Enel Americas 20F/A 2015 Annual report (foreign) (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F/A

(Amendment No. 1)

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

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

For the fiscal year ended December 31, 2015

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

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

Date of event requiring this shell company report,

For the transition period from to

Commission file number: 001-12440

ENERSIS AMÉRICAS S.A.

(Exact name of Registrant as specified in its charter)

ENERSIS AMÉRICAS S.A.

(Translation of Registrant’s name into English)

CHILE

(Jurisdiction of incorporation or organization)

Santa Rosa 76, Santiago, Chile

(Address of principal executive offices)

Javier Galán, phone: (56-2) 2353-4510, jg@enersis.cl, Santa Rosa 76, Piso 15, Santiago, Chile

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

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


Title of Each Class		Name of Each Exchange on Which Registered
American Depositary Shares representing Common Stock		New York Stock Exchange
Common Stock, no par value*		New York Stock Exchange
US$ 249,734,000 7.40% Notes due December 1, 2016		New York Stock Exchange
US$ 858,000 6.60% Notes due December 1, 2026		New York Stock Exchange

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

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

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

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report Shares of Common Stock: 49,092,772,762

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ Yes ¨ No

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ¨

International Financial Reporting Standards as issued

by the International Accounting Standards Board x

Other ¨

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

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

EXPLANATORY NOTE

Enersis Américas S.A. (“Enersis Américas” or the “Company”) is filing this Amendment No. 1 to its Annual Report on Form 20-F for the fiscal year ended December 31, 2015, as filed with the U.S. Securities and Exchange Commission (the “SEC”) on May 2, 2016 (the “Original Form 20-F”) to amend the following items of the Original Form 20-F: (1) Item 4. Information on the Company, to clarify which generation and transmission companies were consolidated by the Company as of December 31, 2015, (2) Item 5. Operating and Financial Review and Prospects, to discuss the reasons for fluctuations in the effective tax rates related to each country in which the Company operates and to quantify the impact of each country on the Company’s overall effective tax rate and to add disclosure regarding financing risks in Brazil, (3) Item 18. Financial Statements, to revise the audit report of KPMG Auditores Consultores Ltda. as well as to revise, among other things, the disclosure in the notes to the financial statements regarding impairment of non-financial assets, cash and cash equivalents, trade and other receivables, and sanctions, and to delete Appendix 4, renumber former Appendices 5, 6, 7.2 and 8, and update and renumber former Appendices 7 and 7.1, and (4) Item 19. Exhibits, to update the exhibit index. In addition, the Company has also generally updated the Original Form 20-F to revise references to the “generation business” to refer to the “generation and transmission business”.

This Form 20-F/A sets forth the Original Form 20-F in its entirety and reflects the additions and changes described above. Except for the amendments described above, the updated certifications of the Company’s Chief Executive Officer and Chief Financial Officer and the consents of the independent registered public accounting firms, this Amendment No. 1 does not modify or update other disclosures in or exhibits to the Original Form20-F, which as amended by this Amendment No. 1, speaks as of May 2, 2016 and is not intended to reflect events that may have occurred subsequent to the initial filing date of the Original Form 20-F.

Enersis Américas’ Organizational Structure⁽¹⁾

As of December 31, 2015 (assuming the spin-off of Enersis Chile S.A. had occurred as of such date)

LOGO

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

TABLE OF CONTENTS


		Page
Glossary			5

Introduction			10

Financial Information			11

Technical Terms			12

Calculation of Economic Interest			12

Forward-Looking Statements			13

PART I

Item 1.	Identity of Directors, Senior Management and Advisers		14

Item 2.	Offer Statistics and Expected Timetable		14

Item 3.	Key Information		14

Item 4.	Information on the Company		30

Item 4A.	Unresolved Staff Comments		118

Item 5.	Operating and Financial Review and Prospects		119

Item 6.	Directors, Senior Management and Employees		171

Item 7.	Major Shareholders and Related Party Transactions		185

Item 8.	Financial Information		187

Item 9.	The Offer and Listing		189

Item 10.	Additional Information		191

Item 11.	Quantitative and Qualitative Disclosures About Market Risk		209

Item 12.	Description of Securities Other Than Equity Securities		213

PART II

Item 13.	Defaults, Dividend Arrearages and Delinquencies		215

Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds		215

Item 15.	Controls and Procedures		215

Item 16.	Reserved		216

Item 16A.	Audit Committee Financial Expert		216

Item 16B.	Code of Ethics		216

Item 16C.	Principal Accountant Fees and Services		217

Item 16D.	Exemptions from the Listing Standards for Audit Committees		218

Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		218

Item 16F.	Change in Registrant’s Certifying Accountant		218

Item 16G.	Corporate Governance		218

Item 16H.	Mine Safety Disclosure		218

PART III

Item 17.	Financial Statements		219

Item 18.	Financial Statements		219

Item 19.	Exhibits		219

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 Enel Brasil, our subsidiary.

ANEEL	Agência Nacional de Energia Elétrica	Brazilian governmental agency for electric energy.

BNDES	Banco Nacional de Desarrollo Económico y Social	The National Bank for Economic and Social Development (“BNDES”) is the principal agent of development in Brazil with a focus on sustainable social and environmental development.

Cachoeira Dourada	Centrais Elétricas Cachoeira Dourada S.A.	Brazilian generation company owned by Enel Brasil, our subsidiary.

CAMMESA	Compañía Administradora del Mercado Mayorista Eléctrico S.A.	Argentine autonomous entity in charge of the operation of theMercado Eléctrico Mayorista (Wholesale Electricity Market), or MEM. CAMMESA’s stockholders are generation, transmission and distribution companies, large users and the Secretariat of Energy.

Cemsa	Central Comercializadora de Energía S.A.	Energy trading company with operations in Argentina, and our subsidiary.

Chilean Stock Exchanges	Chilean Stock Exchanges	The three principal stock exchanges located within Chile: the Santiago Stock Exchange, the Electronic Stock Exchange and the Valparaíso Stock Exchange.

Chilectra Américas	Chilectra Américas S.A.	Electricity distribution company holding minority interests in electricity distribution companies in Argentina, Brazil, Colombia and Peru, and our subsidiary.

Chilectra Chile	Chilectra S.A.	Chilean electricity distribution company operating in the Santiago metropolitan area and a combined entity of Enersis Chile.

CIEN	Companhia de Interconexão Energética S.A.	Brazilian transmission company, wholly-owned by Enel Brasil, our subsidiary.


Codensa	Codensa S.A. E.S.P.	Colombian distribution company that operates mainly in Bogotá and controlled by us.

Coelce	Companhia Energética do Ceará S.A.	A publicly held Brazilian distribution company operating in the state of Ceará. Coelce is controlled by Enel Brasil, our subsidiary.

COES	Comité de Operación Económica del Sistema	Peruvian entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand.

Costanera	Central Costanera S.A.	A publicly held Argentine generation company controlled by Endesa Américas. Formerly known as Endesa Costanera.

CREG	Comisión de Regulación de Energía y Gas	Colombian Commission for the Regulation of Energy and Gas.

CTM	Compañía de Transmisión del Mercosur S.A.	Argentine transmission company and subsidiary of Enel Brasil.

DCV	Depósito Central de Valores S.A.	Chilean Central Securities Depositary.

DECSA	Distribuidora Eléctrica de Cundinamarca S.A.	Colombian distribution company and a subsidiary of Codensa.

Dock Sud	Central Dock Sud S.A.	Argentine generation company and our subsidiary.

Edegel	Edegel S.A.A.	A publicly held Peruvian generation company and a combined entity of Endesa Américas.

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 our subsidiary.

Edesur	Empresa Distribuidora Sur S.A.	Argentine distribution company, with a concession area in the south of the Buenos Aires greater metropolitan area, and our subsidiary.

EEB	Empresa de Energía de Bogotá S.A.	Colombian stated-owned financial and energy holding company, with investments in the electricity generation, transmission, trading and distribution sectors and in the natural gas transmission, distribution and trading sectors.

EEC	Empresa de Energía de Cundinamarca S.A. E.S.P.	Colombian distribution company and a subsidiary of DECSA, in which we hold 19.5% interest.


EEPSA	Empresa Eléctrica de Piura S.A.	A publicly held Peruvian generation company with natural gas thermal plants, and our subsidiary.

El Chocón	Hidroeléctrica El Chocón S.A.	Argentine generation company with two hydroelectric plants, El Chocón and Arroyito, both located in the Limay River, Argentina and a combined entity of Endesa Américas.

Emgesa	Emgesa S.A. E.S.P.	Colombian generation company controlled by Endesa Américas.

Endesa Américas	Endesa Américas S.A.	A limited liability stock corporation incorporated under the laws of the Republic of Chile, with electricity generation operations in Argentina, Colombia and Peru. Our subsidiary.

Endesa Chile	Empresa Nacional de Electricidad S.A.	A publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, with electricity generation assets in Chile, and a combined entity of Enersis Chile.

Enel	Enel S.p.A.	An Italian energy company with multinational operations in the power and gas markets. A 60.6% beneficial owner of us and our ultimate parent company.

Enel Brasil	Enel Brasil S.A.	Brazilian holding company and our subsidiary. Enel Brasil was formerly known as Endesa Brasil S.A.

Enel Iberoamérica	Enel Iberoamérica, S.R.L.	A wholly-owned subsidiary of Enel and owner of 20.3% of us, which it acquired from Endesa Spain in October 2014. Enel Iberoamérica was formerly known as Enel Energy Europe S.R.L.

Enel Latinoamérica	Enel Latinoamérica, S.A.	A wholly-owned subsidiary of Enel Iberoamérica and owner of 40.3% of us.

Enersis Américas	Enersis Américas S.A.	Our company, a publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, with subsidiaries engaged primarily in the generation, transmission and distribution of electricity in Argentina, Brazil, Colombia, and Peru. Registrant of this Report.



Enersis Chile	Enersis Chile S.A.	A publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, which holds combined entities engaged primarily in the generation and distribution of electricity in Chile controlled by Enel.

ENRE	Ente Nacional Regulador de la Electricidad	Argentine national regulatory authority for the energy sector.

ESM	Extraordinary Shareholders’ Meeting	Extraordinary Shareholders’ Meeting.

FONINVEMEM	Fondo para Inversiones Necesarias que permitan Incrementar la Oferta de Energía Eléctrica en el Mercado Eléctrico Mayorista	Argentine fund created to increase electricity supply in the MEM.

Fortaleza	Central Geradora Termelétrica Fortaleza S.A.	Brazilian generation company that operates in the state of Ceará. Fortaleza is wholly-owned by Enel Brasil, our subsidiary.

Gener	AES Gener S.A.	Chilean generation company that competes with the Company in Argentina and Colombia.

IFRS	International Financial Reporting Standards	International Financial Reporting Standards as issued by the International Accounting Standards Board (IASB).

LNG	Liquefied Natural Gas.	Liquefied natural gas.

MEM	Mercado Eléctrico Mayorista	Wholesale Electricity Market in Argentina, Colombia, and Peru.

MME	Ministério de Minas e Energia	Brazilian Ministry of Mines and Energy.

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 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.

SVS	Superintendencia de Valores y Seguros	Chilean Superintendence of Securities and Insurance, the authority that supervises public companies, securities and the insurance business.

TESA	Transportadora de Energía S.A.	Transmission company with operations in Argentina and a subsidiary of Enel Brasil.

UF	Unidad de Fomento	Chilean inflation-indexed, Chilean peso-denominated monetary unit.

UTA	Unidad Tributaria Anual	Chilean annual tax unit. One UTA equals 12Unidad Tributaria Mensual (“UTM”), which is a Chilean inflation-indexed monthly tax unit used to define fines, among other purposes.

VAD	Valor Agregado de Distribución	Value added from distribution of electricity.

XM	Expertos de Mercado S.A. E.S.P.	A subsidiary of Interconexión Eléctrica S.A. (“ISA”), a Colombian company that provides system management in real time services in electrical, financial and transportation sectors.

INTRODUCTION

As used in this Report on Form 20-F (“Report”), first person personal pronouns such as “we”, “us” or “our” refer to Enersis Américas S.A. (“Enersis Américas” or the “Company”) and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries, and jointly-controlled companies and associates is expressed in terms of our economic interest as of December 31, 2015.

We are a Chilean company engaged through our subsidiaries and jointly-controlled companies in the electricity generation, transmission and distribution businesses in Argentina, Brazil, Colombia, and Peru. As of the date of this Report, we own 60.0% of Endesa Américas S.A. (“Endesa Américas”), a Chilean electricity generation company that holds electricity generation operations in Argentina, Colombia and Peru, minority interests in generation, distribution and transmission operations in Brazil, and 99.1% of Chilectra Américas S.A. (“Chilectra Américas”), a Chilean electricity distribution company that holds minority interests in distribution companies in Argentina, Brazil, Colombia and Peru. As of the date of this Report, Enel S.p.A. (“Enel”), an Italian energy company with multinational operations in the power and gas markets, beneficially owns 60.6% of us and our ultimate parent.

On April 21, 2016, (i) we completed the spin-off of Enersis Chile, (ii) Endesa Chile completed the spin-off of Endesa Americas and (iii) Chilectra completed the spin-off of Chilectra Americas. As a result of these transactions, we acquired our 60.0% interest in Endesa Americas and 99.1% interest in Chilectra Americas. The respective spin-offs were effected by means of a division or “demerger” under Chilean law of each of Enersis Américas, Endesa Chile and Chilectra effective as of March 1, 2016, which created Enersis Chile, Endesa Américas and Chilectra Américas, respectively. These spin-offs were followed by the distribution on April 21, 2016 of the shares of Enersis Chile, Endesa Américas and Chilectra Américas and on April 26, 2016 of the ADRs of Enersis Chile and Endesa Américas. Each of Enersis Chile, Endesa Chile and Chilectra continues to own the Chilean assets it owned prior to the respective spin-offs. Enersis Chile owns 60.0% of Endesa Chile and 99.1% of Chilectra. We do not hold any remaining interest in Enersis Chile, Endesa Chile or Chilectra, which collectively hold the Chilean assets owned by us prior to the spin-offs.

We have announced a plan for a merger of Endesa Americas and Chilectra Americas with us (the “Merger”) and for a related tender offer by us for shares of Endesa Americas (the “Tender Offer”). It is expected that the Merger and Tender Offer will be consummated in the third quarter of 2016, subject to satisfaction of the conditions to such transactions. All of the transactions referred to above collectively are referred to as the “Reorganization.” The purpose of the spin-offs and the Reorganization is to separate our generation, transmission and distribution businesses in Chile from the generation, transmission and distribution businesses in Argentina, Brazil, Colombia and Peru. The purpose of the Merger is to combine our non-Chilean generation, transmission and distribution businesses under a single holding company, to reduce inefficiencies and create more liquidity for our shareholders.

PRESENTATION OF INFORMATION

Financial Information

In this Report, unless otherwise specified, references to “U.S. dollars,” “US$,” are to dollars of the United States of America; references to “pesos” or “Ch$” 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 Soles, 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 UF is a Chilean inflation-indexed, peso-denominated monetary unit that is adjusted daily to reflect changes in the official Consumer Price Index (“CPI”) of the Chilean National Institute of Statistics (Instituto Nacional de Estadísticasor “INE”). The UF is adjusted in monthly cycles. Each day in the period beginning on the tenth day of the current month through the ninth day of the succeeding month, the nominal peso value of the UF is indexed in order to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month. As of December 31, 2015, one UF was equivalent to Ch$ 25,629.09. The U.S. dollar equivalent of one UF was US$ 36.09 as of December 31, 2015, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2015 of Ch$ 710.16 per US$ 1.00. The U.S. dollar observed exchange rate (dólar observado) (the “Observed Exchange Rate”), which is reported by the Central Bank of Chile and published daily on its webpage, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market

The Central Bank of Chile may intervene by buying or selling foreign currency on the Formal Exchange Market to maintain the Observed Exchange Rate within a desired range.

As of March 31, 2016, one UF was equivalent to Ch$ 25,812.05. The U.S. dollar equivalent of one UF was US$ 38.54 on March 31, 2016, using the Observed Exchange Rate reported by the Central Bank of Chile as of such date of Ch$ 669.80 per US$ 1.00.

Our consolidated financial statements and, unless otherwise indicated, other financial information concerning us included in this Report are presented in Chilean pesos. We have prepared our consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).

All of our subsidiaries are integrated and all their assets, liabilities, income, expenses and cash flows are included in the consolidated financial statements after making the adjustments and eliminations related to intra-group transactions. Investments in associated companies over which we exercise significant influence are included in our consolidated financial statements using the equity method. For detailed information regarding consolidated entities, jointly-controlled entities and associated companies, see Appendices 1, 2 and 3 to the consolidated financial statements.

Since the conditions established under IFRS were met by December 31, 2015, in the financial statements included in this Report, all operations regarding the former Chilean businesses have been presented as discontinued operations.

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, 2015, as defined in “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”. The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. No representation is made that the Chilean peso or U.S. dollar amounts shown in this Report could have been or could be converted into U.S. dollars or Chilean pesos, as the case may be, at such rate or at any other rate. See “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”.

Technical Terms

References to “TW” are to terawatts; 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. References to “BTU” and “MBTU” are to British thermal unit and million British thermal units, respectively. A “BTU” is an energy unit equal to approximately 1,055 joules. References to “Hz” are to hertz; and references to “mtpa” are to metric tons per annum. Unless otherwise indicated, statistics provided in this Report with respect to the installed capacity of electricity generation facilities are expressed in MW. One TW equals 1,000 GW, one GW equals 1,000 MW and one MW equals 1,000 kW.

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

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

Energy losses during distribution are calculated as the difference between total energy purchased (GWh of electricity demand, including own generation) and the energy sold (also measured in GWh), within a given period. Distribution losses are expressed as a percentage of total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical losses.

Calculation of Economic Interest

References are made in this Report to the “economic interest” of Enersis Américas 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%.

