are the SIC, which services the central and south central part of the territory, where 92% of the Chilean population lives, and the SING, which operates in the northern part of the country, where most of the mining industry is located and where 6% of the Chilean population lives (figures based on the 2013 CDEC-SIC annual report). In addition to the SIC and the SING, there are two isolated systems in southern Chile that provide electricity to remote areas, where 2% of the population lives.

In 2013, the Chilean government sent a proposal to modify the Chilean Electricity Law (described below) to allow the state to promote the interconnection project between the SIC and the SING. In January 2014, the proposal was approved and signed into law by the Chilean President as Law 20,726. The interconnection is expected to be completed between 2018 and 2019.

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The operation of electricity generation companies in each of the two major interconnected electricity systems is coordinated by their respective dispatch centers, known as a CDEC, an independent entity that coordinates generators, transmission companies and large customers. CDEC coordinates the operation of its system with an efficiency criterion in which the lowest cost producer available is usually required to satisfy demand at any moment in time. As a result, at any specific level of demand, the appropriate supply will be provided at the lowest possible production cost available in the system. The marginal cost used is the price at which generators trade energy on an hourly basis, involving both their injections into the system and their withdrawals or purchases for supplying their customers.

Principal Regulatory Authorities

The Chilean Ministry of Energy develops and coordinates plans, policies and standards for the proper operation of the sector, approves tariffs and node prices set by the CNE, and regulates the granting of concessions to electricity generation, transmission and distribution companies.

The CNE is the technical entity in charge of defining prices, technical standards and regulatory requirements. The SEF monitors the proper operation of electricity, gas and fuel sectors in compliance with the law in terms of safety, quality, and technical standards.

The Chilean Ministry of Environment is responsible for the development and application of regulatory and policy instruments that provide for the protection of natural resources, the promotion of environmental education and the control of pollution, among other matters. It is also responsible for administering the environmental impact assessment system at the national level, coordinating the preparation of environmental standards and establishing the programs for compliance with the standards.

Chilean antitrust authorities are responsible for preventing, investigating and correcting any threats to free market competition and any anti-competitive practices by potentially monopolistic companies. These authorities include:

— Free Market Competition Tribunal (“TDLC” in its Spanish acronym). This is a special and independent jurisdictional entity, subject to the directive, correctional and economic authority of the Chilean Supreme Court, which functions to prevent, correct and sanction threats to free market competition.

— National Economic Prosecutor (“FNE” in its Spanish acronym). This is the attorney general responsible for economic matters and for investigating and prosecuting all antitrust conduct before the FNE’s resolutory commission and other tribunals.

The panel of experts acts as a tribunal in electricity matters arising from disputes between participants in the electricity market and the regulatory authority in certain tariff processes. It issues enforceable resolutions and comprises experts in industry matters, five engineers or economists and two lawyers, all of whom are elected every six years by the TDLC.

There are also other entities related to the energy sector: the Chilean Nuclear Energy Committee in charge of research, development, use and control of nuclear energy, and the Chilean Energy Efficiency Agency, in charge of promoting energy efficiency.

The Electricity Law

General

Since its inception, the Chilean electricity industry has been developed by private sector companies. Nationalization was carried out during the period 1970-73. During the 1980s, the sector was reorganized through the Chilean Electricity Law, known as DFL 1, allowing participation of private capital in the electricity sector. By the end of the 1990s, foreign companies had a majority participation in the Chilean electricity system.

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The goal of the Chilean Electricity Law is to provide incentives to maximize efficiency and to provide a simplified regulatory scheme and tariff-setting process that limits the discretionary role of the government by establishing objective criteria for setting prices. The goal is an economically efficient allocation of resources. The regulatory system is designed to provide a competitive rate of return on investment to stimulate private investment, while ensuring the availability of electricity to all who request it.

DFL 1 was published in 1982 and has had only two important changes since then. The first one took place in 2004 to encourage investments in transmission lines. The second one was in 2005 to create long-term contracts between generation and distribution companies as part of a bid process.

The present text of the law was restated in DFL No. 4 of 2006, which is supplemented with a series of regulations and standards.

Limits and Restrictions

The owners of the main transmission system must be constituted as limited liability stock corporations and cannot take part in the electricity generation or distribution businesses.

Individual participation in the Main Transmission System (“STT”) by companies operating in another electricity or unregulated customer segment cannot exceed, directly or indirectly, 8% of the total investment value of the STT. The aggregate participation of all such agents in the STT must never exceed 40% of the investment value.

According to the Chilean Electricity Law, there are no restrictions on market concentration for generation and distribution activities. However, Chilean antitrust authorities have imposed certain measures to increase the transparency within the different companies that form the Enersis group. The FNE’s resolution 667/2002 requires:

(i) board members of Enersis, Endesa Chile and Chilectra be elected from different and independent groups;

(ii) the external auditors of Enersis, Endesa Chile and Chilectra be different;

(iii) Enersis, Endesa Chile and Chilectra may not merge companies within the Enersis group which operate in electricity generation and distribution; instead, Enersis must continue to maintain both business segments separately through companies that are independent business units; and

(iv) Enersis, Endesa Chile and Chilectra must remain subject to the regulatory authority of the SVS and comply with the regulations applicable to publicly held stock corporations, even if they should lose such designation.

Additionally, in October 2012, Official Letter No. 1479 imposed additional restrictions on Endesa Chile stating that:

(i) the controlling shareholders should refrain from designating those persons who had been directors of Chilectra the prior term, as Endesa Chile directors; and

(ii) Endesa Chile’s management should refrain from designating employees in first and second level positions, that had held the same positions in Chilectra during the six months prior to their designation.

In addition, the Water Utility Services Law also sets restrictions on the overlapping of concessions in the same area, setting restrictions on the ownership of the property between sewage services concessions and utilities that are natural monopolies, such as electricity distribution, gas or home telephone networks.

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Regulation of Generation Companies

Concessions

The law permits generation activity without a concession. However, companies may apply for a concession to facilitate access to third-party properties. Third-party property owners are entitled to compensation, which may be agreed to by the parties or, if there is no agreement, it may be determined by an administrative proceeding that may be appealed in the Chilean courts.

Dispatch and Pricing

In each transmission system, the pertinent CDEC coordinates the operations of generation companies, in order to minimize the operating costs in the electricity system and monitor the quality of service provided by the generation and transmission companies. Generation companies satisfy their contractual sales requirements with dispatched electricity, whether produced by them or purchased from other generation companies in the spot market.

Sales by Generation Companies to Unregulated Customers

Sales by generation companies may be made to final unregulated customers or to other generation companies under freely negotiated contracts. To balance their contractual obligations with their dispatch, generators have to trade deficit and surplus electricity at the spot market price, which is set hourly by each CDEC, based on the lowest cost of production of the next kWh to be dispatched.

Sales to Distribution Companies and Certain Regulated Customers

Prior to 2005, sales to distribution companies for resale to regulated customers were made through contracts at regulated prices set by the CNE (node prices) in effect at the relevant locations (or nodes) on the interconnected system through which such electricity was supplied. Under Law 20,018 Ley Corta II, enacted on May 19, 2005, all new contracts between generation and distribution companies to supply electricity to regulated customers must arise from international bids. The bids must have a maximum energy price offer based on the average price paid by the unregulated customers at the time that the bid takes place, which is calculated twice a year by the CNE. If a first bid is unsuccessful, the CNE may increase this maximum price by an additional 15%. The bids are awarded on a minimum price basis. The average prices associated with these bids are transferred directly to end customers, replacing the regulated node price regime. During the term of the contracts, the energy and capacity prices are indexed according to formulas set forth in the bid documentation and linked to fuel, investment and other costs of energy generation. Under the bid system, all distribution companies have separate electricity contracts for their regulated and unregulated customers.

Due to the bankruptcy of the generating company Campanario in September 2011, certain regulated customers in the central-southern region of the country no longer had electricity contracts. In response, the Chilean government published two resolutions: RM 2288 and RM 239. Pursuant to these resolutions, all generating companies must meet demand from their customers on a pro rata basis to their injections into the system until new contracts are awarded under new tendering processes. As of the date of this Report, only 47% of this energy has been awarded to generation companies until December 2014 (of which 38% was to Endesa Chile and 9% to Gener).

As in most of the countries of the region, the Chilean electricity markets are concentrated on a few big operators. In the generation market, ranked by electricity generation market share, the major participants are as follows: Endesa Chile 29 %, Gener 28%, Colbún 16.5% and GDF Suez 14%, according to CDEC-SIC and CDEC-SING. In the distribution market, ranked by physical sales market share, the major participants are as follows: Chilectra (an Enersis subsidiary) 40%, Compañía General de Electricidad 39% Saesa Frontel 9% and Chilquinta 9%, according to Empresas Eléctricas A.G.

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Sales of Capacity to Other Generation Companies

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

A generation company may be required to purchase or sell capacity in the spot market, depending upon its contractual requirements in relation to the amount of electricity to be dispatched from such company and to its firm capacity.

Regulatory Charges

Chilean laws have not established any specific charge for the electric system. Nevertheless, if the tariff for residential customers increases by more than 5% in a six-month period, the government can establish a subsidy for low-income families. The last governmental subsidy was granted in 2009.

Promotion of Generation from Renewable Energy Sources

On April 1, 2008, Law 20,257 amended Law 19,940 of March 2004, known as the General Electric Services Law. The purpose of the amendment was to promote the use of NCRE. This law defines the different types of technologies that qualify as NCRE and establishes the obligation for generators, between 2010 and 2014, to supply at least 5% of the total energy contracted as of August 31, 2007, to be of a certain type, and to progressively increase this percentage by 0.5 percentage points annually up to a minimum of 10% as of 2024.

On October 22, 2013, Law 20,698 (known as the “20/25 Law”) supported renewable energy sources and modified the previously defined NCRE minimum requirements. This law establishes a mandatory share of renewable energy sources in 2025, calculated as a percentage of the total contracted energy of each generator. In particular, for those contracts signed between 2007 and 2013, the target is 10% in 2024, while for contracts beyond 2013, the target is 20% by 2025.

Incentives and Penalties

If a rationing decree is enacted in response to prolonged periods of electricity shortages, strict penalties may be imposed on generation companies that contravene the decree. A severe drought is not considered a force majeure event under our service agreements.

Generation companies may also be required to pay fines to the regulatory authorities, as well as to make compensatory payments to electricity customers affected by shortages of electricity. The fines are related to system blackouts due to an electricity generator’s operational problems, including failures related to the coordination duties of all system agents. If generation companies cannot satisfy their contractual commitments to deliver electricity during periods when a rationing decree is in effect and there is no energy available to purchase in the system, the generation company must compensate the customers at a rate known as the “failure cost” determined by the authority in each tariff setting. This failure cost, which is updated semiannually by the CNE, is a measurement of how many final customers would pay for one extra MWh under rationing conditions.

Regulation in Transmission

The main transmission system consists of 220 kV or higher voltage lines that are used by generators and customers. Every four years, a study is done to evaluate the existing system and to define the expansion plan. On December 31, 2010, the last study was delivered to the CNE. In November 2011, the CNE promulgated Decree 61, which defines the current value of the existing lines to be remunerated for the 2011 to 2014 period. The main transmission system is paid by generators and customers.

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According to the modifications to the General Electricity Services Law, the transportation of electricity by main transmission systems and sub-transmission systems are defined as a public service. Therefore, the transmitter has a service obligation and is responsible for the maintenance and improvement of its facilities.

On October 14, 2013, the Electricity Concessions Law was approved, which law aims to streamline the processing of electrical concessions, including, among other things, compensation, taxation and notifications.

Regulation in Subtransmission

Subtransmission systems are defined as voltage lines exceeding 23 kV. There are seven subtransmission systems defined by decree. The subtransmission systems are paid mainly by customers according to the values fixed by decree of the Ministry of Energy. Generators and unregulated customers pay only for the lines they use in each system. In April 2013, Decree 14 was promulgated, which established a tariff schedule from 2011 through 2014.

Environmental Regulation

The Chilean Constitution grants citizens the right to live in a pollution-free environment. It further provides that certain other constitutional rights may be limited in order to protect the environment. Chile has numerous laws, regulations, decrees and municipal ordinances that address environmental considerations. Among them are regulations relating to waste disposal (including the discharge of liquid industrial wastes), the establishment of industries in areas in which they may affect public health, and the protection of water for human consumption.

Environmental Law 19,300 was enacted in 1994 and implemented by several rules, such as the Environmental Impact Assessment System Rule issued in 1997 and modified in 2001. This law requires companies to conduct an environmental impact study and a declaration of any future generation or transmission projects.