Rounding

Certain figures included in our consolidated financial statements have been rounded for ease of presentation. Percentages expressed in this Report may not have been calculated using rounded figures, but by using amounts prior to rounding. For this reason, percentages expressed in this Report may vary from those obtained by performing the same calculations using figures in our consolidated financial statements. Certain other amounts that appear in the tables in this Report may not total exactly due to rounding.

FORWARD-LOOKING STATEMENTS

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

•

our capital investment program;

•

trends affecting our financial condition or results from operations;

•

our dividend policy;

•

the future impact of competition and regulation;

•

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

•

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

•

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

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

•

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 registered public accounting firm has not examined or compiled the forward-looking statements and, accordingly, does not provide any assurance with respect to such statements. You should consider these cautionary statements together with any written or oral forward-looking statements that we may issue in the future. We do not undertake any obligation to release publicly any revisions to forward-looking statements contained in this Report to reflect later events or circumstances or to reflect the occurrence of unanticipated events.

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.

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 consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2015 and 2014 and for each of the years in the three-year period ended December 31, 2015 is derived from our audited consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2013 is derived from our consolidated financial statements included in this Report. Since January 1, 2009, our consolidated financial statements were prepared in accordance with IFRS, as issued by the IASB.

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, 2015, has been converted at the U.S. dollar Observed Exchange Rate (dólar observado) for that date of Ch$ 710.16 per US$ 1.00. The Observed Exchange Rate, which is reported and published daily on the Central Bank of Chile’s web page, corresponds to the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market.

For more information concerning historical exchange rates, see “ — Exchange Rates” below.

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


	As of and for the year ended December 31,
	2015⁽¹⁾			2015			2014			2013⁽²⁾
	(US$ millions)						(Ch$ millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income		7,465			5,301,440			5,206,370			4,528,148
Operating expenses⁽³⁾		(5,698	)		(4,046,682	)		(3,818,370	)		(3,177,080	)
Operating income		1,767			1,254,758			(1,388,000	)		1,351,068
Financial income (expense), net		40			28,287			(213,316	)		(118,899	)
Total gain (loss) on sale of non-current assets not held for sale		(9	)		(6,566	)		877			4,642
Other non-operating income		5			3,333			2,560			980

Income before income tax		1,802			1,279,812			1,178,121			1,237,791
Income tax expenses, continuing operations		(737	)		(523,663	)		(425,958	)		(442,455	)
Income after tax from discontinued operations		547			388,321			215,332			318,065
Income after tax from continuing operations		1,065			756,149			752,163			795,336

Net income		1,612			1,144,470			967,495			1,113,401
Net income attributable to shareholders of the Company		932			661,587			571,873			658,514

Net income attributable to Minority interests		680			482,883			395,622			454,887
Net income (loss) from continuing operations per average number of shares basic and diluted (Ch$/US$)		0.01			8.35			8.344			9.49
Net income (loss) from continuing operations per average number of ADS (Ch$/US$)		0.59			417,50			417.00			474.50
Net income (loss) from discontinued operations per average number of shares basic and diluted (Ch$/US$)		0.01			5.13			3.31			5.08
Net income (loss) from discontinued operations per average number of ADSs (Ch$/US$)		0.36			256.50			165.50			254.00
Net income (loss) per average number of shares, basic and diluted (Ch$/US$ per share)		0.01			8.35			8.34			9.49
Net income (loss) per average number of ADSs (Ch$/US$ per ADS)		0.59			417.50			417.00			474.50
Cash dividends per share (Ch$/US$ per share)		0.01			6.21			6.71			4.25
Cash dividends per ADS (Ch$/US$ per ADS)		0.44			310.72			335.34			212.51
Weighted average number of shares of common stock (millions)					49,093			49,093			45,219
Number of ADS (millions)⁽⁴⁾					99.69			102.65			105,20

Consolidated Statement of Financial Position Data
Total assets		21,754			15,449,154			15,921,322			15,177,664
Non-current liabilities		3,878			2,753,965			4,447,282			3,688,940
Equity attributable to shareholders		8,486			6,026,149			6,201,976			6,168,554
Equity attributable to Minority interests		3,047			2,163,659			2,077,243			2,338,911
Total equity		11,532			8,189,808			8,279,219			8,507,464
Capital stock⁽⁵⁾		8,173			5,804,448			5,804,448			5,828,040

Other Consolidated Financial Data
Capital expenditures (CAPEX)⁽⁶⁾		1,919			1,362,561			1,089,362			774,820
Depreciation, amortization and impairment losses⁽⁷⁾		507			360,354			389,073			382,631

(1)	Solely for the convenience of the reader, Chilean peso amounts have been converted into U.S. dollars at the exchange rate of Ch$ 710.16 per U.S. dollar, as of December 31, 2015.

(2)	Restated as a result of the application of IFRS 11.

(3)	Operating expenses include selling and administration expense.

(4)	As of December 31 of each year.

(5)	Includes share premium.

(6)	CAPEX figures represent effective payments for each year.

(7)	For further detail please refer to Note 30 of the Notes to our consolidated financial statements.


	As of and for the year ended December 31,
	2015			2014			2013			2012			2011
OPERATING DATA OF SUBSIDIARIES

Edesur (Argentina)
Electricity sold (GWh)⁽¹⁾		18,492			17,972			18,110			17,710			17,210
Number of customers (thousands)		2,480			2,464			2,444			2,389			2,389
Total energy losses (%)⁽²⁾		12.3	%		10.8	%		10.8	%		10.6	%		10.5	%

Ampla (Brazil)
Electricity sold (GWh)⁽¹⁾		11,547			11,678			11,025			10,793			10,202
Number of customers (thousands)		2,997			2,875			2,801			2,712			2,644
Total energy losses (%)⁽²⁾		20.9	%		20.1	%		19.8	%		19.6	%		19.7	%

Coelce (Brazil)
Electricity sold (GWh)⁽¹⁾		11,229			11,165			10,705			9,865			8,958
Number of customers (thousands)		3,758			3,625			3,500			3,338			3,224
Total energy losses (%)⁽²⁾		13.7	%		12.7	%		12.5	%		12.6	%		11.9	%

Codensa (Colombia)
Electricity sold (GWh)⁽¹⁾		13,946			13,660			13,332			12,958			12,552
Number of customers (thousands)		2,865			2,772			2,687			2,588			2,496
Total energy losses (%)⁽²⁾		7.3	%		7.2	%		7.0	%		7.3	%		7.8	%

Edelnor (Peru)
Electricity sold (GWh)⁽¹⁾		7,624			7,338			7,030			6,850			6,560
Number of customers (thousands)		1,337			1,293			1,255			1,203			1,144
Total energy losses (%)⁽²⁾		8.3	%		8.0	%		8.0	%		8.2	%		8.2	%

Endesa Américas
Installed capacity in Argentina (MW)⁽³⁾⁽⁴⁾		3,632			3,632			3,632			3,632			3,632
Installed capacity in Colombia (MW)⁽⁵⁾		3,459			3,059			2,925			2,914			2,914
Installed capacity in Peru (MW)⁽⁶⁾		1,686			1,652			1,540			1,657			1,668
Generation in Argentina (GWh)⁽³⁾⁽⁷⁾		11,405			9,604			10,840			11,207			10,713
Generation in Colombia (GWh)⁽⁵⁾⁷⁾		13,705			13,559			12,748			13,251			12,051
Generation in Peru (GWh)⁽⁶⁾⁽⁷⁾		8,218			8,609			8,391			8,570			8,980

Enel Brasil (Brazil)⁽⁷⁾
Installed capacity in Brazil (MW)		987			987			987			987			987
Generation in Brazil (GWh)⁽³⁾		4,398			5,225			4,992			5,183			4,129

Dock Sud (Argentina)⁽³⁾
Installed capacity in Argentina (MW)		870			870			870			n.a			n.a.
Generation in Argentina (GWh)		3,799			4,786			3,582			n.a			n.a.

EEPSA (Peru)⁽³⁾⁽⁶⁾
Installed capacity in Peru (MW)		298			297			302			n.a			n.a.
Generation in Peru (GWh)		583			453			98			n.a			n.a.

(1)	Electricity sales may be different than reported in previous periods because currently sales do not reflect non-billable consumption.

(2)	Energy losses are calculated as the difference between total energy generated, and purchased (GWh) and the energy sold (GWh), within a given period. Losses are expressed as a percentage of total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical losses.

(3)	As a result of the 2013 capital increase described under “Item 4. Information on the Company – A. History and Development of the Company – History”, Dock Sud in Argentina and EEPSA in Peru were contributed

by Endesa Spain and their consolidation by Enersis began as of April 2013; therefore, 2013 data only includes the nine-month period from April 1, 2013 to December 31, 2013.

(4)	Values from 2011 to 2015 were modified and correspond to values reported to CAMMESA (Argentina TSO).

(5)	El Quimbo entered commercial operation during 2015, adding 400 MW of capacity.

(6)	In Peru, the Santa Rosa TG 7 unit was recommissioned in December 2014, and during 2015 there were capacity adjustments and upgrades to existing plants, totaling an additional 33 MW. Mainly, Huinco with 20 (MW), Santa Rosa with 6 (MW) and Callahuanca with 4 MW.

(7)	Beginning in 2013, we changed how we calculate our electricity generation. The impact of applying the new criteria on a cumulative basis for 2011 and 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 affect the price of our American Depositary Shares (“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 that must be carried out through the Formal Exchange Market.

The U.S. dollar 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, 2015, the U.S. dollar Observed Exchange Rate was Ch$ 710.16 per US$ 1.00.

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


	Daily Observed Exchange Rate (Ch$ per US$)⁽¹⁾
	Low⁽²⁾		High⁽²⁾		Average⁽³⁾		Period-end
Year ended December 31,
2015		597.10		715.66		654.66		710.16
2014		527.53		621.41		573.70		606.75
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
Month ended
March 2016		669.80		694.82		n.a.		669.80
February 2016		689.18		715.41		n.a.		694.17
January 2016		710.37		730.31		n.a.		710.37
December 2015		693.72		711.52		n.a.		710.16
November 2015		688.94		715.66		n.a.		711.20
October 2015		673.91		695.53		n.a.		690.32

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 April 28, 2016, the U.S. dollar Observed Exchange Rate was Ch$ 663.40 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 devaluation of the year-end Chilean peso in 2015, one determines the percent change between the reciprocal of Ch$ 606.75, the value of one U.S. dollar as of December 31, 2014, or 0.001648, and the reciprocal of Ch$ 710.16, the value of one U.S. dollar as of December 31, 2015, or 0.001408. In this example, the percentage change between the two periods is negative 14.6%, which represents the 2015 year-end devaluation of the Chilean peso against the 2014 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, 2011 through December 31, 2015, based on information published by the Central Bank of Chile.


	Ch$ per US$⁽¹⁾
	Period End		Appreciation (Devaluation)
	(in Ch$)		(in %)
Year ended December 31,
2015		710.16		(14.6)
2014		606.75		(13.5)
2013		524.61		(8.5)
2012		479.96		8.2
2011		519.20		(9.9)

Source: Central Bank of Chile.

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

B.	Capitalization and Indebtedness.

Not applicable.

C.	Reasons for the Offer and Use of Proceeds.

Not applicable.

D.	Risk Factors.

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

The four countries in which we have electricity investments 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 and that some of our customers may experience difficulties paying their electric bills, possibly increasing our uncollectible accounts. Any of these situations could adversely affect our results of operations and financial condition.

Financial and political crises in other parts of the world could also adversely affect our business. For example, instability in the Middle East or in other oil producing regions could result in higher fuel prices worldwide, which in turn could increase the cost of fuel for our thermal generation plants and adversely affect our results of operations and financial condition.

In addition, an international financial crisis and its disruptive effects on the financial industry could adversely impact our ability to obtain new bank financings on the same historical terms and conditions. A financial crisis could also diminish our ability to access the capital markets in the four countries in which we operate as well as the international capital markets for other sources of liquidity, or increase the interest rates available to us. Reduced liquidity could, in turn, adversely affect our capital expenditures, our long-term investments and acquisitions, our growth prospects and our dividend payout policy.

South American economic fluctuations may affect our results of operations and financial condition as well as the value of our securities.

All of our operations are located in four 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 four 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 and Brazil. In Brazil, during 2015, some instability arose from the political sector due to corruption scandals involving several government officials, which has led to a deterioration of the perception of the Brazilian market, which in turn has led Brazil to lose its investment grade rating from Standard & Poor’s and Fitch Ratings. In 2015, 63% of our operating revenues and 67% of our operating income came from Brazil and Colombia.

Insufficient cash flows for our subsidiaries located in these volatile countries, have, in some cases, resulted in their inability to meet debt obligations and the need to seek waivers to comply with some debt covenants, or, to a limited extent, to require guarantees or other emergency measures from us, including extraordinary capital increases.

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

In addition, South American financial and securities markets are, to varying degrees, influenced by economic and market conditions in other countries. Brazilian, Chilean and Colombian financial and securities markets may be adversely affected by events in other countries, which could adversely affect the value of our securities.

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

The Argentine peso suffered a steep devaluation against the U.S. dollar during 2014, which has continued during 2015. Due to the decline in value of the Argentine peso relative to foreign currencies, the Argentine government has implemented policies to limit purchases of U.S. dollars. In 2014, the Argentine Central Bank raised the reference interest rate, which increased financing costs for banks and for private sector companies and it has been intervening in the market on a daily basis during 2015 in order to control further devaluation expectations. Although the pace of the devaluation of the Argentine peso against the U.S. dollar has slowed recently, the increase in interest paid on deposits has been insufficient to offset the inflation rate. The new government recently liberalized all currency restrictions imposed by the prior government, which resulted in the immediate devaluation of the Argentinean peso by more than 35% in one day. While the new government is expected to take actions to soften the impact of the one-time effect of devaluation, the devaluation of the Argentine peso may continue in 2016 and future years.

If Argentina’s economy were deemed hyperinflationary, a general price index would be used to present the amounts related to our Argentine subsidiaries in our consolidated financial statements under the provisions outlined in IAS 29, “Financial Reporting in Hyperinflationary Economies.” Amounts for the previous reporting periods would be restated by applying the general price index so that the financial statements between the periods presented would be comparative.

In 2014, the Argentine banking industry increased interest rates on loans and shortened maturities. Liquidity in the Argentine derivatives market also deteriorated, which limited access to swaps of Argentine peso denominated debt into other currencies. As a result our Argentine peso-denominated debt is exposed to further devaluation of the Argentine peso.

Argentina’s sovereign creditworthiness seriously deteriorated in 2014, based on market data and reports from credit ratings agencies and such situation has worsened during 2015. Argentina’s sovereign debt rating maintained its “selective default” rating by Standard & Poor’s and “restricted default” rating by Fitch, both ratings as a result of a default on Argentina’s sovereign bonds in July 2014. Moody’s maintained the long term foreign currency debt rating at “Caa1,” updated in November 2015 with positive outlook. Further deterioration of Argentina’s economy could adversely affect our results of operations and financial condition. For further information on our consolidated financial statements by segments, please see Note 35 of the Notes to our consolidated financial statements.

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. Even though we do not have assets in Chile, we are a company established under the laws of the Republic of Chile. Therefore, taxes will be paid in Chile and we will be subject to changes in Chilean tax laws. To a lesser extent, the Chilean government continues to exercise substantial influence over many aspects of the private sector, which may result in changes to economic or other policies. For example, in September 2014, the Chilean government approved the progressive increase of the corporate income tax and a change in the tax system, which may have an additional negative effect upon non-Chilean holders of shares or ADSs. On February 8, 2016, Law 20,899 was enacted, which made adjustments to

this tax reform. For further details regarding Chilean tax considerations, please refer to “Item 10. Additional Information — E. Taxation.” Other governmental actions in these South American countries have also involved wage, price and tariff rate controls and other interventionist measures, such as expropriation or nationalization.

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, expropriated Repsol’s 51% stake in YPF in 2012 and imposed exchange controls in 2014, which limited Argentine access to foreign currencies. 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 recorded in January 2011 for taxes payable in 2011 through 2014.

Changes in governmental and monetary policies regarding tariffs, exchange controls, regulations and taxation could reduce our profitability. Inflation, devaluation, social instability and other political, economic or diplomatic developments, including the response by governments in the region to these circumstances, could also reduce our profitability. 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, liquefied natural gas (“LNG”) terminals and re-gasification plants, storage and chartered LNG tankers. Our facilities may be damaged by earthquakes, flooding, fires, and 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 maximum amounts.

As an example, on May 6, 2013, a blade of Edegel’s Santa Rosa gas turbine unit No. 7 broke and produced catastrophic damage to the unit following a fire. The turbine damage was classified as a total loss and its replacement cost exceeded US$ 60 million in property damage and lost profits. The unit was out of service for 19 months, until December 5, 2014. Such accidents may affect our operations, earnings and cash flow.

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, 2015, our consolidated debt totaled Ch$ 2,464 billion.

Our debt had the following maturity profile:

•

Ch$ 617 billion in 2016;

•

Ch$ 682 billion from 2017 to 2018;

•

Ch$ 373 billion from 2019 to 2020; and

•

Ch$ 792 billion thereafter.

Set forth below is a breakdown by country for debt maturing in 2016:

•

Ch$ 183 billion for Chile;

•

Ch$ 170 billion for Colombia

•

Ch$ 135 billion for Brazil;

•

Ch$ 98 billion for Peru; and

•

Ch$ 31 billion for Argentina.

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 bondholders may demand immediate repayment, and a significant portion of our indebtedness could become due and payable. For example, for the quarters ended December 31, 2014, March 31, 2015, June 30, 2015 and September 30, 2015, our Argentine subsidiary El Chocón did not comply with the interest coverage ratio test (EBITDA to interest expense) pursuant to a covenant requirement under the loan agreement with Standard Bank, Deutsche Bank and Itaú that matured and was paid in February 2016. El Chocón experienced difficulties in complying with this covenant several times in the past and obtained waivers from its lenders. If the lenders had decided to declare an event of default and accelerate the loan, the principal and interest would have become immediately due and payable under this facility. Because of cross-acceleration provisions of El Chocón’s other loans, an additional debt would also have been accelerated and El Chocón would have been forced into bankruptcy. In the distribution business, Ampla has been facing different financial problems as a consequence of the Brazilian economic and political situation, which led to a lower electricity demand, higher costs related to inflation and in the specific case of Ampla, to a deterioration of its cash flows and EBITDA, similar to other distribution companies in the Brazilian market. This required Ampla to renegotiate, among other measures, some of its financial covenants between December 2015 and January 2016, in order to avoid breaching them. There is an additional risk of noncompliance if the economic environment in Brazil continues to worsen. In March 2016, as a consequence of the political and economic situation prevailing in Brazil, we also have guaranteed Ampla’s US$ 75 million three-year bank term loan. The financing was granted in Chile in U.S. dollars, and has a swap from U.S. Dollars to Brazilian reais contracted in Brazil, which was also guaranteed by us.