In January 2010, Law 19,300 was modified by Law 20,417, which introduced changes in the environmental assessment process and in the public institutions involved, principally creating the Chilean Ministry of Environment and the Superintendency of Environment. Consequently, environmental assessment processes are coordinated by this entity and the Environmental Assessment Service.

For more information about Chile’s NCRE regulations, see “— Promotion of Generation from Renewable Energy Sources”.

In June 2011, the Ministry of Environment published Decree 13, emission standards for thermoelectric plants applicable to generation units of at least 50 MW, in the Diario Oficial , a governmental publication. The object of this regulation is to control atmospheric emissions of particulate matter (MP), nitrogen oxides (NOx), sulfur dioxide (SO2) and mercury (Hg), in order to prevent and protect the health of the population and protect the environment. Existing emission sources will have to meet emission limits as established in the regulation for MP emissions within two and a half years from the date this decree was published (December 2013) and for SO2 and NOx emissions, within four years in highly polluted areas and within five years elsewhere.

In June 2012, Law 20,600 created the Environmental Courts, special jurisdictional courts subject to the control of the Chilean Supreme Court. Their primary function is to resolve environmental disputes within their jurisdiction and look into other matters that are submitted for their attention under the law. The law created three such courts, the first of which began operating in December 2012 and the other two of which began operating in June 2013.

On December 28, 2012, the Superintendency of Environment was formally created and began to exercise its powers of enforcement and sanctions pursuant to Chilean environmental regulations.

Water Rights

Companies in Chile must pay an annual fee for unused water rights. License fees already paid may be recovered through monthly tax credits commencing on the start-up date of the project associated with the water right. The maximum license fees that may be recovered are those paid during the eight years before the start-up date.

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The Chilean constitution considers water as a national public good on which real utilization rights are defined; that is similar to holding the private property rights over water, as set forth in article 19, paragraph 24 “The rights of individuals over water, recognized or constituted in accordance with the law, grant their holders ownership over such rights.” Notwithstanding the foregoing, paragraph 24 also elaborates on the societal function of the private property so that water rights are subject to legal limitations.

Argentina

Industry Overview

Industry Structure

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

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

LOGO

The generation sector was organized on a competitive basis until March 2013, with independent generating companies selling their output in the Argentine MEM spot market, through private contracts to purchasers in the Argentine MEM contract market or to CAMMESA, which is the entity in charge of the operation of the Argentine MEM, through special transactions like contracts under Resolutions SE 220/2007 and 724/2008.

On March 26, 2013 the Secretariat for Energy published Resolution 95/2013 that set out a regulated remuneration scheme for power generation activity beginning retroactively from February 2013. The main features of the Resolution are as follows:

— It applies to generators, co-generators and self-generators except for power plants entered into operation after 2005, nuclear generation, cross-border hydro generation.

— CAMMESA, the market operator, will be the single buyer/seller for the fuel needed for plant operations. This implies that market agents will not be allowed to trade commodities.

— Free bilateral trading is suspended: large customers will have to buy electricity directly from CAMMESA (no change of supply for residential customers, they will still be served by distribution companies).

— Generators are to receive a regulated remuneration, which should cover fixed and variable costs and include an additional remuneration.

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

Distribution is regarded as a public service operating under monopoly conditions and is comprised of companies that have been granted concessions by the Argentine government. Distribution companies have the obligation to make electricity available to end customers within a specific concession area, regardless of whether the customer has a contract with the distributor or directly with a generator. Accordingly, these companies have regulated tariffs and are subject to quality service specifications. Distribution companies may obtain electricity on the Argentine MEM’s spot market, at a price called “seasonal price,” which is defined by the Argentine Secretariat of Energy as the cap for the costs of electricity bought by distributors that can be passed through to regulated customers.

There are two electricity distribution areas subject to federal concessions. The concessionaires are Edesur (one of our subsidiaries) and Edenor (which is not a related company), both of which are located in the greater Buenos Aires area. The local distribution areas are subject to concessions granted by the provincial or municipal authorities. However, all distribution companies acting on the Argentine MEM must operate under its rules.

Regulated customers are supplied by distributors at regulated tariffs.

“Large Customers” are classified into three categories: major large customers, minor large customers and private large customers. Each of these categories of customers has different requirements with respect to purchases of their energy demand. For example, major large customers are required to purchase 50% of their demand through supply contracts and the remainder in the spot market, while minor large customers and private large customers are required to purchase all of their demand through supply contracts. Large customers participate in CAMMESA by appointing two acting and two alternate directors through the Argentine Association of Electric Power for Large Customers.

There is one interconnected system, the Argentine Interconnection System (“Argentine SADI”), and smaller systems that provide electricity to specific areas. According to the Argentine National Institute of Statistics and Census (“INDEC” in its Spanish acronym), 99.2% of the energy required by the country is supplied by the Argentine SADI interconnected system and only 0.8% is supplied by isolated systems.

Principal Regulatory Authorities

The Argentine Ministry of Federal Planning, Public Investment and Services, through the Argentine Secretariat of Energy, is primarily responsible for studying and analyzing the behavior of energy markets, preparing the strategic planning with respect to electricity, hydrocarbons and other fuels, promoting policies to increase competition and improve efficiency in the assignment of resources, leading actions for applying the sector policy, orienting new operators to the general interest, respecting the rational exploitation of the resources and the preservation of the environment.

The Electricity National Regulatory Agency (“ENRE” in its Spanish acronym) carries out the measures necessary for meeting national policy objectives with respect to the generation, transmission and distribution of electricity. Its principal objectives are to protect the rights of customers, promote competitiveness in production, encourage investments that assure long-term supply; promote free access, non-discrimination and the generalized use of the transmission and distribution services; regulate transmission and distribution services to ensure fair and reasonable tariffs, and encourage private investment in production, transmission, and distribution, ensuring the competitiveness of the markets where possible. ENRE directly controls the management of Edenor and Edesur as

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distribution companies operating under a national concession. In the case of Edesur, on July 12, 2012, ENRE temporarily appointed an overseer for 45 business days, a term that was extended for successive periods of the same duration, in order to monitor and control all acts of management of the Company. ENRE resolution 243/13 increased the term from 45 to 90 business days and it may be extended further. The Vice President of ENRE was initially appointed to oversee Edesur. However, pursuant to ENRE Resolution 31/2014 passed January 30, 2014, the President of ENRE will oversee Edesur for 90 business days, which may be extended further.

The principal functions of the Administrative Company for the Wholesale Electricity Market (“CAMMESA”) are the coordination of dispatch operations, the establishment of wholesale prices and the administration of economic transactions made through the SIN. It is also responsible for executing the economic dispatch through economic considerations and rationality in the administration of energy resources, coordinating the centralized operation of the SIN to guarantee its security and quality, and managing the Argentine MEM, in order to ensure transparency through the participation of all the players involved and with respect to the respective regulations.

The principal functions of the Argentine Federal Electricity Council are the following: (i) managing specific funds for the electricity sector and (ii) advising the national executive authority and the provincial governments with respect to the electricity industry, the priorities in performing studies and works, concessions and authorizations, and prices and tariffs in the electricity sector. It also provides advice regarding modifications resulting from legislation referring to the electricity industry.

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

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

The Electricity Law

General

The Argentine electricity industry was originally developed by private companies. As a result of service problems, the government began to intervene in the sector in the 1950s and initiated a nationalization process. Law 15,336/60 was passed to organize the sector and establish the federal legal framework for the start of major transmission and generation projects. Many state companies were created within this framework in order to carry out various hydroelectric and nuclear projects.

As a result of the electricity shortage in 1989, the following laws were passed starting in 1990: Law 23,696 (“State Reform”), Law 23,697 (“Economic Emergency”) and Law 24,065 (“Electricity Framework”).

The objective of the new legislations was essentially to replace the vertically-integrated system based on a centrally-planned state monopoly with a competitive system based on the market and indicative planning.

Regulatory Developments: The Industry After the Public Emergency Law

Law 25,561, the Public Emergency Law, was enacted in 2002 to manage the economic crisis that began that year. It forced the renegotiation of public service contracts (such as electricity transmission and distribution concession contracts) and imposed the conversion of U.S. dollar denominated obligations into Argentine pesos at a pegged rate of Ar$ 1.00 per US$ 1.00. The mandatory conversion of transmission and distribution tariffs from

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U.S. dollars to Argentine pesos at this pegged rate (compared to the market exchange rate at that time of approximately Ar$ 3.00 per US$ 1.00) and the regulatory measures that cap and reduce the spot and seasonal prices hindered the pass-through of generation variable costs in the tariffs to end customers.

The Public Emergency Law also empowered the Argentine government to implement additional monetary, financial and foreign exchange measures to overcome the economic crisis in the medium term. These measures have been periodically extended. Law 26,729, which was enacted in December 2011, extended the measures until December 31, 2013 and Law 26,896, enacted in October 2013 further extended the measures until December 31, 2015.

The Argentine Secretariat of Energy introduced several regulatory measures aimed at correcting the effects of the devaluation into the Argentine MEM’s costs and prices and to reduce the price paid by the end customers.

Resolution SE 240/2003 changed the method for calculating spot prices by decoupling such prices from the marginal cost of operation. Prior to this resolution, spot prices in the Argentine MEM were typically fixed by units operating with natural gas during the warm season (from September through April) and units operating with liquid fuel/diesel in the winter (May through August). Due to restrictions on natural gas supply, winter prices were higher and affected by the price of imported fuels priced in U.S. dollars. Resolution SE 240/2003 sought to avoid price indexation pegged to the U.S. dollar and, although generation dispatch is still based on actual fuels used, the calculation of the spot price under the resolution is defined as if all dispatched generation units did not have the existing restrictions on natural gas supply. In addition, water value is not considered if its opportunity cost is higher than the cost of generating with natural gas. The resolution also set a cap on the spot price at Ar$ 120/MWh, which was valid until the adoption of Resolution 95/2013. The real variable costs of thermal units burning liquid fuels were paid by CAMMESA through the Transitory Additional Dispatch Cost ( Sobrecosto transitorio de despacho , or “STD”) plus a margin of Ar$ 2.5/MWh, according to the Resolutions SE 6,866/2009 and 6,169/2010, that came into effect in May 2010.

The government has avoided the increase in electricity tariffs to end customers and seasonal prices have been maintained substantially fixed in Argentine pesos. In contrast, gas producers have received price revisions by the authority and thereby were able to recover part of the value that they lost as a result of the 2002 devaluation.

Under this system, CAMMESA sells energy to distributors who pay seasonal prices and buys energy from generators at spot prices that recognize rising gas prices at a contractual price defined by the instructions of the Argentine Secretariat of Energy. To overcome this imbalance, the Argentine Secretariat of Energy — through Resolution SE 406/2003 — only allows payments to generators for amounts collected from the purchasers in the spot market. This resolution set a priority of payment for different services, such as capacity payment, fuel cost and energy sales margin, among others. As a result, CAMMESA accumulates debt with generators while the system gives a distorted price incentive to the market that encourages electricity consumption but discourages investments to satisfy the growth in electricity demand, including investments in transmission capacity. Additionally, electricity generators experience a reduction of estimated income from contract prices because of the reduction of the spot price.

The Argentine government has gradually reversed its decision to freeze distribution tariffs. During 2011, various resolutions authorizing the elimination of electricity and natural gas subsidies were issued. However, the subsidy elimination has been applied to only 5% of the demand. For further details, see “— Sales to Distribution Companies and Certain Regulated Customers” below.

In order to enhance the energy supply, the Argentine Secretariat of Energy created different schemes to sell “more reliable energy.” Resolution 1,281/2006 created the Energy Plus Service Program, which was designed to increase generation capacity in order to meet growth in electricity demand over the “Base Demand,” which was the demand for electricity in 2005.

Resolutions SE 220/2007 and 724/2008 gave thermal generators the opportunity to reduce some of the adverse effects of Resolution SE 406/2003 by entering into MEM Supply Commitment Contracts, (“CCAM” in its Spanish acronym). Under these resolutions, a thermal generator can perform maintenance or repowering investments to improve the availability of its units and add additional capacity to the system. After authorization, the thermal

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generator can then sign a CCAM at prices that would permit the recovery of such capital expenditures. Additionally, energy sales through a CCAM receive payment priority compared with spot energy sales under Resolution 406/2003). Generators with a CCAM can supply energy to CAMMESA for up to 36 months, renewable only for an additional period of six months.

During 2009, Resolution SE 762/2009 created the National Hydroelectric Program to promote the construction of new hydro plants. The program enables authorized generators to enter into energy supply contracts with CAMMESA for up to 15 years at prices that would allow for the recoupment of their investment.

The Argentine government has adopted several other measures to encourage new investments, including the following: auctions to expand the capacity of natural gas transportation and electricity transmission; the implementation of certain projects for the construction of power plants; the creation of fiduciary funds to finance these expansions; and the awarding of contracts with renewable energy, called the “GENREN program.” For more details, refer to “— Environmental Regulation” below. In addition, Law 26,095/2006 created specific charges that must be paid by end customers, which are used to finance new electricity and gas infrastructure projects. The Argentine government has also enacted regulations to encourage the rational and efficient use of electricity.

Since the implementation of Law 24,065 (“Electricity Framework”), the generation sector has sold the electricity it generates on the wholesale spot market and the private contract market. However, a series of resolutions have been published in recent years that have permitted the Argentine government and generators to sign contracts for the incorporation of new generation and/or maintenance of existing plants to guarantee the availability of the units, all in accordance with Resolutions 146/02, 220/07, 724/08 and 200/09.

On August 24, 2012, the Argentine government informed electricity sector companies that it would reform the Argentine MEM and end the marginalist system of the 1990s. To implement these changes, a Strategic Planning and Coordination Commission of the National Hydrocarbons Investment Plan was created. The principal change in the generation sector is the evolution of the “liberalized marginalist” model into a “Cost Plus” model in accordance with the following “Declared Principles”: (i) any income shall be applied to each company based on the sum of its equity and debt, less redundant assets, (ii) a “Reasonable Profit” would be recognized, and (iii) efficient operating costs would be recognized.

With this new regulatory model, the Argentine government will have more information and control over (i) the profitability of companies, (ii) the quality of service, and (iii) the supply of fuels through CAMMESA, which will be the sole supplier of fuels (through imports and a contract with YPF S.A., an Argentine company engaged in the exploration, distribution and sale of petroleum and its derivatives).

As mentioned above, Resolution 95/2013 attempted to implement the majority of the reforms announced in 2012 by moving from a marginalist system to a regulated system, in which an electricity generation company’s income is driven by regulated streams of revenues. Based on the new regulation, generators’ remuneration is now made up of the following items, which vary depending on the method of generation:

— Fixed costs: capacity remuneration subject to the achievement of a target availability.

— Variable costs: variable remuneration for operation and maintenance costs only, given that electricity generators do not incur fuel cost, which is managed by CAMMESA.

— Additional remuneration: part is paid in cash to the electricity generators, and the remainder is accumulated in a fund that will be used to finance investments in new generation facilities.

FONINVEMEM

Resolution SE 712/2004 created FONINVEMEM, a fund whose purpose is to increase electricity capacity/generation within the Argentine MEM. Pursuant to Resolution SE 406/2003, the Argentine Secretariat of Energy decided to pay generators for the spot prices up to the amount available in a stabilization fund, after collecting the funds from the purchasers in the spot market at seasonal prices, which were lower than spot prices for the same period. FONINVEMEM would receive the differences between spot prices and payments to sellers, according to Resolution SE 406/ 2003 from January 1, 2004 to December 31, 2006. CAMMESA was appointed to manage FONINVEMEM.

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Pursuant to Resolution SE 1,193/2005, all private generators in the Argentine MEM were called upon to participate in the construction, operation and maintenance of the electricity generation plants to be built with the funds from FONINVEMEM, consisting of two combined -cycle generation plants of approximately 825 MW each.

Due to the insufficient resources to construct the plants, Resolution SE 564/2007 required all of the Argentine MEM’s private sector generators to commit to FONINVEMEM by including the differences between spot prices and payments made pursuant to Resolution SE 406/2003 for an additional period ending December 31, 2007. These plants were completed in 2010 and are powered by natural gas or alternative fuels.

The Energy Plus Program

In September 2006, the Argentine Secretariat of Energy issued Resolution SE 1,281/2006 in an effort to respond to the continued increase in energy demand following Argentina’s economic recovery after the crisis. With this resolution the Argentine government started the Energy Plus Program. which principal objectives are to (i) create incentives to construct electricity generation plants and (ii) ensure that energy available in the market is used primarily to service residential customers and industrial and commercial customers with an energy demand is at or below 300 kW as well as those who do not have access to other viable energy alternatives.

The resolution also established the price large customers are required to pay for excess demand that are not covered by a contract under the Energy Plus Program, which is equal to the marginal cost of operations. This marginal cost is equal to the generation cost of the last generation unit dispatched to supply the incremental demand for electricity at any given time.

Agreement to Manage and Operate Projects

On November 25, 2010, the Argentine Secretariat of Energy signed an agreement with several generation companies, including Enersis’ subsidiaries, in order to: (i) increase thermoelectric unit availability, (ii) increase energy and capacity prices and (iii) develop new generation units through the contribution of outstanding debts of CAMMESA owed to the generation companies. This agreement seeks to accomplish the following: (i) continue the reform of the Argentine MEM; (ii) enable the incorporation of new generation to meet the increased demand for energy in the Argentine MEM (pursuant to this agreement, Endesa Chile’s subsidiaries, together with the SADESA Group and Duke, formed a company to develop the combined-cycle project with a capacity of approximately 800 MW at the Vuelta de Obligado thermal plant); (iii) determine a mechanism to pay the generators’ sales settlements with maturity dates to be determined (“LVFVDs” in the Spanish acronym), which represent generators’ claims for the period from January 1, 2008 to December 31, 2011; and (iv) determine the method for recognizing the total remuneration due to generators. On October 24, 2012, the contract for the turnkey supply and construction of the Vuelta de Obligado plant was entered into among General Electric Internacional Inc. and General Electric Internacional Inc., Argentina branch, and the Argentine Secretariat of Energy. The project also includes the expansion of the Río Coronda 500 kV transformer station which connects to the Argentine Interconnected System (“Argentine NIS”), the construction of four new fuel tanks, the construction of a gas pipeline to supply natural gas from the national network, and maintenance of the plant during the single and combined-cycle operation periods for a period of ten years.

Limits and Restrictions

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

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Vertical Integration Restrictions

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

Generators

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

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

Transmitters

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

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

— Transmission companies cannot buy or sell electric energy.

Distributors

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

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

Horizontal Integration Restrictions

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

Transmitters

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

Distributors

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

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

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Regulation of Generation Companies

Concessions

Hydroelectric generators with a normal generation capacity exceeding 500kW must obtain a concession to use public water sources. Concessions may be granted for a fixed or an indefinite term.

Such concession-holders have the right to: (i) take control of the private properties within the concession area (subject to general laws and local regulations) that are necessary to create reservoirs as well as underground or above ground supply-line and release channels, (ii) flood lands that are necessary to raise water levels, and (iii) request the authorities to make use of the powers conferred in article 10 of Law 15,336 in cases where it is absolutely necessary to appropriate the property of a third-party that was not part of the concession and the concession-holder has failed to reach an agreement with such third-party.

Dispatch and Pricing

CAMMESA controls the coordination of dispatch operations and the administration of the Argentine MEM’s economic transactions. All generators that are Argentine MEM agents must be connected to the Argentine NIS and are obliged to comply with the dispatch order to generate and deliver energy to the Argentine NIS.

The emergency regulations enacted after the Argentine crisis in 2001 had a significant impact on energy prices. Among the measures implemented pursuant to the emergency regulations were the specification of prices in the Argentine MEM and the requirement that all spot prices be calculated based on the price of natural gas, even in circumstances where alternative fuel such as diesel is purchased to meet demand due to the lack of supply of natural gas.

The introduction of the Resolution 95/2013, (see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework.— Argentina — Industry Overview” and — Regulatory Developments: the industry after the Public Emergency Law”), suppressed the market for energy transactions among generators, large customers and traders. This resolution defines a regulated remuneration scheme for each type of technology used in power generation.

Seasonal Prices

The emergency regulations also made significant changes to the seasonal prices charged to distributors in the Argentine MEM, including the implementation of a cap (which varies depending on the category of customer) on the cost of electricity charged by CAMMESA to distributors at a price significantly below the spot price charged by generators. These prices have not changed since November 2008.

Pursuant to Resolution SE 1,301/2011, which announced the elimination of subsidies, the Argentine MEM’s seasonal reference prices for non-subsidized electricity were published in November 2011. This resolution also provided for the (i) discontinuation of the practice of charging subsidized prices for non-residential customers based on their payment capacity and economic activity; (ii) creation of a Register of Exceptions including a list of customers exempt from the subsidy elimination, provided that they can certify their inability to bear the seasonal reference prices for non-subsidized electricity; and (iii) the identification of the National State Subsidy, requiring CAMMESA to explicitly identify the subsidies that it provides to each level of demand. Under the resolution, distributors are also required to notify residential customers that will be affected by the elimination of subsidies.

Stabilization Fund

The stabilization fund, managed by CAMMESA, was created to absorb the difference between purchases by distributors at seasonal prices and payments to generators for energy sales at the spot price. When the spot price is

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lower than the seasonal price, the stabilization fund increases and when the spot price is higher than the seasonal price, the stabilization fund decreases. The outstanding balance of this fund at any given time reflects the accumulation of differences between the seasonal price and the hourly energy price in the spot market. The stabilization fund is required to maintain a minimum balance to cover payments to generators if prices in the spot market during the quarter exceed the seasonal price.

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

Sales to Distribution Companies and Regulated Customers

In order to stabilize the prices for distribution, the market uses the seasonal price as the energy price to be paid by distributors for their purchases of electricity traded in the spot market. This is a fixed price determined every six months by the Argentine Secretariat of Energy based on CAMMESA’s recommended seasonal price level for the next period according to its estimated spot price. CAMMESA estimates this price by evaluating its expected supply, demand and available capacity, as well as other factors. The seasonal price is maintained for at least 90 days. Since 2002, the Argentine Secretariat of Energy has been approving seasonal prices lower than those recommended by CAMMESA.

At the end of 2011, the Argentine government issued various resolutions in order to being a process of reducing subsidies to gas, electricity and water tariffs. These resolutions provide for, among other things, the (i) approval of the seasonal programming of regulated tariffs for the period from November 2011 to April 2012, (ii) establishment of a new non-subsidized seasonal price, which increased from Ar$ 243/MWh to Ar$ 320/MWh, (iii) listing of economic activities that are subject to the reduction in subsidies, (iv) creation of a register recording the exceptions to the reduction in subsidies, (v) establishment of the effective date for the new tariffs as of January 1, 2012, and (vi) provisions for voluntarily renouncing gas, electricity and water subsidies through an online system.

Specific Regulatory Charges for Electricity Companies

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

Incentives and Penalties

The Energy Plus Service Program, part of the Energy Plus Program, is provided by generators that have (i) installed new generation capacity or (ii) connected previously unconnected existing generation capacity to the Argentine NIS. All “Large Customers” that had a higher demand than their Base Demand as of November 1, 2006 were required to enter into a contract with the Energy Plus Service Program to cover their excess demand. Large Customers that did not enter into such contracts are required to pay additional amounts for any consumption that exceeds the Base Demand. The prices under the contracts with Energy Plus Service Program must be approved by the relevant authorities. Unregulated customers that were unable to secure an Energy Plus Service contract are able to request CAMMESA to conduct an auction in order to satisfy their demand.

Regulation in Transmission

The transmission sector is regulated based on the principles established in Law 24,065 and the terms of the concession granted to Transener S.A. (not an affiliated company) under Decree 2,743/92. Due to technological reasons, the transmission sector is heavily affected by economies of scale that limit competition. As a result, the transmission sector operates under monopoly conditions and is subject to considerable regulation.

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Natural Gas Market

Since the emergency economic measures of 2002, the lack of investment in natural gas production forced the system to burn increasing amounts of liquid fuels.

The Argentine government has adopted different measures to improve the natural gas supply. Since 2004, local gas producers and the Argentine government have entered into various agreements to guarantee gas supply. The last agreement was signed in July 2009 and resulted in a 30% increase in the natural gas price for power generators until December 2009. In addition, Argentina and Bolivia entered into a 20-year agreement in 2006 that guarantees Argentina’s right to receive up to 28 million cubic meters of natural gas on a daily basis.

The Electronic Gas Market (“MEG” in its Spanish acronym) was also recently created to increase the transparency of physical and commercial operations in the spot market.

Electricity Exports and Imports

In order to give priority to the internal market supply, the Argentine Secretariat of Energy adopted additional measures that restricted electricity and gas exports. Resolution SE 949/2004 established measures that allowed agents to export and import electricity under very restricted conditions. These measures prevented generators from satisfying their export commitments.

The Argentine Secretariat of Energy published Disposition 27/2004, together with related resolutions and decrees, which created a plan to ration natural gas exports and the use of transport capacity. These measures restricted gas delivery to Chile and Brazil. These restrictions are expected to continue as Resolution Enargas 1,410, which was issued in October 2010, reinforced such restrictions on gas distribution to certain customers. Specifically, the resolution mandated that the distribution of gas be made in the following order, from highest to lowest priority: (i) residential and commercial customers, (ii) the compressed natural gas market, (iii) large customers, (iv) thermal generator units, and (v) exports.