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, we believe that Brazil is a country in which we operate with a high refinancing risk. As of December 31, 2015, the third-party debt of our Brazilian subsidiaries amounted to Ch$ 560 billion. 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 be unable to enter into suitable investments, alliances and acquisitions.

On an ongoing basis, we review acquisition prospects that may increase 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 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, amortization expenses related to tangible assets and the diversion of 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.

Because our generation and transmission business depends heavily on hydrological conditions, droughts and climate change may adversely affect our operations and profitability.

Approximately 53% of our consolidated installed generation capacity in 2015 was hydroelectric. Accordingly, extreme hydrological conditions and climate change could adversely affect our business, results of operations and financial condition. In the last few years, regional hydrological conditions have been affected by two climate phenomena — El Niño and La Niña — that influence rainfall and resulted in droughts. For example, in Brazil, where 67% of our installed capacity is hydroelectric, the low hydrological contributions recorded in 2014 and 2015 and the consequent higher thermal dispatch and spot prices, encouraged the authority in making regulatory changes through a modification of the upper limits. Also, El Niño phenomenon has affected Colombian hydrologic conditions since May 2015, leading to a rainfall deficit and high temperatures, and as a consequence, higher energy prices. Each El Niño event is different and, depending on its intensity and duration, the magnitude of the social and economic effects could be more pronounced. Peru has also experienced rain deficits, especially towards the end of 2015, and forecasts show an expected decrease in the natural flow of the basins in which we operate. The hydrology situation will depend on the level of reservoirs by the beginning of May 2016.

Droughts also affect the operation of our thermal plants, including our facilities that use natural gas, fuel oil or coal as fuel, in the following manner:

•

During drought periods, thermal plants are used more frequently. Thermal plant operating costs can be considerably higher than those of hydroelectric plants. Our operating expenses increase during these periods. In addition, depending on our commercial obligations, we may need to buy electricity at spot prices in order to comply with our contractual supply obligations and the cost of these electricity purchases may exceed our contracted electricity sale prices, thus potentially producing losses from those contracts. For further information with respect to the effect of hydrology on our business and financial results, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — a. Generation Business.”

•

Our thermal plants require water for cooling and droughts not only reduce the availability of water, but also increase the concentration of chemicals, such as sulfates in the water. The high concentration of chemicals in the water we use for cooling increases the risk of damaging the equipment at our thermal plants as well as the risk of violating environmental regulations. As a result, we may have to purchase water from agricultural areas that are also experiencing shortages of water. These water purchases may increase our operating costs and also require us to further negotiate with the local communities.

•

Thermal power plants burning natural gas generate emissions such as sulfur dioxide (SO₂) and nitrogen oxide (NO) gases. When operating with diesel they also release particulate matter into the atmosphere. Coal fired plants generate emissions of SO₂ and NO. Therefore, greater use of thermal plants during periods of drought increases the risk of producing a higher level of pollutants.

In addition, according to certain weather forecast models, the drought that is affecting the regions where most of our hydroelectric plants are located may last for an extended period and may recur in the future. A prolonged drought may exacerbate the risks described above and have a further adverse effect upon our business, results of operations and financial condition.

Governmental regulations may adversely affect our business.

We are subject to extensive regulation on the tariffs we charge to our customers and on other aspects of our business and these regulations may adversely affect our profitability. For example, governments can impose electricity rationing during droughts or prolonged failures of power facilities. During rationing, if 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 aforce majeure event. If we are unable to buy enough electricity at the spot price to comply with our contractual obligations, we would have to compensate our regulated customers for the electricity we failed to provide at the rationed price. Rationing periods have occurred in the past and may occur in the future. Our generation subsidiaries may be required to pay regulatory penalties if they fail to provide adequate service under their contractual obligations. Material rationing policies imposed by regulatory authorities in any of the countries in which we operate could adversely affect our business, results of operations and financial condition.

Governmental authorities may also delay the distribution tariff review process, or tariff adjustments determined by governmental authorities may be insufficient to pass through our costs (as has been the case with Edesur, our Argentine distribution subsidiary and with Ampla and Coelce, our Brazilian distribution subsidiaries, for part of 2014). Similarly, electricity regulations issued by governmental authorities in the countries in which we operate may affect the ability of our generation companies to collect revenues sufficient to offset their operating costs.

The inability of any company in our consolidated group to collect revenues sufficient to cover operating costs may affect the ability of that company to operate as a going concern and may otherwise have an adverse effect on our business, 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 some of these changes could have a material adverse impact on our business, results of operations and financial condition. For example, commercial operations of Emgesa’s El Quimbo power plant have been intermittent due to legislative and judicial decisions regarding its authorization to commence commercial operations.

These changes could adversely affect our business, results of operations and financial condition.

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

Approximately 53% of our installed capacity is hydroelectric. We own water rights for the supply of water from rivers and lakes near our production facilities, granted in Argentina by the Argentine State, in Colombia by the Ministry of Environment, Housing and Territorial Development (“MAVDT” in its Spanish acronym), in Peru by the Water National Authority (“ANA” in its Spanish acronym), and in Brazil by the Water National Authority (“ANA” in its Portuguese acronym). In Colombia, water rights or water concessions are granted for 50 years, renewable by equal periods; however, these concessions may be revoked, for example, due to a progressive decrease or depletion of water. In Colombia, human consumption is the first priority before any other use. A similar event may happen in Peru and we could lose our water rights, even when concessions are granted for indefinite periods, due to scarcity or decline in quality.

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

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 four countries in which we operate. In Peru, fines may be imposed for a maximum

of 1,400 Treasury Tax Units (Unidad Impositiva Tributariaor “UIT”), or Ch $ 1,103 million, using the UIT and foreign exchange rates as of December 31, 2015. In Colombia, fines may be imposed for a maximum of 2,000 Minimum Monthly Salaries (Salarios Mínimos Mensuales), or Ch$ 291 million using the Minimum Monthly Salary and foreign exchange rates as of December 31, 2015. In Argentina, there is no maximum limit for relevant fines. In Brazil, fines may be imposed for up to 2.0% of an electricity company’s revenues.

Our electricity generation subsidiaries are supervised by their local regulatory entities and 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 such as when agents are not coordinated with the system operator. In addition, our subsidiaries may be required to pay fines or 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 April 2013, Edegel, our generation company in Peru, was fined Ch$ 73.9 million by the Osinergmin, the Peruvian regulatory electricity authority, for the unavailability in several occasions of some of its units in 2008. Edegel paid two of the four fines and appealed the other two, which are still under dispute. In 2015, the Electricity National Regulatory Agency (“ENRE” in its Spanish acronym) imposed fines on Edesur, our distribution company in Argentina, for a total of Ch$ 6.6 billion due to technical and commercial operation failures. For further information on fines, please refer to Note 38 of the Notes to our consolidated financial statements.

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

In order to pay our obligations, we rely on cash from dividends, loans, interest payments, capital reductions and other distributions from our subsidiaries and equity affiliates. 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 four countries where they operate.

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

Our future results from operations may continue to be subject to greater economic and political uncertainties, such as government regulations, economic conditions and credit restrictions, and therefore we may not be able to rely on cash flows from operations in those entities to repay our debt.

Dividend Limits and Other Legal Restrictions. Some of our subsidiaries are subject to legal reserve requirements and other restrictions on dividend payments. Other legal restrictions, such as foreign currency controls, may limit the ability of our subsidiaries and equity affiliates to pay dividends and make loan payments or other distributions to us. In addition, the ability of any of our subsidiaries that are not wholly-owned to distribute cash to us may be limited by the directors’ fiduciary duties of such subsidiaries to their minority shareholders. Furthermore, some of our subsidiaries may be forced by local authorities, in accordance with applicable regulation, to diminish or eliminate dividend payments. As a consequence of such restrictions, our subsidiaries could, under certain circumstances, be impeded from distributing cash to us.

Contractual Constraints. Distribution restrictions included in certain credit agreements of our subsidiaries 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, which was the case of Ampla and Enel Brazil as a consequence of the economic and political situation that Brazil and especially the distribution sector, is dealing with.

Any of the situations described above could adversely affect our business, 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 (primarily coming from the generation and transmission business), 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.

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 adversely affect our business, results of operations and financial condition.

As of December 31, 2015, the amount of our total consolidated debt was Ch$ 2,464 billion. Of this amount, Ch$ 379 billion, or 15%, was denominated in U.S. dollars. As of December 31, 2015, our consolidated foreign currency-denominated indebtedness (other than U.S. dollars) included the equivalent of:

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Ch$ 1,182 billion in Colombian pesos;

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Ch$ 558 billion in Brazilian reais;

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Ch$ 290 billion in Peruvian soles;

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Ch$ 30 billion in Argentine pesos; and

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Ch$ 25 billion in Chilean pesos.

These amounts total Ch$ 2,085 billion in currencies other than U.S. dollars.

For the twelve-month period ended December 31, 2015, our operating cash flows were Ch$ 1,933 billion (before consolidation adjustments) of which:

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Ch$ 550 billion, or 29%, came from Chile;

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Ch$ 490 billion, or 25%, came from Colombia;

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Ch$ 350 billion, or 18%, came from Argentina;

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Ch$ 277 billion, or 14%, came from Peru; and

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Ch$ 266 billion, or 14%, came from Brazil.

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

For example, in 2001, the inhabitants of Sibaté (part of the Cundinamarca Department, Colombia) sued Emgesa and two other unrelated parties because of the possible contamination of El Muña Reservoir, demanding that the defendants pay for damages of CPs 3 billion (approximately Ch$ 675 billion). The plaintiffs argued that the contamination is a consequence of the pumping of polluted water from the Bogotá River. Emgesa argued that it is not responsible since the company had received the polluted water and requested the inclusion as additional defendants in the judicial proceedings, numerous public and private entities that discharged pollutants into the river or were responsible for the environmental management of the river’s basin. This request was originally accepted by the court, but in June 2015 the court decision was reversed and the new parties were subsequently excluded as defendants. Emgesa appealed such determination and the case remains pending. Our financial condition or results of operations could be adversely affected if we are unsuccessful in defending this litigation or other lawsuits and proceedings against us. For further information on litigation proceedings, please see Note 36.3 of the Notes to our consolidated financial statements.

The values of our generation and transmission business 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 business, results of operations and financial condition.

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

Enel beneficially owns 60.6% of our share capital. Enel, our ultimate controlling shareholder, has the power to determine the outcome of substantially all material matters that require shareholders’ votes, such as the election of the majority of our board members and, subject to contractual and legal restrictions, our dividend policy. Enel also exercises decisive influence over our business strategy and operations. Its interests may in some cases differ from those of our minority shareholders. For example, Enel conducts its business operations in the field of renewable energies in South America through Enel Green Power S.p.A. and in the Chilean electricity business through Enersis Chile, in neither of which we have equity interests. Any present or future conflict of interest affecting Enel may be resolved against our best interests in these matters. As a consequence, our growth may be potentially limited, and our business and results of operations may be adversely affected.

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.

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. Any such event could adversely impact our results of operations and financial condition.

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

Our power plant projects may encounter significant opposition from different groups that may delay their development, increase costs, damage our reputation and potentially result in impairment of our 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 that could negatively impact sentiments toward us, our business, results of operations and financial condition could be adversely affected.

The development of new and existing 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, El Quimbo hydroelectric project in Colombia faced constant demands from the public which delayed construction and increased costs. From April 27, 2014 to May 12, 2014, a national agricultural strike involving communities near the project blocked roads and occupied neighboring land. Additional protests during 2014 blocked the entrance to the Balseadero viaduct construction site and the reservoir basin.

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, causing our share prices to drop and hindering our ability to attract or retain valuable employees, all of which could result in an impairment of our goodwill with stakeholders.

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 adversely impact our business, results of operations and financial condition as well as our reputation.

Interruption or failure of our information technology and communications systems or external attacks to or breaches 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 business, results of operations and financial condition.

IT Systems are all vital to our generation subsidiaries’ ability to monitor our power plants’ operations, maintain generation and network performance, adequately generate invoices to customers, achieve operating efficiencies and meet our service targets and standards. Our distribution subsidiaries could also be affected adversely because they rely heavily on IT Systems to monitor their grids, billing processes for millions of customers and customer service platforms. 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 2014, we suffered two cyber attacks perpetrated by a cyber-terrorist group, which impacted websites in Argentina, Brazil, Colombia and Peru. In one case, the attack resulted in a service interruption of 90 minutes. Further cyber attacks may occur and may affect us in the future.

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. Currently, the construction of new transmission lines is taking longer than in the past, mainly because of new social and environmental requirements that are creating uncertainty about the probability of completing the projects. In addition, the increase of new non-conventional renewable energy (“NCRE”) projects in the region is congesting the current transmission systems as these projects can be built relatively quickly, while new transmission projects may take longer to be built.

Any such disruption or failure of transmission facilities 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 ADSs.

Even though we do not have assets in Chile, our shares are traded on the Chilean Stock Exchanges since we are organized under the laws of the Republic of Chile and we have our headquarters in Chile. 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 shareholders to sell shares, or holders of ADSs to sell shares of our common stock withdrawn from the ADS program into the Chilean market in the amount and at the price and time they wish to do so. Also, the liquidity and the market for our shares or ADSs may be affected by a number of factors including variations in exchange and interest rates, the deterioration and volatility of the markets for similar securities and any changes in our liquidity, financial condition, creditworthiness, results and profitability.

Our historical performance may not be representative of our performance after the Spin-Off.

Our historical performance might have been different if we had been a separate entity during the periods presented in our financial statements. The historical financial information included in this Report is not necessarily indicative of what our results of operations, financial position and cash flows will be in the future. There may be changes that will occur in our cost structure, funding and operations as a result of the separation of Enersis Chile from us, including increased costs associated with reduced economies of scale.

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

All of our assets are located outside of the United States. All of our directors and all of our officers reside outside of the United States and most of their assets are located outside the United States as well. If any investor were to bring a lawsuit against our directors, officers or experts in the United States, it may be difficult for them to effect service of legal process within the United States upon these persons, or to enforce against them, in United States or Chilean courts, judgments obtained in United States courts based upon the civil liability provisions of the federal securities laws of the United States. In addition, there is doubt as to whether an action could be brought successfully in Chile on the basis of liability based solely upon the civil liability provisions of the United States federal securities laws.

Our business and the shares and ADSs may be adversely impacted if the Merger is not consummated.

There can be no assurance that the Merger will occur, as the Merger is subject to certain conditions including shareholders approval, among others. The Company cannot guarantee that these conditions will be satisfied and that the Merger will be successfully completed. The failure to consummate the Merger following the Spin-Off will prevent the Company from reaping the expected benefits of the Merger, which could adversely affect our results of operations and financial condition and could adversely affect the price of the Company’s shares and ADSs.

Item 4.

Information on the Company

History and Development of the Company.

History

We are a publicly held limited liability stock corporation organized under the law of the Republic of Chile. We were organized on June 19, 1981 and we operated under the name Enersis S.A. (“Enersis”) from 1988 until March 1, 2016, when our name was changed to Enersis Américas S.A. Since January 1983, we have been registered in Santiago with the SVS under Registration No. 0175. We also registered with the United States Securities and Exchange Commission under the commission file number 001-12440 on October 19, 1993.

Our contact information in Chile is:


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

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

Since June 2009, our controlling shareholder has been the Italian company Enel S.p.A. (“Enel”), which holds a beneficial ownership of 60.6% of our shares. Enel is an international energy company operating worldwide in the power and gas markets, with a focus on Europe and Latin America. Enel operates in 32 countries across four continents, with over 95 GW of net installed capacity and distributes electricity and gas through a network covering approximately 1.9 million km. Enel has 61 million customers worldwide.

We are one of the largest publicly listed companies in the electricity sector in South America. We trace our origins to Compañía Chilena de Electricidad Ltda. (“CCE”), which was formed in 1921 as a result of the merger of Chilean Electric Tramway and Light Co., founded in 1889, and Compañía Nacional de Fuerza Eléctrica (“CONAFE”), with operations dating back to 1919. In 1970, the Chilean government nationalized CCE. During the 1980s, the sector was reorganized through the Chilean Electricity Law, known as the Decree No. with Force

of Law Number 1 of 1982 (“DFL 1”), CCE’s operations were divided into one generation company, AES Gener S.A. (“Gener”), a currently unrelated company, and two distribution companies, one with a concession in the Valparaíso Region, Chilquinta S.A., a currently unrelated company, and the other with a concession in the Santiago metropolitan region, Compañía Chilena Metropolitana de Distribución Eléctrica S.A. From 1982 to 1987, the Chilean electric utility sector went through a process of re-privatization. In August 1988, Compañía Chilena Metropolitana de Distribución Eléctrica S.A., our predecessor company, changed its name to Enersis S.A. and became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A. In the 1990s, we diversified into electricity generation and transmission through our increasing equity stakes in Endesa Chile.

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

In 2005, Enel Brasil was formed to manage all generation, transmission and distribution assets that Endesa Latinoamérica, Endesa Chile, Chilectra and we held in Brazil; namely, Ampla, Fortaleza, CIEN, Cachoeira Dourada and Coelce. As of December 31, 2015, we had an 84.4% beneficial economic interest in Enel Brasil.

In 2006, in order to achieve synergies in Peru, we merged Edegel and Empresa de Generación Termoeléctrica Ventanilla S.A., a Peruvian generation company that was owned by the Spanish electric utility, Endesa, S.A. (“Endesa Spain”) at the time, creating a 457 MW thermoelectric generation company.

In September 2007, we merged our generation subsidiaries in Colombia to form Emgesa. As of December 31, 2015, we had a 37.7% beneficial economic interest in Emgesa, directly and indirectly through Endesa Chile. Pursuant to a shareholders’ agreement and the transfer of our 25.1% voting rights to Endesa Chile, we control Emgesa though Endesa Chile and therefore consolidate Emgesa. For more information regarding the control and consolidation of Emgesa, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

In February 2009, Codensa, our Colombian distribution subsidiary, acquired approximately 49% of DECSA, an investment vehicle. The remaining 51% was acquired by Empresa de Energía de Bogotá (“EEB”). Codensa and EEB jointly control DECSA.

In March 2009, DECSA acquired 82.3% of Empresa de Energía de Cundinamarca S.A. (“EEC”), a formerly state-owned company that was privatized that year. EEC is a Colombian company primarily engaged in trading of electricity in Cundinamarca province.

In October 2009, Endesa Chile purchased an additional 29.4% of Edegel from Generalima, an indirect Peruvian subsidiary of Endesa Spain. With this transaction, Endesa Chile increased its economic interest in Edegel from 33.1% to 62.5%. As of December 31, 2015, we had a 58.6% beneficial economic interest in Edegel. In the same month, we acquired additional share capital of our Peruvian subsidiary, Edelnor, increasing our beneficial ownership stake in Edelnor to 75.5%.

In June 2012, Endesa Spain, our parent company at the time, proposed a capital increase in our Company, in which it would carry out an in-kind contribution of all of its equity interests in 25 companies in the five South American countries in which we operate. The rest of the shareholders would have the right to contribute their

proportional participation in cash. The capital increase was approved by an Extraordinary Shareholders’ Meeting held on December 20, 2012. The capital increase was first offered to existing shareholders through a rights offering registered with both the Chilean SVS and the United States SEC and subsequently through a follow-on offering, which ended on March 28, 2013. The total Ch$ 2,846 billion (approximately US$ 6 billion) capital increase consisted of Ch$ 1,714 billion (approximately US$ 3.6 billion) of in-kind contributions from Endesa Spain and Ch$ 1,132 billion (approximately US$ 2.4 billion) in cash from minority shareholders (the “2013 capital increase”). We began consolidating Piura, Cemsa and Dock Sud as of April 1, 2013, following the in-kind contribution.

Following the 2013 capital increase, we acquired additional interests in certain companies in which we already had a minority economic interest, directly or indirectly through our subsidiaries, including the following transactions:

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On January 14, 2014, we submitted a voluntary public offer for the acquisition of shares from the shareholders of our subsidiary Coelce. A price of R$ 49 was offered per share, for all share classes. At the time of the announcement, we controlled Coelce and had an economic interest of 58.9%. We acquired 3,002,812 additional ordinary shares, 8,818,006 preferred A shares and 424 preferred B shares, equivalent to an investment of approximately Ch$ 133 billion. As a consequence of this transaction which closed in May 2014, we hold a 64.9% economic interest in Coelce.

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On April 30, 2014, we announced the purchase of all indirectly held shares that Inkia Americas Holdings Limited had in Generandes Perú S.A. (equal to 39.0% of such company), the controlling company of Edegel. The total investment amounted to Ch$ 243 billion (equivalent to US$ 413 million). As result of this transaction, which closed in September 2014, we hold a 58.6% economic interest in Edegel.

On October 23, 2014, Endesa Spain sold 9,967,630,058 of our shares (representing a 20.3% interest) directly held by it and 100% of its shareholding in Enel Latinoamérica (owner of 40.32% of our shares) to a subsidiary of Enel. As a result, Enel beneficially owns 60.6% of our shares and is our controller.

In the Extraordinary Shareholders’ Meeting (“ESM”) held on December 18, 2015, shareholders agreed to carry out a spin-off in order to separate the Chilean activities from those in other Latin American countries (Argentina, Brazil, Colombia and Peru). The new company, Enersis Chile S.A. (“Enersis Chile”), was established as a separate company effective as of March 1, 2016 and was assigned the equity interests, assets and associated liabilities of our businesses in Chile. We, the continuing company, hold the non-Chilean businesses and assets. On April 21, 2016, we distributed to our shareholders shares of Enersis Chile in proportion to their share ownership in our Company based on a ratio of one share of Enersis Chile for each of our outstanding shares.

Each of Endesa Chile and Chilectra also conducted a demerger to separate them into two companies. As part of the demerger, Endesa Américas S.A. (“Endesa Américas”) and Chilectra Américas S.A. (“Chilectra Américas”) were formed and hold the non-Chilean business, comprised exclusively of their respective ownership interests in shares of companies domiciled outside of Chile, formerly held by Endesa Chile and Chilectra, respectively.

We own 60.0% of Endesa Américas and 99.1% of Chilectra Américas. The minority shareholders of Endesa Chile and Chilectra (which changed its name to Chilectra Chile on March 1, 2016) own their respective percentage interests in Endesa Américas and Chilectra Américas, respectively, based on a pro rata distribution of the spin-off company shares. The shares of Endesa Américas and Chilectra Américas are listed and traded on the Chilean Stock Exchanges and the American Depositary Receipts (“ADRs”) of Endesa Américas are listed and traded on the New York Stock Exchange (“NYSE”).

Prior to the Extraordinary Shareholders’ Meeting to approve the Merger, we will conduct a public cash tender offer (oferta pública de adquisición de valores, or Tender Offer). This Tender Offer will provide protection to Endesa Américas’ minority shareholders and an opportunity for us to buy out minority shareholders

using the funds from the 2013 capital increase. The Tender Offer will provide a floor to the stock price post-spin-off, will be directed equally to all Endesa Américas minority shareholders and will enable us to align incentives to approve the Merger, reducing uncertainty and providing additional liquidity for Endesa Américas shareholders. The Tender Offer is contingent on (i) the approval of the Merger by the respective shareholders of our Company, Endesa Américas and Chilectra Américas at separate ESM of the three companies, (ii) less than 10% of our outstanding shares, 7.72% of the outstanding shares of Endesa Américas and 0.91% of the outstanding shares of Chilectra Américas exercising the right of withdrawal in connection with the merger, and (iii) the absence of any significant adverse supervening events that would make the Tender Offer not in our best interest.

The Tender Offer will be for all shares of Endesa Américas, including in the form of ADSs represented by ADRs of Endesa Américas (other than those held by us), for a price of Ch$ 285.00 per share (or the equivalent in U.S. dollars at the date of payment in the case of ADSs), and will be subject to other terms and conditions which will be provided at the appropriate time. The Tender Offer is expected to occur by the third quarter of 2016.

Subject to approval by shareholders holding at least two-thirds of the outstanding shares of the relevant companies, Endesa Américas and Chilectra Américas intend to merge into our Company, which will continue as the surviving company and under the name Enersis Américas S.A.

Following completion of the Merger, we will continue to have our shares publicly traded and listed in Chile on the Chilean Stock Exchanges and our ADRs traded on the NYSE. In the Merger, the shares of Endesa Américas and Chilectra Américas will be converted into shares of our Company, shares of Endesa Américas and Chilectra Américas shares will cease trading on the Chilean Stock Exchanges and ADRs of Endesa Américas will cease to trade on the NYSE. Following the Merger, Enel is expected to continue to be our ultimate controlling shareholder, through its beneficial ownership. Our current minority shareholders, together with the former minority shareholders of both Endesa Américas and Chilectra Américas will own the minority interest in our Company.

In connection with the Merger, we, as well as Endesa Américas and Chilectra Américas, will each hold an ESM to approve the Merger. Prior to the ESM, we will register the shares to be issued in the Merger with the SEC under the Securities Act. In connection with the respective ESM to approve the Merger, which are expected to be held in the third quarter of 2016, we will distribute a prospectus/information statement to our and Endesa Américas’ shareholders, which contains information about the Merger and our Company post-Merger.

In the event that the Merger is not materialized, we, as well as Endesa Américas and Chilectra Américas, will remain as separate publicly traded companies.

As of December 31, 2015, we had 10,932 MW of installed capacity with 101 power units in the four countries in which we operate, consolidated assets of Ch$ 10,303.1 billion and operating revenues of Ch$ 5,301.4 billion.

Capital Investments, Capital Expenditures and Divestitures

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

Our investment plan is flexible enough to adapt to changing circumstances by giving different priorities to each project in accordance with profitability and strategic fit. Investment priorities are currently focused on developing additional thermal capacity in Peru to guarantee adequate levels of reliable supply while remaining focused on the environment.

For the 2016-2020 period, we expect to make capital expenditures of Ch$ 3,781 billion in our subsidiaries, related to investments currently in progress, maintenance of our distribution network, maintenance of existing generation plants and in the studies required to develop other potential generation and distribution projects. For further detail regarding these projects, please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Development.”

The table below sets forth the expected capital expenditures for the 2016-2020 period and the capital expenditures incurred in 2015, 2014 and 2013:


	Estimated 2016-2020		2015		2014		2013
	(in millions of Ch$)
Capital expenditures⁽¹⁾		3,780,986		1,362,561		1,089,362		774,820

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

Capital Expenditures 2015, 2014 and 2013

In the generation and transmission business, our capital expenditures in the last three years were related principally to the 400 MW El Quimbo project in Colombia. El Quimbo was completed and began commercial operations in November 2015. Additionally, in December 2014, the Salaco plant optimization was completed, adding a total of 145 MW to the Colombian system.

In addition, in our distribution business, we invested to expand the service in response to increasing demand for energy, to improve quality of service, improve safety and to prevent energy losses, especially in Brazil.

Investments currently in progress

An important part of our capital expenditures are related to non-discretionary investments that include maintenance of existing installed capacity in order to increase the quality and operation standards of our facilities.

In our distribution business, we plan to continue to expand our services, increasing the connections available to end customers, and reduce energy losses to improve efficiency and profitability.

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

B.	Business Overview.

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

The table below presents our revenues by business segment.


	Year ended December 31,
	2015			2014			2013			Change 2015 vs. 2014
	(in millions of Ch$)									(in %)
Generation and Transmission Business
Costanera (Argentina)		100,857			75,194			94,888			34.1
El Chocón (Argentina)		40,005			30,174			36,687			32.6
Cachoeira Dourada (Brazil)		91,563			158,965			117,445			(42.4	)
Fortaleza (Brazil)		159,052			210,793			168,871			(24.5	)
CIEN (Brazil)		58,667			70,800			67,689			(17.1	)
Emgesa (Colombia)		778,756			753,373			639,503			3.4
Edegel (Peru)		382,453			353,795			283,806			8.1
Cemsa (Argentina)		2,270			1,281			1,591			77.2
Dock Sud (Argentina)		69,963			61,606			41,186			13.6
EEPSA (Peru)		58,093			50,849			33,752			14.2
Otros		(6,917	)		(3,961	)		(4,074	)		74.6

Total		1,734,762			1,762,869			1,481,344			(1.6	)

Distribution Business
Edesur (Argentina)		607,345			371,412			528,653			63.5
Edelnor (Peru)		562,046			478,695			413,911			17.4
Ampla (Brazil)		1,026,680			1,092,282			945,131			(6.0	)
Coelce (Brazil)		810,184			876,944			688,981			(7.6	)
Codensa (Colombia)		884,468			982,771			852,780			(10.0	)
Otros					5						(100.0	)

Total		3,890,723			3,802,109			3,429,456			2.3

Less: Consolidation adjustments and non-core activities		(324,045	)		(358,608	)		(382,652	)		(9.6	)

Total		5,301,440			5,206,370			4,528,148			1.8

For further information related to operating revenues and total income by business segment, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 35.2 of the Notes to our consolidated financial statements.

Electricity Generation and Transmission Business

Electricity Generation

As of December 31, 2015, electricity generation represented 33% of our operating revenues and 57% of our operating income before consolidation adjustments.

Our consolidated electricity sales in 2015 were 48,481 GWh and our production was 42,109 GWh, a 0.8% increase and a 0.3% decrease, respectively, compared to 2014.

Our total installed capacity in 2015 was 10,932 MW, a 435 MW increase compared to 2014, mainly due to the additional 400 MW of capacity of El Quimbo, a new hydroelectric plant with two operating units in Colombia, and 34 MW additional capacity in Peru due to capacity adjustments and upgrades to existing plants. Our electricity generation business is conducted primarily through Endesa Américas, which consolidates our operations in Argentina, Colombia and Peru. We also have separate consolidated operations in Brazil through Enel Brasil, in Argentina through Dock Sud and in Peru through EEPSA.

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

ELECTRICITY DATA BY COUNTRY


	Year ended December 31,
	2015		2014		2013
Argentina
Number of generating units⁽¹⁾		25		25		25
Installed capacity (MW)⁽²⁾		4,502		4,502		4,502
Electricity generation (GWh)		15,204		14,390		14,422
Energy sales (GWh)		15,770		15,276		16,549
Brazil
Number of generating units⁽¹⁾		13		13		13
Installed capacity (MW)⁽²⁾		987		987		987
Electricity generation (GWh)		4,398		5,225		4,992
Energy sales (GWh)		6,541		7,108		6,826
Colombia
Number of generating units⁽¹⁾⁽³⁾		36		32		29
Installed capacity (MW)⁽²⁾⁽³⁾		3,459		3,059		2,925
Electricity generation (GWh)		13,705		13,559		12,748
Energy sales (GWh)		16,886		15,773		16,090
Peru
Number of generating units⁽¹⁾		27		27		27
Installed capacity (MW)⁽²⁾⁽⁴⁾		1,984		1,949		1,842
Electricity generation (GWh)		8,801		9,062		8,489
Energy sales (GWh)		9,283		9,916		9,497
Total

Number of generating units⁽¹⁾		101		97		94
Installed capacity (MW)⁽²⁾		10,932		10,497		10,256
Electricity generation (GWh)		42,109		42,237		40,650
Energy sales (GWh)		48,481		48,073		48,963

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

(2)

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

(3)	In Colombia, El Quimbo entered into commercial operations during 2015, adding 400 MW of capacity.

(4)	In Peru, the Santa Rosa TG 7 unit was recommissioned in December 2014, and during 2015 there were capacity adjustments to and upgrades to existing plants, totaling an additional 33 MW. We break down our sales to customers by using the two following criteria:

•

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

•

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

In the electricity industry, it is common to divide the business into hydroelectric and thermoelectric generation, because each type of generation has significantly different variable costs. Thermoelectric generation requires the purchase of fuel, which leads to high variable costs compared with hydro generation from reservoirs or rivers that have minimal or no marginal costs. Of our total consolidated generation in 2015, 52.7% was from hydroelectric sources, and 47.3% was from thermal sources.

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

CONSOLIDATED GENERATION BY TYPE OF ENERGY (GWh)


	Year ended December 31,
	2015				2014				2013
	Generation		%		Generation		%		Generation		%
Hydroelectric		22,171		52.7		22,439		53.1		20,979		51.6
Thermal		19,938		47.3		19,798		46.9		19,671		48.4

Total generation		42,109		100		42,237		100		40,650		100

In the countries in which we operate, the potential for contracting electricity is generally related to electricity demand. Customers identified as small volume regulated customers, including residential customers, are subject to government regulated electricity tariffs, and must purchase electricity directly from a distribution company. These distribution companies, which purchase large amounts of electricity for small volume residential customers, generally enter into contractual agreements with generators at a regulated tariff price. Those identified as large volume industrial customers also enter into contractual agreements with energy suppliers. However, such large volume industrial customers are not subject to the regulated tariff price. Instead, these customers are allowed to negotiate the energy price with generators based on the characteristics of the 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 our consolidated sales of electricity by type of customer for each of the periods indicated:

CONSOLIDATED ELECTRICITY SALES BY CUSTOMER TYPE (GWh)


	Year ended December 31,
	2015				2014				2013
	Sales		%		Sales		%		Sales		%
Regulated customers		17,937		37,0		17,125		35.6		17,344		35.4
Unregulated customers		9,605		19,8		10,503		21.8		10,993		22.5

Total contracted sales⁽¹⁾		27,543		56.8		27,627		57.5		28,336		57.9
Electricity pool market sales		20,938		43.2		20,446		42.5		20,626		42.1

Total electricity sales		48,481		100		48,073		100		48,963		100

(1)	Includes the sales to distribution companies without contracts in Peru.

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

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 normally increases. This involves an increase of the total fuel cost and the costs of its transportation to the thermal generation power plants. Under drought conditions, electricity that we have contractually agreed to provide may exceed the amount of electricity that we are able to generate, which requires us to purchase electricity in the pool market at spot prices in order to satisfy our contractual commitments. The cost of these purchases at spot prices may, under certain circumstances, exceed the price at which we sell electricity under contracts and, therefore, may result in a loss We attempt to minimize the effect of poor hydrological conditions on our operations in any year by limiting our contractual sales requirements to a quantity that does not exceed the estimated production in a dry year. To determine an estimated production in a dry year, we take into consideration the available statistical information concerning rainfall, hydrological levels, and the capacity of key reservoirs. In addition to limiting contracted sales, we may adopt other strategies including installing temporary thermal capacity, negotiating lower consumption levels with unregulated customers, negotiating with other water users and including pass-through cost clauses in contracts with customers. (For further details about hydrological conditions and their effects on our business, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — a. Hydrological Conditions).”