Environmental Regulation

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

Certain reporting and monitoring obligations and emission standards are imposed on the electricity sector. Failure to satisfy these requirements entitles the Argentine government to impose penalties such as suspension of operations which, in case of public services, could result in the cancellation of concessions.

Law 26,190, enacted in 2007, defined the use of nonconventional renewable energy for electricity production as a national interest and set as a target 8% market share for generation from renewable energies within a term of 10 years. During 2009, the government took actions to reach this objective by publishing Resolution 712/ 2009 and launching an international auction to promote the installation of up to 1,000 MW of renewable energy capacity. This resolution created a mechanism to sell renewable energy through fifteen-year contracts with CAMMESA under special price conditions through ENARSA. In June 2010, the “GENREN program” awarded a total of 895 MW, distributed in the following manner: 754 MW of wind power, 110 MW of bio-fuels, 11 MW of mini-hydro, and 20 MW of solar units. The prices awarded vary from US$ 150/MWh (for mini-hydro units) to US$ 598/MWh (for solar units). In 2011, the Argentine Secretariat of Energy issued Resolution 108/11 which allowed CAMMESA to sign contracts directly with generators of renewable energy on conditions similar to Resolution 712/ 2009.

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Brazil

Industry Overview

Industry Structure

Brazil’s electricity industry is organized into one large interconnected electricity system, the Brazilian NIS, which comprises most of the regions of Brazil, and several other small isolated systems.

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

LOGO

Generation, transmission, distribution and trading are legally separated activities in Brazil.

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

The Brazilian Constitution was amended in 1995 to authorize foreign investment in power generation. Before, all generation concessions were held either by Brazilian individuals or entities controlled by Brazilian individuals or the Brazilian government.

The transmission sector operates under monopoly conditions. Revenues from the transmission companies are fixed by the Brazilian government. This applies to all electricity companies with transmission operations in Brazil. The transmission revenue fee is fixed and, therefore, transmission revenues do not depend on the amount of electricity transmitted.

Distribution is a public service that works under monopoly conditions and is provided by companies who have also been granted concessions. Distributors in the Brazilian NIS are not permitted to: (i) develop activities related to the generation or transmission of electricity; (ii) sell electricity to unregulated customers, except for those in their concession area and under the same conditions and tariffs maintained with respect to captive customers in the Regulated Market; (iii) hold, directly or indirectly, any interest in any other company, corporation or partnership; or (iv) develop activities that are unrelated to their respective concessions, except for those permitted by law or in the relevant concession agreement. Similarly, generators are not allowed to hold equity interests in excess of 10.0% in distributors.

The selling of electricity is governed by Law 10,848/ 2004 and Decrees 5,163/2004 and 5,177/2004 of the Electricity Trading Chamber or Clearing House (“CCEE” in its Portuguese acronym), and ANEEL Resolution 109/2004, which introduced the Electricity Trading Convention. This is a convention in which the terms, rules and procedures of the trading in the CCEE are defined. Two possible situations were introduced by these regulations for the execution of energy sales agreements: (i) the regulated contracting environment, in which energy generation and distribution agents participate, and (ii) the free market contracting environment, in which energy generation, trading, importing and exporting agents, and unregulated customers, participate.

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Commercial relations between the agents participating in the CCEE are governed mainly by energy sales agreements. All the agreements between the agents in the Brazilian NIS should be registered with the CCEE. The register includes the amounts of energy and the terms. The energy prices agreed are not registered with the CCEE, but instead are specified by the parties involved in the agreements.

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

The unregulated market includes the sale of electricity between generation concessionaires, independent producers, self-producers, sellers of electricity, importers of electricity, unregulated, and special customers. It also includes contracts in place between generators and distributors until their expiration, at which point new contracts may be entered into under the terms of the new regulatory framework. According to the specifications set forth in Law Number 9,427/96, unregulated customers in Brazil are those who currently have: (i) a demand of at least 3,000 kW , generated using any method and purchase the energy supply directly with generators or traders, but not directly from distributors or (ii) a demand in the range of 500 to 3,000 kW generated using ERNC and purchase their energy supply directly with alternative generators or traders, with the option to purchase energy from distributors as well.

The Brazilian NIS is coordinated by the Brazilian Electricity System Operator (“ONS” in its Portuguese acronym) and is divided into four electric sub-systems: South-East/Center-West, South, North-East, and North. In addition to the Brazilian NIS, there are also the isolated systems that are not part of the Brazilian NIS. These isolated systems are generally located in the Northern and North-Eastern regions of Brazil, and rely solely on electricity generated from coal-fired and oil-fueled thermal plants. According to the ONS, more than 98% of the energy required by Brazil is supplied by the Brazilian NIS and only 1.7% is supplied by isolated systems.

Principal Regulatory Authorities

The Brazilian Ministry of Mines and Energy (“Brazilian MME”) regulates the electricity industry and its primary role is to establish the policies, guidelines and regulations for the sector.

The Brazilian National Energy Policy Council (“CNPE” in its Portuguese acronym) is in charge of developing the national electricity policy. Among its roles are to guide the President in the formulation of energy policies and guidelines, promote the stable and secure supply of the country’s energy resources, ensure the energy supply to the most distant places of the country, establish directives for specific programs (such as the use of natural gas, alcohol, biomass, coal and thermonuclear energy), and establish directives for the import and export of energy.

The Energy Research Company (“EPE” in its Portuguese acronym) is an entity under the Brazilian MME. Its purpose is to provide services in the area of studies and research to support the energy sector planning.

ANEEL, the Brazilian National Agency for Electric Energy, is the entity that implements the regulatory policies, and its main responsibilities include, among others: (i) supervision of the concessions for electricity sale, generation, transmission and distribution; (ii) enactment of regulations for the electricity sector; (iii) implementation and regulation of the exploitation of electricity resources, including the use of hydroelectricity; (iv) promotion of a bidding process for new concessions; (v) resolution of administrative disputes between electricity sector agents; and (vi) setting the criteria and methodology for determining distribution and transmission tariffs, as well as the approval of all the electricity tariffs, ensuring that customers pay a fair price for energy supplied and, at the same time, preserving the economic-financial balance of the distribution companies, so that they can provide the service to agreed quality and continuity.

The Energy Sector Monitoring Committee (“CMSE” in its Portuguese acronym) is an entity created under the scope of the Brazilian MME and is under the Brazilian MME’s direct coordination. CMSE was established to

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evaluate the continuity and security of the energy supply across the country. CMSE has the mandate to: (i) follow the development of the energy generation, transmission, distribution, trading, import and export activities; (ii) assess the supply and customer service as well as the security of the system; (iii) identify difficulties and obstacles that affect the supply security and regularity; and (iv) recommend proposals for preventive actions that can help preserve the supply security and service.

CCEE is a non-profit company subject to authorization, inspection and regulation by ANEEL and its main purpose is to carry out the wholesale transactions and trading of electric power within the Brazilian NIS by registering the agreements resulting from market adjustments and whose agents are gathered into four categories: generation, distribution, trading and customers.

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

The Brazilian Institute of Environment and Renewable Natural Resources (“IBAMA” in its Portuguese acronym) is an executive body of the National Environmental Policy, which takes the form of a federal autarchy. It is part of the Ministry of Environment, with responsibility for the implementation of the National Environmental Policy and the preservation and conservation of natural heritage, exercising control and supervision over the use of natural resources (water, flora, wildlife, soil, etc.).

IBAMA is also responsible for the environmental impact studies and the granting of environmental licenses for projects nationwide. The environmental license is a procedure by which the competent environmental agency at the federal, state or municipal levels, allows the location installation, expansion, and operation of businesses and activities that require natural resources. It also can consider the effective or potential pollution, in whatever form, and any cause of environmental degradation. This license seeks to ensure that preventive and control measures taken in the draft are compatible with sustainable development.

The Electricity Law

General

Before 1993, power tariffs were the same throughout Brazil. The dealers were entitled to a guaranteed return because the regulatory regime provided for the cost of service. Concession areas that obtained a higher return than the one guaranteed deposited the surplus in a fund from which the distributors with less than the guaranteed return withdrew the difference.

In 1993, the Brazilian electric sector was reformed through Law 8,631/93, which abolished the equalization of electricity tariffs system.

The Concessions Law 8,987 and the Power Sector Law 9,074, both enacted in 1995, intended to promote competition and attract private capital into the electricity sector. Since then, several assets owned by the Brazilian government and/or state governments have been privatized.

The Power Sector Law also introduced the concept of independent power producers (“IPPs”) in order to open the electricity sector to private sector investment. IPPs are single agents, or agents acting in a consortium, who receive a concession, permit or authorization from the Brazilian government to produce electricity for sale for their own account.

Law 9,648/98 created the wholesale energy market, composed by the generation and distribution companies. Under this new law, the purchase and sale of electricity are freely negotiated.

The spot price is used to value the purchase and sale of electric power in the short term market. According to the law, the CCEE is responsible for setting electricity prices in the spot market. These prices are calculated on a marginal costs basis, modeling future operation conditions and setting a merit order curve with variable costs for thermal units and opportunity cost for hydroelectric plants, resulting in one price for each subsystem set for the week subsequent to the determination.

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Pursuant to Law 10,433/02, the wholesale energy market structure came to be closely regulated and monitored by ANEEL. ANEEL is also responsible for setting wholesale energy market governance rules including measures to stimulate permanent external investment.

During 2003 and 2004, the Brazilian government established the basis for a new model for the Brazilian electricity sector through Laws 10,847 and 10,848 of March 15, 2004, and Decree 5,163 of July 30, 2004. The principal objectives of these laws and decrees were to (i) guarantee the security of the electricity supply, (ii) promote the reasonability of tariffs, and (iii) improve social integration in the Brazilian electricity sector through programs designed to provide universal access to electricity.

The new model contemplates a series of measures to be followed by the agents, such as the obligation to contract all the demand of the distributors and unregulated customers. It also defines a new methodology for calculating the physical energy guarantee for sale of generation, contracting hydroelectric and thermal generating plants in proportions that ensure the best balance between guarantee and supply cost, plus the constant monitoring of the continuity and security of supply, seeking to detect occasional imbalances between supply and demand.

In terms of the tariffs’ reasonability, the model contemplates the purchase of electricity by distributors in a regulated environment through tenders in which the principle of lowest tariff is observed. As a result, the cost of acquiring electricity to be passed on to captive customers can be reduced. The new model creates conditions for the benefits of electricity made available to customers who do not yet have this service and for guaranteeing a subsidy for low income customers.

Limits and Restrictions

Regulatory Resolution 299/2008 repeals certain sections of ANEEL Resolution 278/2000, which established the limits and conditions for the participation of electricity distributors and traders. Specifically, the section of Resolution 278/2000 on limits to generation was repealed. Subsequently, Resolution 378/2009 establishes new procedures for analyzing mergers and violations of economic regulations in the electric power sector.

Regulation of Generation Companies

Concessions

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

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

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

In September 2012, ANEEL’s Provisional Resolution 579 established the criteria for the renewal of generation, transmission and distribution concessions that expire between 2015 and 2017. It foresees the reduction of energy tariffs and indemnities for non-depreciated investments in hydroelectric plants and transmission installations. In addition, Provisional Resolution 577 defines procedures for the temporary provision of the electricity energy service in the case of cancellation of concessions due to management problems. It also reinforces the powers of ANEEL to intervene in the case of economic-financial imbalance in order to avoid affecting the service provided.

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On January 23, 2013, the Brazilian Congress approved Law 12,783, which renewed electricity concessions according to Provisional Resolution 579. This law requires companies to reduce the average electricity tariff by 20.2% from February 2013, and to extend generation, transmission and distribution concessions for up to 30 years, for both hydroelectric and thermal plants, which expire between 2015 and 2017.

Dispatch and Pricing (Settlement Price for the Differences (“PLD”)

The PLD is used to value the purchase and the sale of electric power in the short term market. The price-setting process of the electric power traded in the short-term market is accomplished by using the data employed by the ONS to optimize the operation of the Brazilian NIS.

The mathematical models used to compute the PLD take into account the preponderance of hydro-electric plants within the Brazilian power generation grid. The purpose is to find an optimal equilibrium solution between the current benefit obtained from the use of the water and the future benefit resulting from its storage, measured in terms of the savings from the use of fuels for thermal plants.