Seasonality

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

The distribution business is directly influenced by seasonal changes in energy demand. Although the price at which a distribution company purchases electricity can change seasonally and has an impact on the price at which it is sold to end users, it does not have an impact on our profitability since the cost of electricity purchased is passed to end users through tariffs that are set for multi-year periods. In Argentina, there are typically extreme temperatures in both summer and winter, which are the peak periods for distributors. During these periods, demand increases due to the need for heating and air conditioning. The Company launched the “Winter 2015 Plan” and “Summer Plan 2014-2015” in order to address these critical periods with preventive actions. During 2015, the average temperatures in Brazil were similar to the previous year. During the past year Brazil went through a political and economic crisis, which resulted in significant tariff adjustments during 2015. On average, there was a 42% increase for Ampla and a 22% increase for Coelce. This, combined with poor hydrology, resulted in 0.4% weaker demand for Ampla and 1.6% greater demand for Coelce, in their respective concession areas. The Colombian distribution business is directly influenced by seasonal changes in energy demand. Although the price at which distribution companies purchase electricity can change seasonally and has an impact on the price at which it is sold to end users, it does not have an impact on our profitability since the cost of purchased electricity is passed to end users through tariffs that are set for multi-year periods. During 2015, the effects of higher than historical average temperatures, due to El Niño Phenomenon in Colombia, have impacted electricity prices paid October. In part, these effects were offset during the fourth quarter. Electricity demand Bogotá grew 2.4% in 2015 vs. 2.6% in 2014, mainly the residential sector. During 2015, Peruvian energy demand was higher than planned, mainly due to higher consumption in toll and medium-voltage customers, partially offset by the slightly lower consumption of low-voltage customers. The country’s fishing, mining, hydrocarbon and manufacturing sectors rebounded in the second half of the year. March is the month that typically has the highest energy demand (7% higher than the annual average) due to seasonal sectors and February is typically the month with the lowest consumption (4% less than the annual average), because of its shorter length.

The generation businesses in the countries where we operate are affected by seasonal changes throughout the year. The months with the most precipitation in Argentina are typically May through August, with snow

melts typically occurring between October and December. The months with the most precipitation in our operating area in Colombia are typically April and May as well as October and November. The months with the most precipitation in Peru are typically November through March.

When there is more precipitation hydroelectric generating facilities can accumulate additional water to be used for generation. The increased level of our reservoirs allows us to generate more electricity with hydro power plants during months in which marginal electricity costs are lower.

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

Operations in Argentina

We participate in electricity generation in Argentina through subsidiaries of Endesa Américas (Costanera and El Chocón) and through our subsidiary Dock Sud, with an aggregate of 25 power units with a total installed capacity of 4,502 MW. Costanera owns eleven thermal units, with a total installed capacity of 2,304 MW, El Chocón owns nine hydroelectric units, with total installed capacity of 1,328 MW, and Dock Sud owns five thermal units with a total installed capacity of 870 MW. Our hydro and thermal generation units in Argentina represented 14.3% of the Argentine National Interconnected System’s (“Argentine NIS”) installed capacity in 2015.

Our Argentine subsidiaries have stakes in three additional companies: Termoeléctrica Manuel Belgrano S.A., Termoeléctrica San Martín S.A. and Central Vuelta de Obligado S.A. These companies were formed to undertake the construction of three new generation facilities for a fund called “FONINVEMEM”, whose purpose is to increase electricity capacity and generation within the Argentine wholesale electricity market. The first two plants began their operations in 2008 using gas turbines, with an aggregate capacity of 1,125 MW, and began its combined cycle operations in March 2010, with an additional capacity of 572 MW. The total aggregate capacity of these units is 1,697 MW (848 MW from Manuel Belgrano and 849 MW from San Martín). The third plant began its open cycle operations in mid-2015 (with an installed capacity of 550 MW), and it is expected to begin its combined cycle operations in 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. In addition, since 2002, the Argentine government has taken an active role in controlling the fuel supply to the electricity generation sector. (See “Item 4. Information on the Company— B. Business Overview — Electricity Industry Regulatory Framework — Argentina” for further detail).

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

As of December 31, 2015, Costanera’s installed capacity accounted for 7.3% of the total installed capacity in the Argentine NIS. Both Costanera’s steam turbine power plant and second combined-cycle plant can operate with either natural gas or diesel.

El Chocón accounted for 4.2% of the installed capacity in the Argentine NIS as of December 31, 2015. El Chocón has a 30-year concession, ending in 2023, for two hydroelectric generation facilities with an aggregate installed capacity of 1,328 MW. 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 completed construction on the Arroyito dam, and increased the elevation of the reservoir’s water level, which allows the release of water at an additional 1,150 m³/sec, for a total of 3,750 m³/sec. A portion of the Arroyito facility’s generation is sold under the “Energy Plus” program, which provides for the offer of new electricity capacity to supply the electricity demand growth, using the 2005 demand level for electricity as a base. (For details on “Energy Plus”, see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Argentina”).

Dock Sud’s installed capacity of 870 MW accounted for 2.7% of the total installed capacity in the Argentine NIS as of December 31, 2015. The Dock Sud combined-cycle plant consists of three generation units with an installed capacity of 798 MW that operate using either natural gas or diesel as fuel. The two gas turbine units of Dock Sud have 72 MW of installed capacity.

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

Our total generation in Argentina amounted to 15,204 GWh in 2015. According to CAMMESA, our generation market share was approximately 11.1% of the total electricity production in Argentina during 2015.

Hydroelectric generation in Argentina accounted for nearly 21.3% of our total generation in 2015. This was due to the fact that hydrological levels of the Limay River were close to average levels due to higher than average precipitation during the winter months.

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

ELECTRICITY GENERATION IN ARGENTINA (GWh)


	Year ended December 31,
	2015				2014				2013
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (El Chocón)		3,238		21,3		2,632		18.3		2,317		16.1
Thermal generation (Costanera and Dock Sud)		11,966		78,7		11,758		81.7		12,105		83.9

Total generation		15,204		100		14,390		100		14,422		100

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

ELECTRICITY GENERATION AND PURCHASES IN ARGENTINA (GWh)


	Year ended December 31,
	2015				2014				2013
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		15,204		96,4		14,390		94.2		14,422		87.2
Electricity purchases		566		3,6		886		5.8		2,126		12.8

Total⁽¹⁾		15,770		100		15,276		100		16,549		100

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

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

ELECTRICITY SALES PER CUSTOMER SEGMENT IN ARGENTINA (GWh)

Year ended December 31,

2015

2014

2013

Sales

% of
Sales
Volume

Sales

% of
Sales
Volume

Sales

% of
Sales
Volume

Contracted sales

588

3.7

904

5.9

2,225

13.4

Non-contracted sales⁽¹⁾

15,182

96.3

14,372

94.1

14,324

86.6

Total electricity sales

15,770

100

15,276

100

16,549

100

(1)	Non-contracted electricity sales were made at spot prices determined by the regulator.

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

ELECTRICITY SALES PER SUBSIDIARY IN ARGENTINA (GWh)


	Year ended December 31,
	2015		2014		2013
Costanera		8,168		7,051		8,962
El Chocón		3,801		3,391		3,392
Dock Sud		3,802		4,834		4,195

Total		15,770		15,276		16,549

In March 2013, the government intervened in the commercial market for energy, except with respect to the “Energy Plus” program, through the one-time application of Resolution 95/2013. CAMMESA is now responsible for the administration of contracts with end customers, except for those 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 dates.

As of December 31, 2015, Costanera did not have contracts with unregulated customers or distribution companies and sold all of its electricity to the pool market during the year.

As of December 31, 2015, El Chocón had only one contract with unregulated customers and no contracts with distribution companies. Energy is provided to Minera Alumbrera through CEMSA, our subsidiary.

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

For the year ended December 31, 2015, Dock Sud did not have any contracts with regulated customers or distribution companies and sold all of its electricity to the pool market during the year.

According to CAMMESA, electricity demand throughout the Argentine NIS increased by 4.4% during 2015. The total electricity demand was 131,998 GWh in 2015, 126,397 GWh in 2014 and 125,167 GWh in 2013. Our Argentine subsidiaries compete with all the major power plants connected to the Argentine NIS. According to the installed capacity reported by CAMMESA, in its monthly report as of December 2015, our major competitors in Argentina are: (1) the state controlled company Enarsa (with an installed capacity of 1,133 MW),

(2) the nuclear unit “NASA” (with an installed capacity of 1,010 MW), and (3) 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 seven power plants connected to the Argentine NIS with a total installed capacity of 2,753 MW (43.7% 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 2,217 MW, competes with us with six power plants, of which 653 MW is hydroelectric and 1,564 MW is thermal.

Operations in Brazil

Enel Brasil consolidates generation operations of Cachoeira Dourada and Fortaleza.

As of December 2015, we had a total installed capacity of 987 MW in Brazil, of which 665 MW is from Cachoeira Dourada and 322 MW is from Fortaleza.

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

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

ELECTRICITY GENERATION IN BRAZIL (GWh)


	Year ended December 31,
	2015				2014				2013
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (Cachoeira Dourada)		2,057		46.8		2,741		52.5		2,404		48.2
Thermal generation (Fortaleza)		2,342		53.2		2,484		47.5		2,588		51.8

Total		4,398		100		5,225		100		4,992		100

During 2015, thermal generation exceeded hydroelectric generation because hydrological conditions were below the historical average in the Paranaiba basin, where Cachoeira Dourada is located, with rainfall at approximately 66% of the historical average.

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

ELECTRICITY GENERATION AND PURCHASES IN BRAZIL (GWh)


	Year ended December 31,
	2015				2014				2013
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		4,398		67.2		5,225		73.5		4,992		73.1
Electricity purchases		2,142		32.8		1,883		26.5		1,835		26.9

Total⁽¹⁾		6,541		100		7,108		100		6,827		100

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

Cachoeira Dourada is a hydroelectric company consisting of ten generation units with a total installed capacity of 665 MW, located in southern Brazil. Cachoeira Dourada’s market share is 0.5% of the total installed capacity of the Brazilian system. It had long-term contracts (originally seven-year terms, which expired in 2015) with 34 distribution companies due to the bids carried out for regulated customers by bilateral agreements, called Electric Power Trading Agreements within the Regulated Environment (“CCEAR” in its Portuguese acronym). Contracts sales with regulated customers in 2015 were 1,109 GWh. Additionally, during 2015, Cachoeira Dourada had medium-term contracts (originally two to five year terms, expiring in 2015, and currently in negotiations) with 24 unregulated customers, with an average duration of three years. Cachoeira Dourada’s sales to unregulated customers were 1,645 GWh.

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

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

Year ended December 31,

2015

2014

2013

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales

2,754

85.7

3,634

93.1

3,369

94.5

Non-contracted sales

461

14.3

269

6.9

195

5.5

Total electricity sales⁽¹⁾

3,215

100

3,903

100

3,564

100

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

For the year ended December 31, 2015, Cachoeira Dourada’s principal unregulated customers were (ordered alphabetically): AES Tietê, Cargill, Guardian, Peugeot and Tractebel.

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

Fortaleza’s market share is 0.2% of the total installed capacity of the Brazilian system and 0.8% of the thermoelectric generators. Fortaleza has a long-term contract with Coelce that expires in 2023.

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

FORTALEZA’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,

2015

2014

2013

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales

2,690

80.9

2,690

83.9

2,690

82.5

Non-contracted sales

636

19.1

515

16.1

572

17.5

Total electricity sales

3,326

100

3,205

100

3,262

100

For the year ended December 31, 2015, the Fortaleza’s principal distribution customer was Coelce.

Operations in Colombia

Our generation operations in Colombia are carried out through Emgesa. We hold a 37.7% stake in Emgesa as of December 31, 2015, which we control through Endesa Américas and consolidate as a result of Endesa Américas holding 56.4% of Emgesa’s voting rights and the right to appoint a majority of the Board members pursuant to a shareholder agreement. For more information on our control over Emgesa, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

As of December 31, 2015, Emgesa operated 36 generation units, with a total installed capacity of 3,459 MW, of which 3,015 MW was from hydroelectric plants and 444 MW was from thermoelectric plants. According toExpertos de Mercado S.A. E.S.P. (“XM”), a Colombian company that provides system management in real time services in electrical, financial and transportation sectors, our hydroelectric and thermal generation plants represented 21.0% of the country’s total electricity generation capacity as of December 2015. For information on the installed generation capacity for each of our Colombian subsidiaries, see “Item 4. Information on the Company — D. Property, Plant and Equipment—Property, Plant and Equipment of Generating Companies.”

Approximately 89% of our installed capacity in Colombia is hydroelectric, and therefore, our electricity generation depends on reservoir levels and rainfall. According to XM, our generation market share was 20.6% in 2015, 21.2% in 2014 and 20.6% in 2013. In addition to hydrological conditions, the generation amount 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 2015, thermal generation represented 10.8% of total generation and hydroelectric generation represented the remaining 89.2%. In 2015, hydrological conditions were below the historical averages in Colombia, with rainfall around 79% of the historical averages. In the case of Emgesa, according to XM, the three rivers that supply water to Emgesa’s hydroelectric power plants were as follows compared to their historical levels: the Guavio River Basin was 13% higher, the Magdalena River (Betania) was 10% lower and the Bogotá River (Cadena Nueva) was 7% lower. For the year ended December 31, 2015, hydroelectric generation decreased by 3.2% compared to 2014.

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

ELECTRICITY GENERATION IN COLOMBIA (GWh)


	Year ended December 31,
	2015				2014				2013
	Generation		%		Generation		%		Generation		%
Hydroelectric generation		12,223		89.2		12,627		93.1		11,784		92.4
Thermal generation		1,482		10.8		932		6.9		964		7.6

Total generation		13,705		100		13,559		100		12,748		100

During 2015, Emgesa used 554 kilotons of coal for its coal-fired plants, which was obtained from 22 local suppliers compared to the 439 kilotons used during 2014.This higher consumption can be explained by the presence of El Niño climate phenomena which resulted in drier hydrology in Colombia than in 2014. 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.

In 2013, Emgesa also entered into a fuel oil supply agreement with Esapetrol, in addition to the existing oil supply contracts with Petromil and Biomax. During 2015, the Cartagena power plant consumed 118 kilotons of fuel oil, primarily supplied from Petromil. We believe that Emgesa will have 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,
	2015				2014				2013
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		13,705		80.2		13,559		85.3		12,748		78.6
Electricity purchases		3,384		19.8		2,333		14.7		3,461		21.4

Total⁽¹⁾		17,089		100		15,893		100		16,209		100

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

Colombia has a single interconnected electricity system, the National Interconnected System (“Colombian NIS”). Electricity demand in the Colombian NIS increased 4.1% during 2015. Total electricity consumption was 66,173 GWh in 2015, 63,570 GWh in 2014 and 60,890 GWh in 2013.

Colombia has an agreement with Ecuador to provide an interconnection between the electricity systems of both countries. During 2015, Colombian electricity generators sold 457 GWh of electricity to Ecuadorian customers.

In addition, Colombia has interconnection lines with Venezuela that operate under exceptional circumstances as needed by either of the two countries. In April 2011, Colombia and Venezuela signed an agreement to supply energy to Venezuela as part of the normalization of commercial relations. This agreement also includes the import of gasoline and diesel from Venezuela. The total energy exported to Venezuela was 3 GWh in 2015.

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,

2015

2014

2013

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales

12,505

74.1

10,969

69.5

11,567

71.9

Non-contracted sales

4,381

25.9

4,804

30.5

4,523

28.1

Total electricity sales⁽¹⁾

16,886

100

15,773

100

16,090

100

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

During 2015, Emgesa served 440 customers, of which 422 were unregulated customers and 18 were distribution and trading companies. Emgesa’s sales to our Colombian distribution subsidiary, Codensa, accounted for 15% of our total contracted sales with regulated customers in 2015. Electricity sales to the five largest unregulated customers represented 23% of total contracted sales with unregulated customers.

For the year ended December 31, 2015, principal distribution customers were (ordered alphabetically): Codensa (our subsidiary), Compañia Energética del Tolima (“Enertolima”), Electrificadora del Caribe (“Electrocaribe”), Electrificadora del Huila, Electrificadora de Santander and Empresas Públicas de Medellín (“EPM”).

Our most significant competitors in Colombia include the following state-owned companies: Empresas Públicas de Medellín (with an installed capacity of 3,202 MW) and Isagen (with an installed capacity of 3,001 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 1,862 MW), which includes Termoflores and Epsa; and Gecelca (with an installed capacity of 1,361 MW).

Operations in Peru

Through our subsidiaries, Edegel and EEPSA, we operate a total of 27 generation units in Peru, with a total installed capacity of 1,984 MW. As of December 31, 2015, Edegel owns 18 hydroelectric units, with a total installed capacity of 783 MW, and the remaining 903 MW consists of seven thermal units. EEPSA owns two thermal units with an aggregate installed capacity of 298 MW. On May 6, 2013, the TG 7 unit of Santa Rosa was decommissioned due to fire damage. The damage in the plant resulted in a total loss and the insurance covered both the assets and the business interruption for a period of up two years. On December 5, 2014, the TG 7 unit restarted commercial operations again. During 2015, no new generation units entered operation, but both Edegel and EEPSA adjusted the capacities of some units. Edegel’s hydroelectric plants had their capacities adjusted as follows: Chimay increased by 1 MW, Callahuanca increased by 4 MW, Huinco increased by 21 MW and Moyopampa increased 3 MW. Edegel also adjusted the capacity of some of its thermal plants as follows: Santa Rosa increased by 6 MW and Ventanilla was reduced by 1 MW. The capacity of EEPSA’s Malacas plant was also increased by 1 MW in 2014.

According to the Energy and Mining Investment Supervisory Authority (“Osinergmin” in its Spanish acronym) , the Peruvian regulatory electricity authority, our hydroelectric and thermal generation plants in Peru represented 20.7% of the country’s total electricity generation capacity as of December 31, 2015.

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

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

ELECTRICITY GENERATION IN PERU (GWh)


	Year ended December 31,
	2015				2014				2013
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (Edegel)		4,653		52.9		4,439		49.0		4,474		52.7
Thermal generation (Edegel and EEPSA)		4,148		47.1		4,623		51.0		4,014		47.3

Total generation		8,801		100		9,062		100		8,489		100

According to the Committee of Economic Operation of the Peruvian System (“COES” in its Spanish acronym), we generated 20.4% of total Peruvian electricity production in 2015.

Hydroelectric generation represented 52.9% of total production of our Peruvian generation subsidiaries in 2015. In the case of Edegel, hydrological levels were at or above their historical averages in 2015 in the rivers

that supply Edegel’s hydroelectric power plants. According to COES, hydrological levels of the Rimac River Basin (Huinco, Matucana, Callahuanca, Moyopampa and Huampaní) were 5% higher than the average; hydrological levels of the Tulumayo River (C.H. Chimay) were 2.4% lower than the average; and hydrological levels of the Tarma River (C.H. Yanango) were 2.9% lower than the average.