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

The model used to compute the PLD seeks to achieve an optimal result for the period being studied and to define both the hydroelectric and thermal power generation for each submarket by taking into account the hydrological conditions, the demand for electric power, the prices of fuel, the cost of the deficit, the entry of new projects into operation and the availability of equipment used for generation and transmission. As result of this process, the Marginal Operational Costs can be obtained for each load level and submarket.

The calculation of the price is based on the “ex-ante” dispatch that is determined based on estimated information existing prior to the actual operation of the system, taking into account the declared availability amounts regarding both the generation and the consumption envisaged for each submarket. The complete process for calculating the PLD involves the use of the computational models NEWAVE and DECOMP. These models are used to calculate the Marginal Operational Cost for each submarket on a monthly and weekly basis.

Electricity Reallocation Mechanism

The Electricity Reallocation Mechanism (“MRE”) provides financial protection against hydrological risks for hydro-generators in order to mitigate the shared hydrological risks that affect generators and assure the optimal use of the hydroelectric resources of the interconnected power system.

The mechanism guarantees that despite of the centralized dispatch all the generators that participate in the MRE will have a participation in the overall hydro generation dispatched in the proportion of its assured energy. The value of the final allocated energy to a generator can be greater or less than its assured energy depending if the overall hydro generation is greater or less than the overall hydro assured energy, respectively. This mechanism permits each generator, before buying energy in the spot market to fulfill its contracts, to purchase cheaper energy at a price that covers the incremental costs of operation and maintenance of hydroelectric plants and the payment of financial use of water compensation. The tariff used for trading energy in the MRE, the Optimum Energy Tariff, was set as R$ 10.54 per MWh for 2014.

As the overall generation is more stable than the individual production, the MRE is a very efficient mechanism to reduce the volatility of the individual production and the hydrological risk. Therefore, the energy contracts are only financial instruments in the Brazilian system and generation is totally disassociated from the energy contracts.

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Sales Between the Agents of the Market

The current model for the electric sector states that the trading of electric power is accomplished in two market environments: the Regulated Contracting Environment (“ACR” in its Portuguese acronym) and the Free-Market Contracting Environment (“ACL” in its Portuguese acronym).

Contracting in the ACR is formalized by means of regulated, bilateral agreements, called Electric Power Trading Agreements within the Regulated Environment (“CCEAR” in its Portuguese acronym) entered into between selling agents (sellers, generators, independent producers or self-producers) and purchasing agents (distributors) who participate in electric power purchase and sale auctions.

In the ACL environment, on the other hand, the negotiation among the generating agents, trading agents, free-market customers, importers and exporters of electric power is accomplished freely, whereby the agreements for the purchase and sale of electric power are entered into through bilateral agreements.

Generation agents, regardless of whether they are public generation concessionaires, IPPs, self-producers or trading agents, are allowed to sell electric power within the two environments. This allows the overall market to remain competitive. All agreements that have been entered into in the ACR or the ACL are registered in the CCEE and they serve as a basis for the accounting posting and the settlement of the differences in the short term market.

Sales by Generation Companies to Unregulated Customers

In the unregulated contracting environment, the conditions for purchasing energy are negotiable between suppliers and their customers. As for the regulated environment, where distribution companies operate, the purchase of energy must be conducted pursuant to a bidding process coordinated by ANEEL. In 2012, the Brazilian MME’s Decree 455 mandated the creation of a prices index and a requirement to register energy contracts ex-ante. According to the internal schedule of the CCEE, the new price index is expected to be published in June 2014. It is expected that this index will be subject to internal tests over a six month period before being officially published in the market.

Sales by Distribution Companies and Regulated Customers

Pursuant to market regulations, 100% of the energy demand from distributors must be satisfied through long-term contracts. Contracts must be renewed or newly entered into prior to the expiration of current contracts.

Tenders under the current regulatory environment are as follows: (i) A-5 tenders, corresponding to tenders for energy purchases from new generation sources to be supplied five years following the tender; (ii) A-3 tenders, for the acquisition of energy from new generation sources; (iii) A- 1 tenders, for the acquisition of energy from existing generation sources; and (iv) A- 0 tenders, energy adjustment tenders, for supplementing the energy load necessary for servicing customers in the distribution concession market, with a limit of 1% of such load. Reserve tenders are also carried out for increasing the security of the system.

Various energy tenders were held during 2011, including an A-3 tender and a reserve tender completed in August and an A-5 tender in December.

In the A-3 tender process for the supply of 2014, 2,744.6 MW of new capacity was assigned and is to be generated by 51 plants. Of the total contracted, 62% was from renewable sources (hydroelectric, wind and biomass) and the remaining 38% from fossil fuels (natural gas).

The tender for reserve energy in August 2011 assigned 1,218.1 MW. These were from wind farm, thermal and biomass projects, involving a total of 41 generating plants. The average price was R$ 99.61 per MWh.

For the new A-5 tender process carried out in December 2011, 42 projects were assigned with a capacity of 1,211.5 MW at an average price of R$ 102.18 per MWh.

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For 2012, two tenders were planned. An A-3 tender for December 12, 2012 was cancelled due to the low demand of distributors. An A-5 tender for new energy was held on December 14, 2012. Of the 574.3 MW of total installed capacity up for tender, 303.5 MW was allocated. The weighted average price was fixed in R$ 91.25 per MWh. Of the total energy allocated, 294.2 MW was allocated to two hydroelectric plants (at an average price of R$ 93.46 per MWh) and 281.9 MW was allocated to ten wind farms (at an average price of R$ 87.94 per MWh) .

In 2013, six tenders took place: (i) an energy adjustments tender in which no energy was allocated and the maximum price was fixed at R$ 163 per MWh; (ii) an A-0 tender in which no energy was allocated and the maximum price was fixed at R$ 177.22 per MWh; (iii) an A-1 tender in which only 39% of the distributors requirements was allocated at average price of R$ 177.22 per MWh; (iv) an A-3 tender with 332.5 MWh allocated to 39 wind power plants at average price of R$ 124.43 per MWh; (v) an A-5.1 tender in which 690.8 MWh was allocated (46% hydroelectric plants and 54% of biomass thermal plants) at an average price of R$ 124.97 per MWh; and (vi) an A-5.2 tender in which 1,599.5 MWh (33% of hydroelectric plants, 5% of biomass thermal plants and 62% of wind power plants) was allocated at an average price of R$ 109.93 MWh.

For 2014, an A-3 tender has been scheduled for June 6, 2014. Three energy adjustment tenders, at least one A-1 tender and one A-5 are expected to be held as well.

Sales of Capacity to Other Generation Companies

Generators can sell their energy to other generators through direct negotiation at freely-agreed prices and conditions.

Incentives and Penalties

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

Law 10,438/02 created certain incentive programs for the use of alternative sources in the generation of electricity, known under the name of Proinfa. It assures the purchase of the electricity generated by Eletrobras for a period of 20 years and financial support from the Brazilian National Development Bank (“BNDES” in its Portuguese acronym) a state-owned development bank. Other programs include a discount of up to 50% on the distribution or transmission tariffs and a special exception for the customers with electricity demand in the range of 500 to 3,000 kW who decide to migrate to an unregulated environment, provided that such customers purchase electricity from generating companies using non-conventional sources of electricity.

Selling agents are responsible for paying the buying agent if they are unable to satisfy their delivery obligations. ANEEL regulations set forth the fines applicable to electricity agents based on the nature and the materiality of the violation (including warnings, fines, temporary suspension of the right to participate in bids for new concessions, licenses or authorizations and forfeiture). For each violation, fines may be imposed for up to 2% of the concessionaire’s revenues arising from the sale of electricity and services provided (net of taxes) in the 12-month period immediately preceding any assessment notice.

ANEEL may also impose restrictions on the terms and conditions of agreements between related parties and, under extreme circumstances, terminate such agreements.

Decree 5,163/2004 establishes that the selling agents must assure 100% physical coverage for their energy and power contracts. This coverage must be made up of physical guarantees from its own power plants or through the purchase of energy or power contracts from third parties.

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Among other aspects, ANEEL’s Normative Resolution 109/2004 specifies that when these limits are not met, the generation companies and traders are subject to financial penalties. The determination of penalties is predicated on a 12-month period and the revenues obtained from the levying of the penalties are reverted to tariff modality within the ACR.

If the limits on contracting and physical coverage defined in the Trading Rules are not met, the relevant generation companies and traders are notified by the Superintendent of CCEE. Pursuant to the specific Trading Procedure, CCEE’s agents are allowed to file an appeal to be evaluated by CCEE’s Board of Directors who then decides whether to collect or to cancel the financial penalty.

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

Regulation in Transmission

Transmission lines in Brazil are usually very long, since most hydroelectric plants are usually located away from the large centers of power consumption. Today, the country’s system is almost entirely interconnected. Only the states of Amazonas, Roraima, Acre, Amapá, Rondônia and a part of Pará are still not connected to the interconnected power system. In these states, supply is carried out by small thermal plants or hydroelectric plants located close to their respective capital cities, but the Brazilian government is gradually connecting these areas.

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

Any electric power market agent that produces or consumes power is entitled to use the basic network. Free-market customers also have this right, provided that they comply with certain technical and legal requirements. This is called “free access” and is guaranteed by law and by ANEEL.

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

Environmental Regulation

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

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

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Colombia

Industry Overview

Industry Structure

The Wholesale Electricity Market in Colombia (“Colombian MEM” in its Spanish acronym) is based on a competitive market model and operates under open access principles. The Colombian government participates in this market through an institutional structure that is responsible for setting forth policies and regulations, as well as for exercising supervision and control powers in respect of market participants. The Colombian MEM relies for its effective operation on a central agency known as the Colombian Administrator of the Commercial Exchange System (“ASIC” in its Spanish acronym).

The Colombian National Interconnected Electric System (“Colombian NIS”) includes generation plants, the interconnection grid, regional transmission lines, distribution lines and end-customers.

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

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

LOGO

Generation activity consists of the production of electricity through hydroelectric, thermoelectric and all other generation plants connected to the Colombian NIS. The generation sector is organized on a competitive basis, with independent generators selling their output on the spot market or through private contracts with large customers, other generators and traders. Generation companies are required to participate in the Colombian MEM with all of their generation plants or units connected to the Colombian NIS with generating capacities equivalent to or exceeding 20 MW. Generation companies declare their energy availability and the price at which they are willing to sell it. This electricity is centrally dispatched by the National Dispatch Center (“CND” in its Spanish acronym).

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

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

1. Energy spot market: short term daily market

2. Bilateral contracts: long term market; and

3. “Firm Energy.”

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

Transmission works under monopoly conditions and with a guaranteed annual fixed income that is determined by the new replacement value of the networks and equipment and by the resulting value of bidding processes awarding new projects for the expansion of the National Transmission System (“NTS”). This value is allocated among the traders of the NTS in proportion to their energy demand.

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

There is one interconnected system, the Colombian NIS, and several isolated regional and smaller systems that provide electricity to specific areas. According to the World Energy Council 93.6% of the Colombian population in 2012 received electricity through the public network.

Principal Regulatory Authorities

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

The Colombian Mining and Energy Planning Agency (“UPME” in its Spanish acronym) is in charge of planning the expansion of the generation and transmission networks.

The National Council for Economic and Social Policy (“CONPES” in its Spanish acronym) is the highest national planning authority and works as an advisory entity to the government in all aspects related to Colombia’s economic and social development. It coordinates and directs the entities responsible for economic and social direction, through the study and approval of documents on policy development.

The National Planning Department (“DNP” in its Spanish acronym) performs the functions of Executive Secretariat of the CONPES and is therefore the entity responsible for coordinating and presenting the documents for discussion at meetings.

The Energy and Gas Regulatory Commission (“CREG” in its Spanish acronym) implements the principles of the industry set out by the Colombian Electricity Act. This commission is constituted by five experts named by the Colombian President, the Colombian MME, the Colombian Ministry of Public Credit and the director of the DNP or their delegates. Such principles are: efficiency (the correct allocation and use of resources and the supply of electricity at minimum cost); quality (compliance with technical requirements); continuity (continuous electricity supply without unjustified interruptions); adaptability (the incorporation of modern technology and administrative systems to promote quality and efficiency); neutrality (impartial treatment of all electricity customers); solidarity (the provision of funds by high-income customers to subsidize the subsistence consumption of low-income customers); and fairness (an adequate and nondiscriminatory supply of electricity to all regions and sectors of the country).

CREG is empowered to issue regulations that govern technical and commercial operations and to set charges for regulated activities. CREG’s main functions are to establish conditions for gradual deregulation of the electricity sector toward an open and competitive market, approve charges for transmission and distribution networks and for regulated customers, establish the methodology for calculating maximum tariffs for supplying the regulated market, regulations for planning and coordination of operations of the Colombian NIS, technical requirements for quality, reliability and security of supply, and protection of customers’ rights.