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

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

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


	Year ended December 31,
	2015				2014				2013
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		8,801		94.8		9,062		91.4		8,489		89.4
Electricity purchases		482		5.2		854		8.6		1,009		10.6

Total		9,283		100		9,916		100		9,497		100

(1)	Includes sales to distribution companies without contracts.

The Peruvian National Interconnected Electric System (“SEIN”) is the only interconnected system in Peru. Electricity sales in the SEIN increased by 6.6% in 2015 compared to 2014, amounting to 39,937 GWh.

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

EDEGEL’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,

2015

2014

2013

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales⁽¹⁾

7,971

92.3

8,719

93.6

7,892

88.6

Non-contracted sales

662

7.7

601

6.4

1,011

11.4

Total electricity sales

8,633

100

9,320

100

8,903

100

(1)	Includes sales to distribution companies without contracts.

Edegel’s electricity sales decreased by 7.4% in 2015 compared to 2014, mainly due to reduced mining activities by one of Edegel’s principal customers, resulting in reduced energy consumption. In 2015, sales to unregulated customers represented 43.2% of Edegel’s total contracted sales. During 2015, Edegel had nine regulated customers and seventeen unregulated customers.

For the year ended December 31, 2015. Edegel’s principal distribution customers were (ordered alphabetically): Edelnor (our subsidiary), ElectroSur, Electrosureste, Hidrandina, Luz del Sur and Seal. Edegel’s principal unregulated customers were (ordered alphabetically): Compañia Minera Casapalca, Creditex, Hudbay Perú, Minera Chinalco Perú, Minera La Arena and Refinería Cajamarquilla.

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

In 2015, EEPSA had contracts with seven regulated customers and four unregulated customers. Sales to regulated customers represented 90.2% of EEPSA’s total contracted sales.

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

EEPSA’s ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

Year ended December 31,

2015

2014

2013⁽¹⁾

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Sales

% of Sales
Volume

Contracted sales⁽²⁾

597

91.8

498

83.6

594

100

Non-contracted sales

8.2

16.4

—

Total electricity sales

650

100

596

100

594

100

(1)	Sales from April 2013 to December 2013.

(2)	Includes sales to distribution companies without contracts.

For the year ended December 31, 2015, EEPSA’s principal distribution customers were (ordered alphabetically): Edelnor and Luz del Sur.

Our most significant competitors in Peru are: Enersur (GDF-Suez group, with an installed capacity of 1,248 MW), Electroperú (a state-owned competitor, with an installed capacity of 911 MW), Kallpa (Inkia Energy group, with an installed capacity of 1,060 MW), Egenor (Duke Energy group, with an installed capacity of 622 MW) and Fenix (Fenix Power Peru group, with an installed capacity of 570 MW).

Electricity Transmission

CIEN

Our electricity transmission operations are conducted through CIEN, a wholly-owned subsidiary of Enel Brasil, in which we hold an 84.4% economic interest. CIEN consolidates CTM and TESA, which operate the Argentine side of the interconnection line between Argentina and Brazil. In 2015, CIEN represented 1.0% of our operating revenues and 2.4% of our operating income. Since April 2011, CIEN has been recognized by the local authority as a “regulatory asset” and as part of the Brazilian grid, and therefore, it is entitled to receive fixed payments called Permitted Annual Compensation (RAP).

CIEN enables the energy integration of Mercosur, as well as the import and export of electricity between Argentina, Brazil and Uruguay. It has two transmission lines covering a distance of 500 kilometers between Rincón in Argentina and the Santa Catarina substation in Brazil, with a total installed capacity of 2,100 MW. CIEN operates each transmission line under a 30-year concession granted by the Brazilian government that will be in force until 2020 and 2022 respectively. Its subsidiaries, CTM and TESA, have concessions for 87 and 85 years granted by the Argentine government, respectively, and both expire in 2087.

Electricity Distribution Business

Our electricity distribution business is conducted in Argentina through Edesur, in Brazil through Ampla and Coelce, in Colombia through Codensa, and in Peru through Edelnor. For the year ended December 31, 2015, electricity sales increased by 1.6% compared to 2014, totaling 62,838 GWh. For more information on energy sales by our distribution subsidiaries for the last five fiscal years, see “Item 3. Key Information — A. Selected Financial Data”.

Edesur (Argentina)

Edesur is one of the largest electricity distribution companies in Argentina in terms of energy purchases. Edesur operates in a concession area of 3,309 square kilometers in the south-central part of the Buenos Aires metropolitan area, serving approximately 2.5 million customers, under a 95-year concession granted by the Argentine government that will be in force until 2087. Our economic interest in Edesur is 71.6%. As of December 31, 2015, residential, commercial, industrial and other customers, primarily public and municipal, represented 45%, 24%, 8% and 23%, respectively, of Edesur’s total energy sales. In 2015, its energy losses were 12.3%, compared to 10.8% in 2014.

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


		Year ended December 31,
		2015			2014			2013
Electricity sales (GWh)			18,492			17,972			18,137
Residential			8,284			7,907			7,845
Commercial			4,489			4,485			4,432
Industrial			1,393			1,363			1,420
Other customers⁽¹⁾			4,326			4,217			4,440
Number of customers (thousands)			2,479			2,464			2,444
Residential			2,174			2,160			2,140
Commercial			273			270			270
Industrial			21			23			23
Other customers			11			11			11
Energy purchased (GWh)⁽²⁾	��		21,084			20,174			20,334
Total energy losses (%)⁽³⁾			12.3	%		10.8	%		10.8	%

(1)	The figures for other customers include tolls.

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

(3)	Energy losses are calculated as the percent difference between energy purchased and energy sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical losses.

For the year ended December 31, 2015, Edesur’s principal unregulated customers were (ordered alphabetically): Abbott Laboratories Argentina S.A., American Express, Arcor, Cencosud S.A., Gas Lanus S.A., Jumbo Retail S.A., Metalcris S.A., Petrobras Energía S.A., Pfizer S.R.L., Pluspetrol S.A., Praxair Argentina S.R.L, Telefónica Argentina S.A and Walmart Argentina.

In 2015, the collection rate from customers was 99.26%, compared to 99.98%, in 2014.

During 2015, Edesur maintained the distribution of energy in Buenos Aires and complied with the year’s investment plan that was presented to the Argentine government. This decision was made despite the delay in the Integral Tariff Revision (“RTI” in its Spanish acronym) process carried out by the Electricity National Regulatory Agency (“ENRE” in its Spanish acronym), that will enable an increase in its tariffs due to higher costs in its services provided and, therefore, ensure the viability of Edesur’s operations. During 2014, Edesur

continued its negotiations with the Argentine government to ensure compliance with the “Agreement for Renegotiation of Concession Contract,” which includes the adjustment of Edesur income in proportion to costs and the definition of a fair and reasonable fee in an RTI process through the formulation of an integral agreement or equivalent alternative, that would meet these objectives and, in addition, ensure Edesur investments and operations for 2014 and 2015.

The Argentine Secretary of Energy, through Resolution No. 32/2015 (enacted on March 13, 2015), decided to approve a temporary revenue increase for Edesur retroactively effective from February 1, 2015. The additional revenue can only be used to pay for the energy it acquires from the electricity market, wages and supplies of goods and services. Like the PUREE funds, funds from the application of Resolution No. 32/2015 are recognized and considered as part of Edesur’s income. The revenue increase is due to the difference between a theoretical rate schedule and the current rate schedule for each category of users, according to calculations by ENRE, in order to not move the rate but instead it will be covered by fund transfers from the CAMMESA in order to compensate for the delay in the application of the RTI, which still does not have a completion date set.

On June 29, 2015, the Argentine Secretary of Energy issued Note No. 1,208 which instructed CAMMESA how to calculate the debts accrued through January 31, 2015 that Edesur has with the Wholesale Electricity Market (MEM), and how to calculate compensation claims arising from the application of MMC. As a result, approximately Ch$ 27 billion of net income of was recognized in 2015.

On June 24, 2014, the Argentine Secretary of Energy, through Note No. 4012/2014, authorized CAMMESA to sign a contract with Edesur and Edenor S.A. to fund higher salary costs due to the application of Resolution ST No. 836/2014.

For further details regarding regulation, see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework Development.” For further details regarding the financial impact, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 2. Analysis of Results of Operations for the years ended December 31, 2015 and 2014 — Distribution Business: Revenues.”

Ampla (Brazil)

Ampla is the second largest electricity distribution company in the State of Rio de Janeiro, Brazil in terms of number of customers and annual energy sales. As of December 31, 2015, we held a 92% economic interest in Ampla. Ampla is mainly engaged in the distribution of electricity to 66 municipalities located in the State of Rio de Janeiro, and serves almost 3 million customers in a concession area of 32,615 square kilometers, with an estimated population of 8.0 million. Ampla operates under a 30-year concession granted by the Brazilian government and it will remain in force until December 2026. As of December 31, 2015, residential, commercial, industrial and other customers represented 41%, 19%, 7% and 33%; respectively of Ampla’s total sales of 11,547 GWh (self supply and energy losses are excluded). In 2015, its energy losses were 20.9%, compared to 20.3% in 2014.

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


	Year ended December 31,
	2015			2014			2013
Electricity sales (GWh)		11,547			11,678			11,025
Residential		4,715			4,754			4,512
Commercial		2,187			2,232			2,133
Industrial		872			970			918
Other customers⁽¹⁾		3,773			3,721			3,462
Number of customers (thousands)		2,997			2,875			2,801
Residential		2,697			2,607			2,536
Commercial		175			172			171
Industrial		5			5			5
Other customers		120			92			90
Energy purchased (GWh)⁽²⁾		14,591			14,647			13,770
Total energy losses (%)⁽³⁾		20.9	%		20.3	%		19.9	%

(1)	The data for other customers includes tolls.

(2)	During 2015, 0.5% of the electricity purchased was acquired from Cachoeira Dourada, 0.4% in 2014 and 0.4% in 2013.

(3)	Energy losses are calculated as the percent difference between energy purchased and energy sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical losses.

In 2015, the collection rate from customers was 97.5%, compared to 98.8% in 2014.

For the year ended December 31, 2015, Ampla’s main unregulated customers were (ordered alphabetically): Anglo Ferrous Minas-Rio Mineral, Braskem Petroquimica, Lafarge Brasil, LLX Minas-Rio Logistica, MAN Latin America, Michelin, Petrobras, Peugeot, Rio Polimeros S.A. and Votorantim.

Under Concession Contract No. 05/1996, which regulates the electricity distribution in Ampla’s concession area, Ampla is subject to a comprehensive tariff review by ANEEL every four years. Ampla underwent its third comprehensive tariff review effective as of March 15, 2014. For this review, ANEEL reduced the Weighted Average Cost of Capital (“WACC”) from 9.95% to 7.50%, net of taxes, which affected income and reduced the recognized operating costs. These modifications resulted in an average tariff reduction of 2.6% effective as of March 2014. This result was detailed in Technical Note No. 12/2014-SRE/ANEEL.

On March 10, 2015, ANEEL approved Ampla’s new tariff, which became effective on March 15, 2015. The average increase perceived by consumers was 42.2%. Low voltage customers had an average increase of 36.4% and medium voltage customers increased by an average of 56.2%. The main causes of these adjustments are the increased CDE (Energy Development Account surcharge), which represents approximately 30% of the 42.2% average increase. Price increases for purchased electricity represented approximately 10% of the total increase.

Coelce (Brazil)

Coelce is the sole electricity distributor of the State of Ceará, located in northeastern Brazil. Coelce serves over 3.8 million customers within a concession area of 148,825 square kilometers, under a 30-year concession granted by the Brazilian government, which will remain in force until May 2028. Residential, commercial,

industrial and other customers represented 35%, 20%, 21% and 24%, respectively, of Coelce’s total energy sales. In 2015, its energy losses were 13.7%, compared to 12.8% in 2014.

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


	Year ended December 31,
	2015			2014			2013
Electricity sales (GWh)		11,229			11,165			10,705
Residential		3,959			3,940			3,703
Commercial		2,148			2,076			1,951
Industrial		1,196			1,206			1,169
Other customers⁽¹⁾		3,925			3,942			3,881
Number of customers (thousands)		3,758			3,625			3,500
Residential		2,865			2,802			2,720
Commercial		232			230			223
Industrial		7			7			7
Other customers		654			587			550
Energy purchased (GWh)		13,016			12,806			12,246
Total energy losses (%)⁽²⁾		13.7	%		12.8	%		12.6	%

(1)	The data for other customers includes tolls. During 2015, 23% of the electricity purchased was acquired from Fortaleza, 21% in 2014 and 22% in 2013.

(2)	Energy losses are calculated as the percent difference between energy purchased and energy sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical losses.

For the year ended December 31, 2015, Coelce’s main unregulated customers were (ordered alphabetically): Durametal, Esmaltec, Gerdau, Grandene, Lojas, Mecesa, Norsa Refrigerante, North Shopping, Petrobras, Vicunha Textil and Votorantim.

In 2015, the collection rate from customers was 97.5% compared to 98.2% in 2014.

On February 27, 2015, ANEEL approved the Extraordinary Tariff Review for 58 distribution companies, including Coelce. The average increase perceived by consumers was 23.4%. The review amortized increased CDE fees, rising energy costs and the energy auctions of 2014 and 2015. In the case of Coelce, final consumer’s tariffs, on average, increased 10.3%, primarily due to the increased CDE fees and increased energy costs. The average effect to be perceived by high voltage consumers was 12.9% and the average effect perceived by low voltage consumers was 9.1%.

On April 4, 2015, ANEEL provisionally approved Coelce’s tariff review which should result in positive financial. According to ANEEL’s decision, the result will be provisional until the final methodology for tariff revisions fourth cycle is defined. The application of the new methodology will be considered in the 2016 tariff adjustment process.

The most important points of the tariff review are the recognition of higher operating costs recognition, the approval of the Regulatory Remuneration Base and the change of WACC. Including the tariff adjustment that occurred in March 2015, the average rate increased to be perceived by consumers should be 11.7%. The new rates have been in effect since April 22, 2015.

Codensa (Colombia)

Codensa is a Colombian electricity distribution company that serves a concession area of 14,456 square kilometers in Bogotá and other 96 municipalities of the provinces of Cundinamarca, Tolima and Boyacá, with approximately 2.9 million customers. As of December 31, 2015, we held a 48.4% economic interest in Codensa, which we control through Chilectra Américas and consolidate pursuant the ownership of 57.2% of Codensa’s voting rights along with a shareholder agreement. For more information regarding the control and consolidation of Codensa, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

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

Since 2001, Codensa only services regulated customers. The unregulated market is serviced directly by our generation company, Emgesa, with the exception of the public lighting in Bogotá. In 2015, its energy losses were 7.3%, compared to 7.2% in 2014.

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


	Year ended December 31,
	2015			2014			2013
Electricity sales (GWh)		13,946			13,660			13,332
Residential		4,665			4,575			4,491
Commercial		2,280			2,213			2,152
Industrial		1,011			931			862
Other customers⁽¹⁾		5,990			5,941			5,827
Number of customers (thousands)		2,865			2,772			2,687
Residential		2,543			2,459			2,381
Commercial		273			265			259
Industrial		45			44			44
Other customers		4			4			3
Energy purchased (GWh)⁽²⁾		15,039			14,726			14,351
Total energy losses (%)⁽³⁾		7.3	%		7.2	%		7.0	%

(1)	The data for other customers includes tolls.

(2)	In 2015, 20% of the electricity purchased was acquired from Emgesa, 28% in 2014 and 41% in 2013.

(3)	Energy losses are calculated as the percent difference between energy purchased and energy sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical losses.

For the year ended December 31, 2015, Codensa’s only unregulated customer was Alumbrado Público Distrito Capital Bogotá.

In 2015, the collection rate from customers was 100.5% compared to 100.9% in 2014. Codensa’s ordinary tariff review is currently in progress and it is expected to conclude in 2016.

Edelnor (Peru)

Edelnor is a Peruvian electricity distribution company that operates in a concession area of 1,518 square kilometers under an indefinite concession granted by the Peruvian government. As of December 31, 2015, we held a 75.5% economic interest in Edelnor. It has an exclusive concession to distribute electricity in the northern part of the Lima metropolitan area, as well as some provinces in the Lima region, including Huaral, Huaura,

Barranca and Oyón, and the adjacent province of Callao. As of December 31, 2015, Edelnor distributed electricity to approximately 1.3 million customers, an increase of 3.4% compared to 2014.

As of December 31, 2015, Edelnor had total energy sales of 7,624 GWh, an increase of 3.8% year over year. In 2015, its energy losses were 8.3%, compared to 8.2% in 2014.

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


	Year ended December 31,
	2015			2014			2013
Electricity sales (GWh)		7,624			7,338			7,030
Residential		2,839			2,719			2,634
Commercial		1,688			1,641			1,582
Industrial		1,213			1,220			1,239
Other customers⁽¹⁾		1,884			1,759			1,575
Number of customers (thousands)		1,337			1,293			1,255
Residential		1,266			1,223			1,185
Commercial		42			42			41
Industrial		1			1			1
Other customers		27			27			28
Energy purchased (GWh)⁽²⁾		8,311			7,995			7,653
Total energy losses (%)⁽³⁾		8.3	%		8.2	%		8.0	%

(1)	The data for other customers includes tolls.

(2)	In 2015, 26% of the electricity purchased was acquired from Edegel, Chinango and EEPSA. In 2014, 27% of the electricity purchased was acquired from Edegel and EEPSA, and 37% in 2013.

(3)	Energy losses are calculated as the percent difference between energy purchased and energy sold (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical losses.

For the year ended December 31, 2015, Edelnor’s primary unregulated customers are (ordered alphabetically): Alicorp, APM Terminals, Corporación Celima, Corporación JR Lindley, DP World, Fabrica Peruana de Eternit, Goodyear Peru, G&M Ferrovias S.A., Indeco, Lima Airport Partners, Molitalia and Refineria La Pampilla.