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The National Operation Council (“CNO” in its Spanish acronym) is responsible for establishing technical standards to facilitate the efficient integration and operation of the Colombian NIS. It is a consultative entity composed of the CND’s Director and generation, transmission and distribution company representatives.

The Commercialization Advisory Committee (“CAC”) is an advisory entity which assists CREG with the commercial aspects of the Colombian MEM.

The Superintendency of Industry and Commerce investigates, corrects and sanctions restrictive commercial competition practices, such as antitrust behavior. It also oversees mergers of companies operating in the same productive activities to prevent excessive concentration or monopoly of certain industries.

The Superintendency of Domestic Public Services (“SSPD” in its Spanish acronym) is responsible for overseeing all public utility services companies. The SSPD monitors the efficiency of all utility companies and the quality of services. The SSPD can also assume control over utility companies when the availability of utility services or the viability of such companies is at risk. Other duties include (i) enforcing regulations, imposing penalties and generally overseeing the financial and administrative performance of public utility companies, (ii) providing accounting norms and rules for public service companies, and (iii) in general, organizing information networks and databases pertaining to public utilities.

The Ministry of Environment and Sustainable Development is responsible for the management of the environment and renewable natural resources. It is also responsible for guiding and regulating environmental planning as well as developing policies and regulations. The Ministry of Environment and Sustainable Development’s goal is to recover, conserve, protect, and promote sustainable use of renewable natural resources, the environment of the nation, and to ensure sustainable development, without prejudice to the functions assigned to other sectors.

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

The Electricity Law

General

In 1994, the Colombian Congress passed significant reforms affecting the public utilities industry. These reforms, contained in Law 142, known as the Public Utility Services Law (“LSPD” in its Spanish acronym), and Law 143, were the result of constitutional amendments made in 1991. These laws form the basic legal framework that currently governs the electricity sector in Colombia. The most significant reforms included the opening of the electricity industry to private sector participation, the functional segregation of the electricity sector into four distinct activities (generation, transmission, distribution and trading), the creation of an open and competitive wholesale electricity market, the regulation of transmission and distribution activities as regulated monopolies and the adoption of universal access principles applicable to transmission and distribution networks.

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

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Limits and Restrictions

The market share for generators and traders is limited. The limit for generators is 25% of the Colombian system’s Firm Energy. The principal market share metric used by CREG to regulate the generation market is the percentage of Firm Energy that a market participant holds.

Additionally, if an electricity generation company’s share of Colombia’s total Firm Energy ranges from 25% to 30% and the market’s Herfindahl Hirschman Index (“IHH” in its Spanish acronym), a measure of market concentration, is at least 1,800, such company becomes subject to monitoring by the SSPD. If an electricity generation company’s share of Colombia’s total Firm Energy exceeds 30%, such company may be required to sell its share exceeding the 25% threshold.

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

Such limits are applied to economic groups, including companies that are controlled by, or under common control with, other companies. In addition, generators may not own more than a 25% interest in a distributor, and vice versa. However, this limitation only applies to individual companies and does not preclude cross-ownership by companies within the same corporate group.

A distribution company can have more than 25% of an integrated company’s equity if the market share of the latter company is less than 2% of the national generation business. A company created before the enactment of Law 143 is prohibited from merging with another company created after Law 143 came into effect.

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

Regulation of Generation Companies

Concessions

The Colombian electricity sector was structurally reformed by Laws 142 and 143 of 1994. Under this new legal structure, economic activities related to the provision of the electricity service are governed by the constitutional principles of free market economic activity, free market private initiative, freedom to enter and leave, corporate freedom, free market competition and private property, with regulation and inspection, surveillance and control by the state.

According to Law 143 of 1994, these constitutional principles of freedom are the general rule in the electricity sector business, while the concession is the exception. Different economic, public, private or mixed agents may participate in the sector’s activities, which agents shall enjoy the freedom to develop their functions in a context of free market competition. In order to operate or start up projects, they must obtain from the competent authorities the necessary environmental, sanitation and water-right permits as well as other municipal permits and licenses. All economic agents may construct generation plants and their respective connection lines to the interconnection and transmission networks.

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

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Dispatch and Pricing

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

The Colombian MEM facilitates the sale of excess energy that has not been committed under contracts. In the wholesale market, an hourly spot price for all dispatched units is established based on the offer price of the highest priced energy dispatched unit for that period. The CND receives price bids each day from all the generators participating in the Colombian MEM. These bids indicate prices and the hourly available capacity for the following day. Based on this information, the CND, guided by an “optimal dispatch” principle (which assumes an infinite transmission capacity through the network), ranks the dispatch optimized during the 24-hour period, taking into account initial operating conditions, and determining which generators will be dispatched the following day in order to satisfy expected demand. The price for all generators is set as the most expensive generator dispatched in each hourly period under the optimal dispatch. This price-ranking system is intended to ensure that national demand, increased by the total amount of energy exported to other countries, will be satisfied at the lowest cost combination of available generating units in the country.

Additionally, the CND plans for the dispatch, which takes into account the limitations of the network, as well as other conditions necessary to satisfy the energy demand expected for the following day in a safe, reliable and cost-efficient manner. The cost differences between the “planned dispatch” and the “optimal dispatch” are called “restriction costs.” The net value of such restriction costs is assigned proportionally to all the traders within the Colombian NIS, according to their energy demand, and these costs are passed through to the end customers. Some generators have initiated legal proceedings against the government arguing that recognized prices do not fully cover the costs associated with these restrictions on the grounds that current regulations do not take into account all the costs incurred under safely reliable generation. However, from CREG’s point of view, Resolution 036-2010 modified the remuneration of these restrictions for hydro plants by assigning the opportunity cost to the spot price.

In July 2012 and October 2013, CREG published Resolutions 076-2012 and 082-2013, respectively (“Statute for situations of scarcity in the MEM as part of the operative regulations”) that proposed a draft resolution for defining the rules of operation under critical supply conditions.

Sales by Generation Companies to Unregulated Customers

In the unregulated market, generation companies and unregulated customers sign contracts in which terms and prices are freely agreed. Typically, these agreements establish that the customer pays the energy that it consumes each month without a cap or a floor. The prices are fixed in Colombian pesos indexed monthly to the Colombian PPI. According to resolution CREG 131 of 1998, to be considered “unregulated,” customers are required to have an average monthly power demand for six months of at least 0.1 MW, or a minimum of 55 MWh in monthly average energy demand over the prior six months.

Sales by Distribution Companies to Regulated Customers

The regulated market is served by traders and by distributors acting as traders, who bill all service costs, according to prices regulated by CREG. The scheme allows distributors to pass through the average purchase price of all the market transactions that affect the regulated market into the customer’s tariff, thereby mitigating spot price volatility and providing an efficiency signal to the market. Additionally, CREG established a formula for the total cost of service, which transfers transmission, distribution, marketing costs, and physical losses costs to the regulated market.

Sales by Generation Companies to Traders for the Regulated Market

Traders in the regulated market are required to buy energy through procedures that ensure free market competition. For evaluating the bids, the buyer takes into account price factors as well as other technical conditions and commercial objectives to be defined before the contracting process. These agreements can be signed with

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different terms, such as: “Pay amount contracted,” “Pay amount demanded with or without a limit,” “Pay the percentage actually consumed,” etc. Prices are denominated in Colombian pesos indexed monthly to the Colombian CPI.

Sales to Other Generation Companies

Generators can sell their energy to other generators through direct negotiation, at freely negotiated prices and conditions.

Regulatory Charges

Contribution by generation per Law 99 of 1993: Generation companies are obliged to pay monthly payments based on their generation to the regional autonomous corporations for environmental protection in areas where the plants are located and to the municipalities where the generation plants are situated. For more information, see “— Environmental Regulation” below.

Generation contribution to the Financial Support Fund for Energy for Unconnected Zones (“FAZNI” in its Spanish acronym): Law 633 of 2000 (tax reform) states that generators must make a contribution of 1 Colombian peso to the FAZNI for every kilowatt dispatched on the Wholesale Energy Exchange. Initially, this requirement was effective until December 31, 2007 but it was extended to 2014 by Law 2,099 of November 2006.

Incentives and Penalties

Generators connected to the Colombian NIS can also receive “reliability payments” which are a result of the OEF that they provide to the system. The OEF is a commitment on the part of generation companies backed by its physical resource capable of producing firm energy during scarcity periods. A generator that acquires an OEF will receive fixed compensation during the commitment period, whether or not the fulfillment of its obligation is required. To receive reliability payments, generators have to participate in firm energy bids by declaring and certifying such firm energy. Until November 2012, the transition period, the firm energy supply for reliability purposes was assigned proportionally to the declared firm energy of each generator. Beyond the transition period, the additional firm energy required by the system is allocated by bids.

During 2011, CREG published resolutions for the assignment of OEF for the periods from December 2014 to November 2015 and from December 2015 to November 2016. For the first of these periods, the OEF assigned this pro rata to the existing generators while, for the second, it carried out a second tender for the electricity sector on December 27, 2011.

During 2013, Resolution 062-2013 created incentives for thermal plants to back up their OEF with imported natural gas to guarantee their OEF for 10 years, beginning December 2015.The new resolution proposes the foundations of the remuneration for the group of thermal plants in order to develop the first regasification terminal in Colombia. The project will be constructed by an “Infrastructure Agent” that will be chosen through a tender process in 2014.

On March 10, 2014, CREG published Resolution 022/ 2014, which defined a transitory regulated revenue in order to motivate the agents to build the regasification terminal.

The tender for firm energy for the period from November 2015 to December 2016 was made on December 27, 2011. Seven companies participated with a total of eight projects of which five were assigned at a price of US$ 15.7/MWh. The new projects are Río Ambeima (hydro, 45 MW), Carlos Lleras Restrepo (hydro, 78 MW), San Miguel (hydro, 42 MW), Gecelca 32 (thermal, 250 MW) and Tasajero 2 (thermal, 160 MW). The new assignments were made for a period of twenty years as of December 1, 2015.

In addition, on January 26, 2012, the auction was concluded for projects with long construction periods (“GPPS” in its Spanish acronym) which assigned OEFs for a period of twenty years to three hydroelectric projects and one thermal project. Two of these were assigned to new plants: Termonorte which will have a capacity of 88

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MW by 2017 and the Porvenir II hydroelectric power plant which will have a capacity of 352 MW by 2018. The other two involved increases in OEF for plants already under construction and had available firm energy following the GPPS process carried out in 2008 (Sogamoso and Pescadero-Ituango hydroelectric plants). The process ended with assignment prices below the maximum defined for the auction in December (US$ 15.7/MWh), and were in connection with Termonorte (US$ 14.9/MWh); Porvenir II (US$ 11.7/MWh); Sogamoso and Pescadero-Ituango (US$ 15.7/MWh).

CREG regulated the reconfiguration auction scheme, under the methodology of reliability charge that allowed agents to change the beginning of the OEF by renouncing the “reliability payments” and paying a premium. The market operator, XM, published the results of the auction sale reconfiguration of OEF and Termocol, Amoya and Gecelca were the participating companies.

During 2012 CREG also issued the statement regarding OEF allocation for the period from December 2016 to November 2017. CREG indicated that (i) a tender for OEF allocation was not necessary due to the conditions of the system and (ii) the assignment schedule will be published once there is greater certainty with regards the dates for execution of the Colombia-Panama interconnection agreement and the processes for importing natural gas. CREG Circular 045 states that this publication will be made after June 30, 2014.

Despite the statement, a tender was finalized in July 2012 for the reconfiguration of the OEF for the period from December 2012 to November 2013. The OEF was allocated to Termocol, which owns the Poliobras project (4.5 GWh per day) and to Amoyá, which owns the Isagen project (0.5 GWh per day). Such tenders are called when previously allocated OEFs exceed the projected demand for a certain period. The tender ended with a price margin of US$ 0.6 per MWh, which is over the reliability load price for the period from December 2012 to November 2013.

Electricity Exports and Imports

Decision CAN 536 of 2002, CAN 720 of 2009, and CAN 757 of 2011, signed by the countries that participate in the Andean Nations Community (“CAN” in its Spanish acronym), Colombia, Ecuador, Bolivia and Peru, established the general framework for the interconnection of electrical systems that created a coordinated economic dispatch for the countries involved in the interconnections. Under this framework, the interconnection system between Colombia and Ecuador was inaugurated in March 2003. The two countries adopted a transitional regime pursuant to CAN 757, while adopting common standards in order to make such international transactions viable.

In addition to the interconnection with Ecuador Colombia is also interconnected with Venezuela by three links, the most important being the Cuestecitas-Cuatricentenario line. During 2011 and 2012, there were some transfers of energy made from Colombia to Venezuela, due to shortages in Venezuela, over this line under an agreement between the presidents of both nations. The agreement covers estimated transactions of 30 GWh/month, with a demand of 70 MW in periods of low and medium load and of 140 MW in periods of high load. The contract was signed on February 1, 2013 for a term of eleven months and was formalized by a contract between Isagen (Colombia) and Corpoelec (Venezuela).

There is also an energy interconnection project with Venezuela being carried out by the Institute of Planning and Promotion of Energy Solutions for Non-Interconnected Zones (“IPSE” in its Spanish acronym) pursuant to an agreement between Colombia and Venezuela. Under the terms of this agreement, Colombia will sell electricity to Venezuela at a rate that is much cheaper than the costs to produce it. Venezuela is expected to pay for the electricity with fuel rather than cash. This interconnection project is estimated to cost US$ 8 billion and contemplates the construction of a 35.6 kilometer transmission line with a capacity of 34,500 volts in order to supply electricity to the region of San Fernando de Atabapo, Venezuela.

In the first half of 2012, CREG and the National Public Services Authority of Panama (“ASEP” in its Spanish acronym) issued resolutions that provided for enhancing the process for tendering of rights to construct the future interconnection line between Colombia and Panama.

The resolutions also supplement pre-existing resolutions by providing for provisions that allow Panamanian distribution companies to participate in future tenders in Colombia. The most important resolutions issued by

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Colombia are (i) CREG-002-2012, which attempts to resolve the discrepancies between firm capacity in Panama and the OEF in Colombia; (ii) CREG-004-2012, which outlines the exchanges in conditions of rationing; and (iii) CREG 057-2012, which is an operative agreement between the operators of the systems of Colombia and Panama. Panama has also issued parallel resolutions that enable Colombian companies to participate in tenders in Panama as international interconnection agents.

Emgesa, Isagen, Celsia and its subsidiary EPSA participated in the tender process to obtain line capacity rights in Panama that took place on August 21, 2012. These companies were able to participate in the tender by forming subsidiaries in Panama and complying with all requirements under Panamanian law, including the provisions relating to guarantees.

In June 2012, Interconexión Eléctrica Colombia-Panamá (“ICP”), which is jointly owned by Interconexión Eléctrica de Colombia (“ISA”) and the state-owned Empresa de Transmisión Eléctrica de Panamá (“ETESA”), was entrusted with the construction of an interconnection project and was allowed to join the tender for capacity rights. ICP submitted the base amount that is necessary to participate in the tender and proceeded to obtain prequalifications in July and August 2012. However, the tender process was suspended indefinitely on August 19, 2012. This was primarily due to financial reasons as the Panamanian government, citing budget constraints, refused to provide a firm commitment to contribute capital.

ICP is expected to continue to seek financial support in order to ensure the viability of the project and reduce uncertainties for the participants. With the support from the Interamerican Development Bank, ICP has hired a consultant to carry out a study that will explore alternatives plans that would result in more competitive energy prices and greater business opportunities. The Colombian government is also in conversations with its Panamanian counterpart in order to restart the process.

In November 2012, the Declaration of Santiago was signed by Chile, Colombia, Ecuador, Peru and Bolivia. The main purpose of this declaration was to facilitate regional electricity transaction by harmonizing regulatory frameworks of the member countries.

Gas Market

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

This regulatory framework is the result of a former proposal that sought to reform the wholesale market for natural gas and ensure that it operates under the principles of transparency and liquidity. This new framework also outlines entities that are eligible to participate in each market, the types of permitted transactions, and the kind of contracts that may be entered into. It even seeks to create standardized force majeure provisions for such contracts in order to clarify the responsibilities of the parties. The new rules took effect in August 2013.

Additionally, in June 2013 the regulatory authorities published a new incentive framework so as to enable the possibility for the first regasification facility on the north coast of the country. The principal purpose of this facility will be to serve as a backup source of gas to certain thermal plants in Colombia. In the long term, this facility will be an alternative point of supply for the market.

Regulation in Transmission

Transmission companies which operate at no less than 220 kV constitute the National Transmission System (“NTS”). They are required to provide access to third parties on equal conditions and are authorized to collect a tariff for their services. The transmission tariff includes a connection charge that covers the cost of operating the facilities, and a usage charge, which applies only to traders.

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

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

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

Trading Regulation

The retail market is divided into regulated and unregulated customers. Customers in the unregulated market may freely and directly enter into electricity supply contracts with a generator or a distributor, acting as traders, or from a pure trader. The unregulated customer, which for 2013 represented about 33% of the market, consists of customers with a peak demand in excess of 0.1 MW or a minimum monthly energy consumption of 55 MWh.

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

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

The trading tariff formula became effective on February 1, 2008. The main changes to this formula were the establishment of a fixed monthly charge and the introduction of reduction costs of non-technical energy losses in the trading charges. In addition, CREG allows traders in the regulated market to choose tariff options to manage tariff increments.

In May 2009, a company called Derivex was created so as to incorporate an energy derivatives market. In October 2010, Derivex began its operation with the first electricity forward derivative contract.

In December 2011, CREG issued the Retailing Code, which includes specific rules that improve retailers’ relations with other electricity market members. It established new regulations about energy measurement, non-technical losses, the retailers’ connection to the wholesale electricity market, and the retailers’ credit risks, among other considerations.

In October 2013, CREG published a new resolution that defines “technical equity” (technical equity corresponding to the minimum equity that allows agents to perform operations on the wholesale market, either as sellers or buyers) as a mechanism to rate the technical abilities of companies in order to protect the wholesale market from unstable companies. According to the new rule, any transaction in the spot market has to be lower than the technical equity of the companies involved in the transaction.

In order to improve wholesale price formation, CREG has been designing a new energy procurement scheme based on long term energy bids, known as Organized Market (“MOR” in its Spanish acronym). The final rules for this new system are not available, but CREG issued a new draft version of the mechanism by Resolution 117-2013, and the deadline for consultations has passed. It is expected that CREG will issue the final resolution on MOR in early 2014 and will call for the first auction in mid-2014.

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Tariffs to Final Customers

The energy trader is responsible for charging the electricity costs to end customers and to transfer their payments to the industry’s agents. The tariffs applied to regulated customers are calculated pursuant to a formula established by CREG. This formula reflects the costs of the industry: generation, transmission, distribution (depending on the customer’s connection level), trading losses, constraints, administrative costs, and market operating costs.

In addition, the final costs of the service are affected by subsidies and/or contributions that are applied according to the socio-economic level of each customer. When subsidies exceed contributions, the Colombian government covers the difference. The subsidies mechanism is experiencing some modifications. Colombian MME’s Resolution 18 1479 (August 2012) modified the subsidy removal method for residential customers whose consumption exceeds the subsistence consumption, as established in article 2 of Resolution 18 1272 of 2011.Colombian MME’s Decree 011 2012 regulating the Social Energy Fund (“FOES” in its Spanish acronym) as provided in article 103 of Law 1450 of 2011 (published in 2012). The purpose of FOES is to cover up to CPs 46 per kWh of the value of electricity for subsistence consumption of residential customers belonging to income groups 1 and 2 of the least developed rural areas.

Another factor that affects the final tariff is the Distribution Area which established a single tariff for the distribution companies in adjacent geographic zones.

Environmental Regulation

The environmental framework in Colombia was established by Law 99/1993, which also established the Colombian Ministry of the Environment (now the Ministry of Environment and Sustainable Development) as the authority for determining environmental policies. The Colombian Ministry of Environment defines issues, executes policies and regulations that focus on the recovery, conservation, protection, organization, administration and use of renewable resources.

Any entity planning to develop projects or activities relating to generation, interconnection, transmission or distribution of electricity that may result in environmental deterioration must first obtain environmental permits and licenses and also establish environmental management plans.

According to Law 99, generation plants that have a total installed nominal capacity above 10 MW are required to contribute to the conservation of the environment. Hydroelectric power plants must pay 6% of their generation and thermoelectric plants must pay 4% of their generation in addition to a tariff that is annually determined. This payment is made monthly to the municipalities and environmental corporations where these facilities are located.

Law 1450 of 2011 issued the National Development Plan 2010-2014. The plan establishes that between 2010 and 2014, the government must develop strategies for environmental sustainability and for the prevention of environment risks. These include measures such as the national plan for adaptation to climate change, the environmental licensing process and environmental impact studies.

In 2011, Institutional Decree 3,570 established a new regulatory structure for the environment, creating the Colombian Ministry of Environment and Sustainable Development (previously, the functions of the Ministry of the Environment were established in conjunction with functions of the Ministry of Housing). The main objective of the Colombian Ministry of Environment and Sustainable Development is the formulation and management of environmental and renewable natural resource policies. In 2012, the Colombian Ministry of Environment and Sustainable Development published several resolutions. Resolution 1517 of 2012 established the procedures relating to the Environmental Compensation for Biodiversity Loss while Decree 1640 of 2012 set forth regulations for the planning and management of hydrographic basins. In addition, Resolution 1526 of 2012 established the procedural requirements for the subtraction of the forest areas protected by Law 2 of 1959.

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In 2012, the Colombian Ministry of the Environment and Sustainable Development included the NAMA (Nationally Appropriate Mitigation Action) in the CDM (Clean Development Mechanism) & NAMA Portfolio.

NAMA and CDM are two mechanisms established by the United Nations in order to promote the developments of project which reduce emissions of greenhouse gases in certain countries (listed in Exhibit I of the Kyoto Protocol), for example, electric vehicles promoted by Endesa Spain and Enersis.

The Colombian Ministry of the Environment and Sustainable Development publishes progress reports annually for the portfolio projects of CDM and NAMA under development in Colombia. This gives interested parties a chance to buy CERs (Certified Emission Reduction) in connection with CDM projects and also provides financing opportunities in the case of NAMA projects.

In December 2012, the UPME published Resolution 0563, which establishes the procedure for the exclusion of sales tax for the programs or activities related to reduced energy consumption and energy efficiency.

In August 2013, the DNP issued CONPES Document 3762, a policy text that established guidelines for the identification and priorization of infrastructure projects that are of national and strategic interest in the energy, mining, oil, gas, and transportation sectors. It defines the relevant issues related with the formalities and procedures for acquiring land, prior consultation, community relations, environmental licensing and permits, and institutional coordination, all of which need to be resolved in order to assure the correct formulation and development of those projects.

In the last few years, the environmental regulation for the electricity sector has been focused on regulating power plant emissions, hydro policies (including water discharges and basin organizations), and environmental licensing and penalties.

Peru

Industry Overview

Industry Structure

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

The following chart shows the relationships among the various participants in the interconnected system, (“SEIN” in its Spanish acronym)

LOGO

The generation segment is composed of companies which own generation plants. This segment is noted for being a competitive market in which prices tend to reflect the marginal cost of production.

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Electricity generators, as energy producers, have capacity and energy sale commitments with their contracted customers. Generators may sell this capacity and energy to both distributors and unregulated customers.

The energy received by a generator’s unregulated and regulated customers does not necessarily coincide with the energy produced by that supplier since the generation plants’ production is allocated by the Committee of Economic Operation of the System (“COES” in its Spanish acronym), the system operator, through a centralized dispatch. The transfer cost is minimized through a consideration of the variable production costs of each power plant, regardless of their contractual commitments (the only exception to this rule are the natural gas (NG) plants wich declare once a year the NG price for dispatch purpose). Therefore, there is a short-term market also managed by the COES, where an economic balance is made between the energy produced and the consumption required by the generators’ customers. The only exception to this rule are the natural gas plants which declare (once a year) the natural gas price for dispatch matters.

The generation plants’ production and the customers’ energy consumption at the nodal short-term marginal cost are valued, and the deficit generators pay for the energy purchased from surplus generators. The balance made in connection with energy sales is also carried out with respect to capacity, in which case the price of the capacity corresponds to a price regulated by the Supervising Entity on Investment in Energy and Mining (“Osinergmin” in its Spanish acronym), the Peruvian regulatory electricity authority.

In 2008, Osinergmin defined a new rule to calculate spot prices through December 2013 due to gas transport and electricity transmission problems. Decree 049/2008 established two models, one which represented a theoretical dispatch without considering any restrictions and another that considered real dispatch with restrictions. The spot price is obtained from the theoretical dispatch (known as “idealized marginal cost”), and the additional operating costs resulting from system restrictions are paid by demand to the affected generators through a mechanism established by the authority. The “idealized marginal cost” regime was finally extended until December 31, 2016.

The settlements made by the COES also include payments and/or collections for complementary services such as frequency and tension regulation. They also consider compensation for operating cost overruns, such as the operation at minimum load, random operational tests, etc.