In 2015, the collection rate from customers was 98.7% compared to 99.8% in 2014.

On October 16, 2013, Osinergmin revised Edelnor’s distribution tariff rates for the four year period from November 2013 to October 2017. The new tariff rate was an increase of 1.2% compared to the previous period that ended in October 2013. The VAD will not increase until the new tariff becomes effective in November 2017.

Edelnor has entered into short-term contracts to supply power to the regulated and unregulated markets from 2015 to 2020. In addition, Edelnor has also entered into long-term power supply contracts for the period from 2015 to 2027.

On June 18, 2014, Resolution No. 120-2014-OS / CD (which was enacted on April 14, 2014) was amended, and established the tariff rate and compensation for secondary and complementary transmission systems for the period from May 1, 2014 to April 30, 2015.

Non-Electricity Businesses

Servicios Informáticos e Inmobiliarios Ltda. (Chile)

Servicios Informáticos e Inmobiliarios Ltda. (“SIEI”), a wholly-owned subsidiary, is a business consultancy in technology, information and computer science, telecommunications, data transmission and develops real estate projects in Chile. SIEI was formed following the merger of ICT Servicios Informáticos Ltda. with Inmobiliaria Manso de Velasco Ltda.

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 operate.



		Argentina	Brazil	Peru	Colombia

Gx	Unregulated Market	Regulated remuneration scheme (Resolution No. 482/2015)	Spot markets with prices defined by the regulator	Spot markets with costs audited by the regulator	Spot market with auctioned cost (Price-offered)
	Regulated	Seasonal Price	Auction Thermal - 20 years / Hydro - 30 years	Auction up to 20 years and node price	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”)

Dx	Law	Concession contract		Administrative Concession (indefinite)	Authorization Operation Zone
	Expansion	95 years	30 years	Undefined
	Tariff review	5 years	4/5 years	4 years	5 years

Cx	Unregulated customers	> 0.03 MW	> 0.5 MW to 3MW/ NCRE >0.5MW/conventional	> 0.2 to 2.5 MW optional >2.5 MW mandatory	> 0.1 MW
Cx	Unregulated market (%)	≈ 20%	≈ 25%	≈ 45%	≈ 30%


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

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 two 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, through special transactions.

On March 26, 2013, the Argentine Secretary of Energy published Resolution No. 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 and cross-border hydro generation.

•

CAMMESA, the market operator, became the single buyer/seller for the fuel needed for plant operations. This implies that market agents are not allowed to trade fuels.

•

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

•

Generators began to receive a regulated remuneration, which should cover fixed and variable costs plus additional remuneration.

The transmission sector is regarded as a public service, operating under monopoly conditions and is comprised of several companies to whom the Argentine government grants concessions. One concessionaire operates and maintains the highest voltage facilities and eight concessionaires operate and maintain high and medium voltage facilities, to which generation plants, distribution systems and large customers are connected. The international interconnected transmission systems also require concessions granted by the Argentine Secretary of Energy. 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 Secretary 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 (an unrelated 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.

Among customers, there are the regulated customers that are supplied by distributors at regulated tariffs and the large customers, who are classified into three categories: major large customers, minor large customers and private large customers. Each of these categories 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 directors and two acting directors through the Argentine Association of Electric Power for Large Customers. Since 2013, due to Resolution No. 95/2013, large customers buy electricity directly from CAMMESA, following the expiration of their bilateral contracts directly with generators.

There is one interconnected system, the Argentine NIS, and smaller systems that provide electricity to specific areas. According to the Argentine National Institute of Statistics and Census (Federal Planning Ministry provisional data of 2014), 99.4% of the energy required by the country is supplied by the Argentine NIS and only 0.6% is supplied by isolated systems.

Principal Regulatory Authorities

The Argentine Ministry of Energy and Mining, 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 Argentine National Regulatory Authority for the Energy Sector (“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 distribution companies operating under a national concession. In the case of Edesur, on July 12, 2012, ENRE appointed an overseer, originally for 45 business days, a term that was extended for successive periods of the same duration, in order to monitor and actively control management of Edesur. ENRE Resolution No.243/2013 increased the term from 45 to 90 business days and it has been extended by successive 90 day-terms and may be extended further.

The principal functions of the CAMMESA are the coordination of dispatch operations, the establishment of wholesale prices and the administration of economic transactions made through the Argentine NIS. 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 Argentine NIS 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 Argentine 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 Secretary 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 branches of the Argentine government.

The Electricity Law

General

The Argentine electricity industry was originally developed by private companies. As a result of service problems, the Argentine 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 government-owned corporations were created within this framework in order to carry out various hydroelectric and nuclear projects.

As a result of the electricity shortage in 1989, the following laws were passed starting in 1990: Law 23,696 (“State Reform”), Law 23,697 (“Economic Emergency”) and Law 24,065 (“Electricity Framework”). The objective of the new legislation 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 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. Most recently, Law 27,200 enacted on November 2015, further extended the measures until December 31, 2017.

The Argentine Secretary 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 No. 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 No. 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 per MWh, which was valid until the adoption of Resolution No. 95/2013 (March 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) plus a margin of Ar$ 2.5 per MWh, according to the Resolutions No. 6,866/2009 and No. 6,169/2010, that came into effect in May 2010. The generators that have adopted Resolution No. 95/2013 are remunerated according to such resolution and later by Resolution No.529/2014 and Resolution No. 482/2015.

The Argentine government has avoided increases 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 of the Argentine peso against the U.S. dollar.

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 Secretary of Energy. To overcome this imbalance, the Argentine Secretary of Energy — through Resolution No. 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. However, since 2013, generators that have adopted Resolution No. 95/2013 collect most of their income through CAMMESA.

The Argentine government had intentions to gradually reverse 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 customers, and has not expanded to other customers. For further details, see “— Sales to Distribution Companies and Certain Regulated Customers” below.

In order to enhance the energy supply, the Argentine Secretary of Energy created different schemes to sell “more reliable energy.” Resolution No. 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.

SE Resolutions No. 220/2007 and 724/2008 gave thermal generators the opportunity to reduce some of the adverse effects of Resolution No. 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 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 No. 406/2003. Generators with a CCAM can supply energy to CAMMESA for up to 36 months, renewable only for an additional six-month period.

During 2009, Resolution No. 762/2009 created the National Hydroelectric Program to promote the construction of new hydroelectric 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 the 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 since 2005 that have permitted the Argentine government and generators to sign contracts for the incorporation of new generation plants and/or maintenance of existing plants to guarantee the availability of the units. On August 24, 2012, the Argentine government informed electricity sector companies that it would reform the Argentine MEM and end the marginal price 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 has more information and control over (i) the profitability of companies, (ii) the quality of service, and (iii) the supply of fuels through CAMMESA, which is 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). Therefore, while generation companies will not pay for fuel, reducing their operating costs, they are not compensated for this expense in their prices, also reducing part of their revenues and changing the method employed to record revenues and operating costs.

The Argentine Secretary of Energy published Resolution No.95/2013, Resolution No. 529/2014 and Resolution No. 482/2015, in 2013, 2014 and 2015, respectively, which established a new remuneration scheme for all generation companies except for biomass/biogas, hydroelectric plants, nuclear plants and blocks of energy commercialized through energy contracts regulated by the Secretary of Energy. The remuneration scheme is based on average costs for generation companies, in contrast with the previous marginal price system. The new scheme establishes payments for fixed and variable costs depending on the type of technology, whether it be

hydroelectric, thermal (gas turbine, steam turbine, combined cycle), internal combustion motor generators, wind, solar photovoltaic, biomass/biogas, as well as the size of the plant (small, medium or large units) separated by their technology and the type of fuel used (natural gas, fuel oil/gas oil, biofuels or coal). The generation companies received payments defined by Resolution No. 95/2013 from February 2013 until January 2014. From February 2014 until January 2015, generation companies received payments according to Resolution No. 529/2014. Since February 2015, generators have received payments according to Resolution No. 482/2015, which increased the amounts in order to compensate them for inflation effects. Resolution No. 482/2015 also includes the recognition of non-recurring maintenance costs for hydroelectric generation plants, and incorporates a new payment to finance new electric project investment.

The impact of Resolution No. 482/2015 has been favorable for generators in 2015 due to higher revenues received than those under Resolution No. 529/2014, leading to greater cash flows. However, the future effect of this regulation will depend on the remuneration values constantly being updated by the Argentine Secretary of Energy.

The increases in the payments to generators due to Resolution No. 482/2015, as compared to Resolution No 529/2014 are summarized as follows:

•

28% increase in the fixed cost recognition for combined cycle gas turbines, CCGTs and hydroelectric plants.

•

23.5% and 23% increase in the variable cost recognition for CCGTs and hydroelectric plants.

•

25% and 10% increase in the additional remuneration in CCGTs hydroelectric plants, respectively.

•

18% increase in the non-recurring maintenance remuneration in hydroelectric plants, which before with Resolution No. 529/2014 did not receive this payment.

•

Create a charge intended to finance new investment projects during 2015-2018, called 2015-2018 FONINVEMEM charge (Cargo Foninvemem 2015-2018).

On July 2, 2015, El Chocón, Costanera and Dock Sud signed the “Agreement to manage and operate projects, increase thermal generation availability and adjust the remuneration for energy generated”. El Chocón, Costanera, Dock Sud and other companies decided to participate in an 800 MW combined-cycle gas turbine power plant project. The agreement states that the project will be funded with the receivables of the 2015-2018 FONINVEMEM remuneration and with a remuneration trust that was not used for other purposes, which is accrued between February 2015 and December 2018. Both the Secretary of Energy and the generators’ agents reserved the right to terminate this agreement if the respective complementary agreements were not signed within 90 days. To date there has been no further progress in the signing of the complementary agreements. Therefore, the contract is no longer valid.

Part of the additional remuneration set in Resolution No. 95/2013, adjusted by Resolution No. 529/2014 and Resolution No. 482/2015, went into a trust for the execution of works in the electricity sector. Resolution No. 95/2013 states that the payment deposited to the trust is not subject to any deduction or discount, and that the Secretary of Energy will define the mechanism under which the receivables collected by CAMMESA due to Resolution No. 406/2003 will be utilized.

Generators, including our subsidiaries, have the option to invest in new capacity, which can be financed with accruals of the trust. Costanera and El Chocón signed an agreement to install four new 9 MW generating units in Costanera. The investment of approximately US$ 44 million was financed with El Chocón’s Additional Remuneration Trust accruals. Resolution No. 482/2015 incorporated the payment values for this technology, generating units, that was not previously defined. The four generating units are expected to begin their commercial operation during the second quarter of 2016.

On December 16, 2015, the National Executive Branch enacted the Decree No. 134/2015, which declared a state of emergency for the National Electricity sector until December 31, 2017 and instructed the newly-created Ministry of Energy and Mining to prepare and implement a national program to improve the quality and safety of the electrical supply and guarantee that it is provided under the best technical and economic conditions.

FONINVEMEM

Resolution No. 712/2004 created FONINVEMEM, a fund whose purpose is to increase electricity capacity/generation within the Argentine MEM. Pursuant to Resolution No. 406/2003, the Argentine Secretary 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 No. 406/ 2003 from January 1, 2004 to December 31, 2006. CAMMESA was appointed to manage FONINVEMEM.

Pursuant to Resolution No. 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 No. 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 No. 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 Secretary of Energy issued Resolution No. 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 (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, as its principal objectives.

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 Secretary of Energy signed an agreement with several generation companies, including our 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: (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, our 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 theVuelta de Obligado thermal plant

(“VOSA”); (iii) determine a mechanism to pay the generators’ sales settlements with maturity dates to be determined (“LVFVD”), which represent generators’ claims for the period from January 1, 2008 to December 31, 2011. These contributions shall be returned with the interests and converted into U.S. dollars at the date of VOSA’s completion, considering the exchange rate existing as of the date on which the agreement was signed; 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 VOSA was entered into among General Electric Internacional Inc., General Electric Internacional Inc. Argentina branch, and the Argentine Secretary of Energy.

The project also includes the expansion of theRío Coronda 500 kV transformer station which connects to the 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. On December 3, 2014, VOSA started to operate its open cycle, with a capacity of 540 MW. Total installed capacity is expected to reach approximately 800 MW in 2016.

Limits and Restrictions

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

Vertical Integration Restrictions

The vertical integration restrictions apply to companies that intend to participate simultaneously in different sub-sectors of the electricity market. These vertical integration restrictions were imposed by Law 24,065 (“Electricity Framework”), 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.

Regulation of Generation Companies

Concessions

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

Such concession holders have the right to: (i) take control of the private properties within the concession area (subject to general laws and local regulations) that are necessary to create reservoirs as well as underground or above ground supply-line and release channels, (ii) flood lands that are necessary to raise water levels, and (iii) request 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 fuels such as diesel are purchased to meet demand due to the lack of supply of natural gas.

The introduction of Resolution No. 95/2013 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 (see — Argentina — Industry Overview” and “— Regulatory Developments: the Industry After the Public Emergency Law”).

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 No. 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.

As a result of Decree No. 134/2015, which declared a state of emergency for the Argentine Electricity sector, the Ministry of Energy and Mining enacted Resolution No. 6/2016 on January 27, 2016, that changed the seasonal price between February 2016 and April 2017 for the MEM. The seasonal price was calculated based on the operational programming, dispatch and price calculations. This resolution allowed prices to reflect the actual energy cost, reducing the subsidies and creating differentiated prices for the residential customers based on their efficient energy usage. This is the first step towards the reconstitution of market conditions.

Stabilization Fund

The stabilization fund, managed by CAMMESA, was created to absorb the difference between purchases by distributors at seasonal prices and payments to generators for energy sales at the spot price. When the spot price is lower than the seasonal price, the stabilization fund increases 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 Secretary of Energy based on CAMMESA’s recommended seasonal price level for the next period according to its estimated spot price. CAMMESA estimates this price by evaluating its expected supply, demand and available capacity, as well as other factors. The seasonal price is maintained for at least 90 days. Since 2002, the Argentine Secretary 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 begin a process to reduce subsidies to gas, electricity and water tariffs. These resolutions provide for, among other things (i) the 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 per MWh to Ar$ 320 per 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 of Distribution Companies

Concessions

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

Energy Purchases

Through SE Resolution No. 2,016/2012, the Argentine Secretary of Energy approved seasonal prices for the period from November 2012 to April 2013. The resolution sets a sole monomic price (combining both energy and capacity prices) to value all purchases on the Argentine MEM by every distributor in the country and established the regulatory combining bodies and/or authorized entities that are responsible for instructing the distributors in their jurisdiction so that the distributors may correctly apply the seasonal reference prices to their respective price tables.

Distribution Tariff-Setting Process

Distribution under national jurisdiction and transmission companies have been renegotiating contracts since 2005 and although tariffs were partially and temporarily established, definitive tariffs are still pending. As a result, although the terms to define energy prices pursuant to the Argentine Electricity Act are still in force, their implementation reflects the measures taken by the authorities that reduce compensation for all electricity companies. On the other hand, distribution companies under provincial or municipal jurisdiction have seen their tariffs adjusted by local authorities.

During 2006, our subsidiary Edesur and Edenor (not related to us), the largest Argentine distributors, entered into the “Agreement for Renegotiation of Concession Contract.” This agreement established, among other things, (i) a transitional tariff regime contingent on the quality of service; and (ii) an Integral Rate Revision Process (“RTI” in its Spanish acronym) to be implemented by ENRE according to Law 25,561 that would set the conditions for a new tariff regime for a five-year period. In December 2009, Edesur presented to ENRE its tariff proposal pursuant to the RTI process and also submitted support studies in accordance with the requirements established by ENRE Resolution No 467/2008. This presentation only included the income requirements and did not include rate proposals, which were later presented to ENRE in May 2010. As of the date of this Report, ENRE has not defined new tariffs and the transitional tariff regime remains in effect.

Resolution 45/2010 of the Argentine Secretary of Energy determined bonus payments to residential customers under the Energy Efficiency Program (“PUREE” in its Spanish acronym), particularly to those with a demand that is less than 1,000 kWh during a two month period. PUREE was created in 2004 and established bonuses and penalties to customers depending on the level of energy savings. The net difference between the bonuses and penalties was originally deposited to the stabilization fund but this was subsequently modified at the request of Edesur and Edenor. The Argentine Secretary of Energy authorized Edesur and Edenor to use all of such amounts to compensate for the cost variations that were not passed on to the tariffs paid by regulated customers.

Edesur’s and Edenor’s distribution tariffs have been remained unchanged since July 2008. Combined with a constant increase in costs due to inflation, this has left Edesur in a very delicate financial position. As a result, Edesur made a request in July 2012 for a special payment plan for energy purchases to CAMMESA.

In 2012, the Argentine Secretary of Energy issued Note No. 3,787/2012 in order to facilitate financing for necessary investments to the distribution system. The resolution authorized CAMMESA to provide financing for high voltage projects in 2012 investment plan pursuant to the mechanism in Resolution No. 146/2002.

At the end of 2012, the ENRE issued ENRE Resolution No. 347/2012 titled “Trust for Financing Distribution Works” (“FOCEDE” in its Spanish acronym). The resolution mandated the formation of a trust with funds collected from customers’ payments in order to finance necessary investments in infrastructure, including any maintenance works to be carried out in the concession area. The funds collected from customers are to be differentiated depending on customer category and will be taken into consideration by the ENRE when it carries out the RTI process. The trust contract and its operative manual agreement were signed by Edesur on November 29, 2012 and December 18, 2012, respectively.