Regulation DS 027-2011-EM of June 2011 established that as of January 2014, several participants may also participate as buyers in the short-term market, in addition to the generators. These other participants include distributors (in order to meet the demand of their unregulated customers), large customers with demand over 10 MW, and a group of unregulated customers whose aggregate demand exceeds 10 MW. This regulation is now suspensed until the wholesale market prices return to previous levels (anticipated to occur after 2017).

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

Electricity distribution is an activity carried out in the concession areas granted to different distribution companies.

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

There is only one interconnected system, the SEIN, and several isolated regional and smaller systems that provide electricity to specific areas. According to the National Institute of Statistics of Peru (“INEI” in its Spanish acronym as of December 2012, 91.2% of the population obtained electricity through the public network.

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Principal Regulatory Authorities

The Peruvian Ministry of Energy and Mining (“MINEM” in its Spanish acronym) defines energy policies applicable nationwide, regulates environmental matters applicable to the energy sector and oversees the granting, supervision, maturity and termination of licenses, authorizations and concessions for generation, transmission, and distribution activities. On August 10, 2012, Regulation DS 030-2012-EM amended the articles of organization and defined the functions of MINEM and the Natural Gas Management Department.

The Agency for the Promotion of Private Investment (“PROINVERSIÓN” in its Spanish acronym) is a public entity responsible for attracting private investment in public utilities and infrastructure works. It also advises regarding the difficulties faced by investors in making their investments.

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

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

The National Institute for Defense of Competition and Intellectual Property (“INDECOPI” in its Spanish acronym) is responsible for promoting competition, protecting customer rights and safeguarding all forms of intellectual property.

The General Electricity Authority (“DGE” in its Spanish acronym) is the regulatory technical entity responsible for evaluating the electricity sector, and proposes the necessary regulations for the development of the electricity generation, transmission and distribution activities.

The Peruvian Ministry of Environment (“MINAM” in its Spanish acronym) defines environmental policies applicable nationwide and is the head of the national environmental management system, which includes the National Environmental Impact Assessment System, the National Environmental Information System, the Protected Natural Areas System, as well as the management of natural resources in its area of competence, biodiversity and climate change, among others.

The Electricity Law

General

The general legal framework applicable to the Peruvian electricity industry includes: the Law of Electricity Concessions (Decree Law 25,844/1992) and its ancillary regulations, the Law to Secure the Efficient Development of Electricity Generation (Law 28,832/2006), the Technical Regulation on the Quality of the Electricity Supply (Supreme Decree 020/1997), the Electricity Import and Export Regulation (Supreme Decree 049/2005), the Antitrust Law for the Electricity Sector (Law 26,876/1997), and the law that regulates the activity of Osinergmin (Law 26,734/1996, together with Law 27,699/2002).

Some of the characteristics of the regulatory framework are (i) the separation of the three main activities: generation, transmission and distribution; (ii) freely-determined prices for the supply of energy in competitive market conditions; (iii) a system of regulated prices based on the principle of efficiency together with a bidding regime; and (iv) private operation of the interconnected electricity systems subject to the principles of efficiency and quality of service.

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Law 29,852/2012 and Regulation 021-2012-EM created the Hydrocarbons Energy Security System and the Fund of Social Energy Inclusion (“FISE” in its Spanish acronym). These laws also created a system of social compensation and universal service for the most vulnerable sectors of the population which will be financed by surcharges on the electricity billing of unregulated customers (equivalent to the surcharge that exists today for regulated customers on the Electrical Social Compensation Fund (“FOSE” in its Spanish acronym)), transport surcharges for hydrocarbon-derivate liquids and natural gas multi-pipelines and surcharges on the use of the natural-gas pipeline.

Osinergmin and distribution companies will be the administrators of the FISE, which funds will be directed to (i) the massification of natural gas to vulnerable sectors, (ii) develop new energy sources like photovoltaic cells, solar panels, etc., and (iii) supply liquefied petroleum gas (“LPG”) to vulnerable sectors.

Law 29,969/2012 provides for the massification of natural gas. State electricity distributors are authorized to carry out natural-gas programs, including the distribution of natural gas in their concession area. They will also be able to associate with companies specializing in the development of gas-distribution projects. Within a maximum term of three years from the start of the gas distribution, MINEM will start the process of promoting private investment for the granting of the gas-distribution concession of gas by the pipeline network.

Law 29,970/2012 guarantees energy security and promotes the development of the petro-chemical complex in the south of the country. Under this law, the following agendas have been declared as a matter of national interest: (i) guaranteeing energy security, (ii) transporting ethane to the south of Peru; and (iii) constructing regional pipelines in the regions of Huancavelica, Junín, and Ayacucho and linking them with the existing gas pipelines.

Limits and Restrictions

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

An authorization is compulsory for those electricity companies that hold more than 5% of another business segment, either before or as a result of a merger or integration. An authorization is also required for the horizontal integration of generation, transmission and distribution activities which result in a market share of 15% or higher of any business segment, either before or as a result of any operation.

Such authorizations are granted by the Institute for Defense of the Consumer and Intellectual Property, using the market share information provided by Osinergmin.

Regulation of Generation Companies

Concessions

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

In order to receive a concession, the applicant must first request for a temporary concession of two years, and must subsequently apply for a definitive concession.

In order to receive an authorization, the applicant must file a petition before the MINEM. If the petition is admitted and no opposition is presented, the MINEM grants the authorization to develop generation activities for unlimited time, subject to compliance with applicable regulations.

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Dispatch and Pricing

The coordination of electricity dispatch operations, the setting of spot prices and the control and management of economic transactions that take place in the SEIN are controlled by COES. Generators can sell energy directly to large customers and buy the deficit or transfer the surplus between contracted energy and actual production in the pool at the spot price. Resolution 080-2012-OS/CD ( 2012) established the criteria and methodology for deciding the real-time operation under exceptional conditions as declared by the MINEM.

Sales by Generation Companies to Unregulated Customers

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

Sales to Distribution Companies and Certain Regulated Customers

Sales to distributors can be under bilateral contracts at a price no greater than the regulated price in the case of regulated customers, or at an agreed price in the case of unregulated customers. In addition to the bilateral method allowed under the Law of Electricity Concessions, Law 28,832 has also established the possibility that distributors may meet their unregulated or regulated customers’ demand under contracts signed following a capacity and energy supply tender process.

Sales of Capacity to Other Generation Companies

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

A generation company may be required to purchase or sell capacity in the spot market, depending upon its contractual requirements in relation to the amount of electricity to be dispatched from such company and to its firm capacity.

Regulatory Charges

In addition to taxes applicable to all industries (mainly an income tax and a value added tax), the electricity industry operators are subject to a special regulation contribution that compensates the costs incurred by the state in connection with the regulation, supervision and monitoring of the electricity industry. The applicable rate for this contribution is up to 1% of the annual billing of each company and the funds levied are distributed proportionally to the MINEM and Osinergmin.

Generators that also have hydroelectric plants pay a water royalty as a function of the hydroelectric energy produced and the regulated energy tariff at peak hours.

Tenders Promoted by the State

During 2009, MINEM carried out several studies which concluded that there will be lack of power generation capacity in the system, in the near future. MINEM recommended the construction of new power plants that would serve as backup in order to guarantee the flow of electricity to the system and avoid blackouts. As a result, PROINVERSIÓN carried out a public bid in August 2010, seeking to secure investments for three projects located in Talara, Trujillo and Ilo that will add another 800 MW to the system. The bid resulted in only two of the projects being awarded: Talara (200 MW, for EEPSA, now an Enersis subsidiary) and Ilo (400 MW, for Enersur, an unrelated company). These plants will receive regular payments for being permanently available to operate and provide energy to the SEIN whenever the COES calls on them and will also be reimbursed for the fuel costs incurred for generating electricity. The Trujillo generation facility was later substituted by the Eten generation facility, and awarded to Planta de Reserva Fría de Generación de Eten S.A. (200 MW) (the “Cold Reserve Project”).

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An international tender was held in 2012 for the concession for the Cold Reserve Project for the Pucallpa (Ucayali) and Puerto Maldonado (Madre de Dios) plants, which were awarded to Consorcio Energía Perú S.A. The term for the construction of the plants will be 30 months from the signing of the contracts and the concession covers a period of 20 years plus the construction period. The Pucallpa thermal plant will require an investment of around US$ 31.5 million and will have a capacity between 35 and 40 MW, covering 80% of the energy demand. The Puerto Maldonado thermal plant will require an investment of around US$ 18.5 million, will have a capacity between 15 and 18 MW, covering 100% of the energy demand.

PROINVERSIÓN established February 28, 2013 as the date to submit offers for the international public tender that is intended to promote private investments for the Hydroelectric Plants project (CH Molloco—310 MW), which is located in the hills of the Arequipa region.

Services provided by generation, transmission, and distribution companies have to comply with technical standards stated in the Technical Regulations on the Quality of the Electric Supply. Failure to do so might result in the imposition of fines by Osinergmin.

Generators receive a capacity payment whose main component is the annuity of a peak-load plant. However, to be eligible to obtain this charge, plants have to be part of the reserve margin established annually by Osinergmin. The capacity ranking is constructed in base of firm power of every power plant connected to the system and their relative efficiency (ordered by variable costs). Only those plants that appear in the ranking as required to cover the peak demand plus the reserve margin obtain capacity payment. Every year, Osinergmin sets the power price that shall be assigned and paid to each generator pursuant to this concept.

Electricity Exports and Imports

A 220 kV transmission line has been implemented for the interconnection with Ecuador, with a limited capacity of 160 MW. However, the line has not operated continuously because of regulatory issues. During June and August 2011, Peru imported energy from Ecuador due to the lack of generation in northern Peru and transmission problems to that zone in the SEIN. In 2012, Peru imported 4.5 GWh of electricity from Ecuador due to the maintenance of the Talara Zorritos line (3.9 GWh in February 2012) and the TGN4 Malacas power plant (0.6 GWh in March 2012). All of the exports to Ecuador totaling 5.5 GWh occurred in August and September 2012 (1.9 GWh and 3.6 GWh, respectively.)

Internal regulations were also approved for the application of Decision 757 of the Andean Community of Nations (“CAN” in its Spanish acronym), which establishes that when bilateral electricity transactions are carried out with other countries of the CAN, the Economic Operation Committee of the SEIN should send to the MINEM and to Osinergmin weekly reports showing that priority has been given to supplying the domestic market (Supreme Decree 011-2012-EM).

In addition to the interconnection with Ecuador, the governments of Peru and Brazil in 2010 signed the “Agreement between the Republic of Peru and the Federal Republic of Brazil for the supply of electricity to Peru and export of surpluses to Brazil,” with the main purpose of exploiting Peruvian hydroelectric resources in the Amazon basin. In January 2012, Peru created a commission to handle the aspects contemplated in that agreement. The general framework establishes that the accumulated capacity of the generation plants that can be committed to export to Brazil is a maximum of 7,200 MW and dispatch will have the following order of priority: (i) the Peruvian regulated market, (ii) the Peruvian unregulated market, and lastly, (iii) the Brazilian market. As of the date of this Report, the process is on hold, and is expected to be approved by the Peruvian Congress that currently is under the study of the Commission of Andean, Amazonian and Afro-Peruvian Peoples, Environment and Ecology.

The governments of Peru and Chile have established a bilateral working group to discuss energy matters. The purpose of the working group is to identify and take advantage of the potential synergies between the two countries. The first few meetings of this group took place in 2011. At the request of the presidents of both nations, the working

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group is expected to propose a framework for an agreement in connection with both countries’ electricity integration that would establish the general rules for energy exchanges between them. As of the date of this Report, both countries have conducted negotiations but a final agreement is still pending.

Regulation in Transmission

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

Environmental Regulation

The environmental legal framework applicable to energy related activities in Peru is set forth in the Environmental Law (Law 28,611/2005) and in the Regulation for Environmental Protection regarding Electricity Activities (Supreme Decree 029-94-EM). The MINEM dictates the specific environmental legal dispositions applicable to electricity activities, and Osinergmin is in charge of supervising certain aspects of their application and implementation. According to the Environmental Law, the Peruvian Ministry of Environment has the principal duties of (i) designing the general environmental policies to every productive activity; and (ii) establishing the main guidelines of the different government authorities for their specific environmental sector regulations. During 2010, most supervision functions regarding the application and implementation of the Environmental Law’s dispositions were transferred from Osinergmin to the Peruvian Ministry of the Environment.

Renewable Energy Resources (“RER”) for electricity generation are considered to be from biomass, wind, solar, geothermal and tidal sources, plus hydroelectric plants whose installed capacity does not exceed 20 MW.

In 2008, the authority issued regulations to promote the use of RER. The principal investment incentives established by these regulations are (i) an obj