On May 7, 2013, the Argentine Secretary of Energy approved Resolution 250/2013 which defined the residual value of the MMC funds that are owed to Edesur and Edenor, allowing the compensation of costs and other debts that Edesur and Edenor accrued with the funds collected under the PUREE program. The resulting balance is allocated to the FOCEDE. The Argentine Secretary of Energy has retained the power to extend, either partially or entirely, the provisions of the Resolution No. 250/2013 on the basis of the information received from ENRE and from CAMMESA. This compensation mechanism is not recurrent but it was utilized several times during 2013 and 2014 by the following Argentine Secretary of Energy Notes: i) on November 6, 2013, Note No. 6852 authorized compensation for the period of March 2013 through September 2013; ii) on June 6, 2014 Note

No. 2361/14 authorized compensation for the period of October 2013 through March 2014; iii) on October 9, 2014 Note No. 0486, authorized application of Resolution No. 250/2013 for the period of April 2014 through August 2014; and iv) on December 18, 2014 Note No. 1136 authorized compensation for the period of September 2014 through December 2014.

On June 2014, Argentine Secretary of Energy, through the Note No. 4012/2014, authorized CAMMESA to provide funds to Edesur and Edenor to finance their higher personnel costs due to the application of ST Resolution No. 836/2014

On March 13, 2015, SE Resolution No. 32/2015 was issued, which permitted Edenor and Edesur, to recognize temporary higher revenues to finance their higher costs of energy purchases in the spot market, salaries and procurement. This increase is to be offset with RTIs, which have not been defined yet and will be with CAMMESA funds. In addition, Resolution No. SE 32/2015 permits Edenor and Edesur to recognize funds from PUREE as their own income, and validated the cost recognition and compensation method until March 2015 as stated in SE Resolution No. 250/2013. It also instructed CAMMESA to provide LVFVD for the amounts defined by ENRE for the higher personnel costs due to the application of ST Resolution No. 836/2014. Lastly, it addresses the payment of amounts owed to MEM, through a payment plant which is still undefined.

The SE Resolution No. 32/2015 represents the first step toward the improvement of the financial conditions of Edesur and Edenor, although it still provides that the investments continue to be financed by debt with CAMMESA, without solving the amounts owed to MEM neither the tariff adjustments that includes the increase of operational cost. The customer tariffs have not changed since 2008.

In addition, in November 2015, ENRE reported Edesur’s and Edenor’s MMC variations from November 2014 to April 2015 and May 2015 to October 2015 to the Argentine Secretary of Energy. Therefore, the Argentine Secretary of Energy, through Notes 2097 and 2197, increased the temporary revenues as defined in the Resolution No. 32/2015. Note 2158 also increased temporary revenues due to higher personnel expenses during 2014, which were paid during 2015.

On January 28, 2016, following the seasonal price changes, emergency Resolution No. 7/2016 was issued by the Ministry of Energy and Mines. The resolution instructs ENRE to adjust the rates of Edenor and Edesur through a transitory tariff until the RTI begins to apply, which is expected by December 31, 2016. In addition, Resolution No. 7/2016 suspends PUREE and requires the application of a subsidized rate to eligible customers.

On January 29, 2016, ENRE issued Resolution No. 1/2016 with a new transitory tariff, which is on force since February 1, 2016. Its application is according to the MEM Resolution No. 7/2016, which changed supply procedures and defines monthly billing.

In addition, ENRE issued Resolution No, 2/2016, which terminated the FOCEDE and set a new procedure for funds from the ENRE Resolution No. 347/12, replacing Edesur’s and Edenor’s trust with a commercial account.

Penalties

The distributors are subject to three types of penalties:

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

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

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

Regulation in Transmission

The transmission sector is regulated based on the principles established in the Electricity Framework and the terms of the concession granted to Transener S.A. (the main operator of transmission lines in Argentina and a company not related to us) under Decree No. 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.

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 Secretary of Energy adopted additional measures that restricted electricity and gas exports. SE Resolution No. 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 Secretary 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 Enargas Resolution No.1,410 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 as a national interest and set the target at 8% market share for generation from renewable sources within a term of ten years. During 2009, the government took actions to reach this objective by publishing Resolution No. 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, a state owned company engaged in upstream and downstream

activities associated with hydrocarbons and electricity. 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-hydroelectric and 20 MW of solar units. The prices awarded vary from US$ 150 per MWh (for mini-hydroelectric units) to US$ 598 per MWh (for solar units). In 2011, the Argentine Secretary of Energy issued Resolution No. 108/11 which allowed CAMMESA to sign contracts directly with generators of renewable energy on conditions similar to Resolution No. 712/2009.

In October 2015, Law 27,191 “National Development Scheme for the Use of Renewable Energy Sources for the production of Electric Power”, was enacted and defined renewable energy sources as: wind energy, solar thermal, solar photovoltaic, geothermal, tidal, wave, ocean currents, hydroelectric, biomass, landfill gas, gas treatment plants, biogas and biofuels, except for the uses established in Law 26,093. The new capacity limit for hydroelectric plants that qualify under Law 27,191 was changed from 30 to 50 MW. The law establishes that large customers should meet their demand with contracts sourced renewable technologies according to the following values: 8% in 2017, 12% in 2019, 16% in 2021, 18% in 2023 and 20% in 2025. A maximum price of US$ 113.00 per MWh is set for renewable energy contracts in the MEM. The law does not set a specific commitment to distributors. It also establishes a penalty for those who do not comply with the rates contained in Art. 8 to pay a price equal to the variable cost of production of electricity generated with imported diesel fuel for the deficit of contracted renewable energy. Finally, Law 27,191 also establishes incentives for investments: anticipation of the added value tax refund, the application of accelerated depreciation, the creation of a common fund for project financing and import duty exemption.

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). There is also a special mechanism between hydroelectric generators that seek to re-allocate hydrological risk by

offsetting differences between hydroelectric 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 then, all generation concessions were held directly or indirectly by Brazilians or by the Brazilian state.

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 operates under monopoly conditions and is comprised of companies who have been granted concessions. Distributors in the Brazilian NIS are not allowed to: (i) perform 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 with respect to captive customers in the Regulated Market; (iii) hold, directly or indirectly, any equity interest in any other company, corporation or partnership; or (iv) develop activities that are unrelated to their respective concessions, except for those permitted by law 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 No. 5,163/2004 and No. 5,177/2004 of the Electricity Trading Chamber or Clearing House (“CCEE” in its Portuguese acronym), and ANEEL Resolution No. 109/2004, which introduced the Electricity Trading Convention. This convention defines the terms, rules and procedures of the trading in the CCEE. 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.

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 records 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 and are determined weekly for each level of required energy or load and for each sub-market, based on the system’s marginal operating cost, within a minimum and maximum price range.

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 9,427/96, unregulated customers in Brazil are those who currently: (i) have a demand of at least 3,000 kW, generated from conventional sources and purchase their energy directly from generators or traders, but not from distributors or (ii) have a demand in the range of 500 to 3,000 kW, which is generated from NCRE and purchase their energy directly from generators, traders or distributors.

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 month electricity report of

January 2015, (“EPE” in its Portuguese acronym), 99.2% of the energy required by Brazil is supplied by the Brazilian NIS and the remaining 0.8% 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 is in charge of developing the national electricity policy. Its principal responsibilities include advising the President in the formulation of energy policies and guidelines, promoting the stability and secure supply of the country’s energy resources, ensuring the energy supply to the most remote parts of the country, establishing directives for specific programs (such as the use of natural gas, alcohol, biomass, coal and thermonuclear energy) and establishing directives for the import and export of energy.

The Energy Research Company is an entity under the Brazilian MME. Its purpose is to conduct research and studies to support energy sector planning.

ANEEL, the Brazilian National Electric Energy Agency, is the entity that implements the regulatory policies. 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 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 acts as a federal independent organization. It is part of the Ministry of Environment, responsible for the implementation of the National Environmental Policy and the preservation and conservation of natural heritage, exercising control and supervision over the use of natural resources. 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

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

The Concessions Law 8,987 and the Electricity 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 Electricity Sector Law also introduced the concept of independent power producers, (“IPPs”), in order to open the electricity sector to private investments. 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.

Law 9,648/1998 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 cost basis, modeling future operation conditions and setting a merit order curve with variable costs for thermal units and opportunity cost for hydroelectric plants, resulting in one price for each subsystem set for the week subsequent to the determination.

Pursuant to Law 10,433/2002, the wholesale energy market structure is 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 No. 5,163 of July 30, 2004. The principal objectives of these laws and decrees were to (i) guarantee the security of the electricity supply, 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 tariff reasonability, the model contemplates the purchase of electricity by distributors in a regulated environment through tenders carried out at the lowest tariff. As a result, the cost of acquiring electricity to be passed on to captive customers can be reduced. The new model includes electricity benefits for customers who are not yet included in this program, guaranteeing a subsidy for low income customers.

Limits and Restrictions

Regulatory Resolution No. 299/2008 repeals certain sections of ANEEL Resolution No. 278/2000, which established the limits and conditions for the participation of electricity distributors and traders. Specifically, the section of Resolution No. 278/2000 on limits to generation was repealed. Subsequently, Resolution No. 378/2009 establishes new procedures for analyzing mergers and violations of economic regulations in the electricity industry.

Regulation of Generation Companies

Concessions

The Concessions Law provides that, upon receiving a concession, IPPs and customers will have access to the distribution and transmission systems owned by other concessionaires, provided 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 up to 35 years for new generation concessions and up to 30 years for new transmission or distribution concessions. Existing concessions may be renewed at the Brazilian government’s discretion for a period equal to their initial term.

In September 2012, ANEEL’s Provisional Resolution No. 579/2012 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 No. 577/2012 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.

On January 23, 2013, the Brazilian Congress approved Law 12,783, which renewed electricity concessions according to Provisional Resolution No. 579/2013. 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 a maximum of 30 years, for both hydroelectric and thermal plants, which expire between 2015 and 2017.

Dispatch and PLD Pricing

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

The mathematical models used to compute the PLD take into account the preponderance of hydroelectric plants within the Brazilian electricity generation grid. The purpose is to find an optimal equilibrium between the current benefit obtained from the use of 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 any given period and to define both the hydroelectric and thermal power generation for each submarket first considering the demand for electricity, then the hydrological conditions, the prices of fuel, the cost of the deficit, the entry of new projects into operation and the availability of equipment used for generation and transmission. As 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 computational models to calculate the Marginal Operational Cost for each submarket on a monthly and weekly basis.

On November 25, 2014, ANEEL approved new limits for the PLD starting in 2015. The maximum limit decreased from R$ 823 per MWh to R$ 388 per MWh and the minimum increased from R$ 16 per MWh to R$ 30 per MWh. The main purpose of the new limits was to reduce the financial impact of the distributor’s exposure risks to the spot market for future contracted energy, principally as a reaction to the high spot prices in 2014. Also, the new maximum price mitigates risks faced by generators, such as unrecoverable economic and financial exposure when production is under contracted values. However, the possibility of selling surplus energy decreases with higher prices. Currently, generators can plan their surplus energy in order to boost their income by producing more energy in the months where higher prices are expected.

Annually, ANEEL defines new limits for the PLD. In December 2015, the range of the PLD for 2016 was set between R$ 30.25 per MWh to R$ 422.56 per MWh.

Electricity Reallocation Mechanism

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

The mechanism guarantees that notwithstanding the centralized dispatch, all hydroelectric generators that participate in the MRE will have a participation in the overall hydroelectric generation dispatched in proportion to their assured energy, or maximum firm energy, which is the electricity that a hydroelectric generation plant is able to deliver on a continual basis during a year, with poor hydrological conditions for the long term. The final value of the energy allocated to a hydroelectric generator can be greater or less than its assured energy depending on whether the hydroelectric generation is greater or less than the overall hydroelectric assured energy, respectively. This mechanism permits each hydroelectric generator, before buying energy in the spot market to fulfill its contracts, to purchase cheaper energy at a price that covers the incremental costs of operation, the maintenance of hydroelectric plants and the financial compensation for use of water. The tariff used for trading energy in the MRE, the Optimum Energy Tariff, was set as R$ 12.32 per MWh for 2016

As the overall hydroelectric generation is more stable than the individual hydroelectric 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.

In November 2015, as a way of mitigating the impacts of drought, ANEEL approved the conditions for renegotiating hydrological risk with the hydroelectric generators that participate in the MRE, but approval by the Brazilian Senate is still pending.

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 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, Brazilian MME’s Decree No. 455 mandated the creation of a price index and a requirement to register energy contracts ex-ante. The new price index was published in June 2014 and was tested internally over a six-month period before being officially published in the market in December 2014.

Sales by Distribution Companies and Regulated Customers

Pursuant to market regulations, all of distributors’ energy demand must be satisfied through regulated auctions coordinated by ANEEL. There are independent tender processes for the: (i) contracting of existing capacity in order to adjust the conditions of the current contracts or to enter into new power purchase agreements to replace expired agreements and (ii) contracting of new capacity to meet future demand.

Tenders for existing capacity are as follows: (i) A-0 tenders, energy adjustment tenders, for supplementing the energy needed to supply distribution customers in the concession market, with a limit of 1% of the energy needed; and (ii) A-1 tenders, for the acquisition of energy from all existing generation sources with purchase energy agreements of up to five years.

Future energy needs are covered through: (i) A-3 tenders, for the acquisition of energy from new generation sources (usually thermal and NCRE), and include reserve tenders that are also carried out to improve the stability of the system; and (ii) A-5 tenders, for energy purchases from any new generation source to be supplied five years following the tender. Both types of tenders involve purchase agreements ranging between 20 to 30 years

Two tenders were planned for 2012. An A-3 tender for December 12, 2012, was cancelled due to low demand from distributors. An A-5 tender for new energy was held on December 14, 2012. Of the 574.3 MW of total installed capacity available for tender, 303.5 MW were allocated. The average price was fixed at R$ 91.25 per MWh. Of the total energy allocated, 294.2 MW were allocated to two hydroelectric plants (at an average price of R$ 93.46 per MWh) and 281.9 MW were 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 were allocated at average price of R$ 177.22 per MWh; (iv) an A-3 tender with 332.5 MWh

allocated to 39 wind farms at an average price of R$ 124.43 per MWh; (v) an A-5 tender in which 690.8 MWh were allocated (46% hydroelectric plants and 54% biomass thermal plants) at an average price of R$ 124.97 per MWh; and (vi) an A-5 tender in which 1,599.5 MWh (33% hydroelectric plants, 5% biomass thermal plants and 62% wind farms) were allocated at an average price of R$ 109.93 per MWh.

In 2014, an A-0 tender was held on April 30, which resulted in 2,046 MW at an average price of R$ 268 per MWh. An A-3 tender was held on June 6, 2014, and of the 2,744.6 MW energy bid, 418 MW were assigned to the Santo Antonio hydroelectric plant at an average price of R$ 121 per MWh and 551 MW were allocated to 21 wind farms at an average price of R$ 130 per MWh.

In 2015, six tenders took place: (i) one A-1 tender was held in December with 1,954 MW allocated to hydroelectric plants (94%), biomass thermal plants (4%) and gas thermal plants (2%) at average price of R$ 147.8 per MWh; (ii) four A-3 tenders (a) one in April with 97 MWh allocated to biomass thermal plants (70%) and wind farms (30%) at an average price of R$ 200 per MWh; (b) two in August, with 233 MWh allocated to solar power plant at average price of R$ 301.8 per MWh and 314.3 per MWh allocated to wind farms (72%), hydroelectric plants (15%), gas thermal plants (7%) and biomass thermal plants (6%) at an average price of R$ 189 per MWh; and (c) one in November with 508 MW allocated to wind farms (52%) and solar plants (48%) at average price of R$ 249 per MWh; and (iii) an A-5 tender in April in which 1,160 MWh was allocated to gas thermal plants (73%), hydroelectric plants (20%) and biomass thermal plants (7 %) at an average price of R$ 259.2 per MWh.

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

Law 10,438/2002 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 comply with their delivery obligations. ANEEL regulations set forth the fines applicable to electricity agents based on the nature and the materiality of the violation (including warnings, fines, temporary suspension of the right to participate in bids for new concessions, licenses or authorizations and forfeiture). For each violation, fines may be imposed for up to 2% of the concessionaire’s revenues arising from the sale of electricity and services 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 No. 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.

Among other aspects, ANEEL’s Normative Resolution No. 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. 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 of Distribution Companies

Energy Purchases

In the regulated market, electricity distribution companies buy electricity through public annual bids, regulated by ANEEL and organized by CCEE.

There are two types of regulated bids: (i) to contract existing capacity in order to adjust the conditions of the current contracts or enter into new power purchase agreements to replace expired agreements and (ii) to contract new capacity, including renewable electricity (biomass, mini-hydroelectric, solar and wind power), to meet future demand as previously described in “—Regulation of Generation Companies — Sales by Distribution Companies and Regulated Customers.”

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

Distribution Tariffs to End Customers

Distribution tariff rates to end customers are subject to review by ANEEL, which has the authority to adjust and review these tariffs in response to changes in energy purchase costs and market conditions.

Distribution Tariff-Setting Process

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

The Concessions Law establishes three kinds of reviews for end customer tariffs: (i) ordinary tariff review according to the concession contracts of each distributor, (ii) annual inflation adjustments less an “X” factor (a unique value for each distributor which reflects its recent efficiency gains, the management of its operating costs, and its service quality) and (iii) extraordinary tariff reviews.

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

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

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

Ordinary tariff reviews take into account the entire tariff-setting structure for the company, including the costs of providing services and purchasing energy, as well as a return for the investor. The tariff review period is defined by distributors at the time of signing their respective concession agreement. Therefore, in Brazil, some distributors have a period of three years, most have four year periods and some have five year periods. This means the tariff review applies to all distributors, but with different time periods.

Since 2003, ANEEL has carried out periodic tariff revisions every four years, which define the methodology to be applied during ordinary tariff reviews. Until the second cycle of periodic tariff revisions, the methodology was based on regulatory costs for a model company, which considered the special characteristics of each distribution concession area.

In November 2011, ANEEL approved a new methodology for the third cycle of periodic tariff revisions, effective from 2011 to 2014. The main changes were:

•

The values defined in the previous cycle, are adjusted by the variation in the number of customers, consumption and networks, discounting the productivity gains achieved by the distributors based on national electricity benchmarking;

•

A new methodology to estimate the distribution of productivity gains and to maintain the economic and financial balance over the tariff cycle was adopted; and

•

A new incentive mechanism for improving the quality of service was introduced.

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

In June 2014, ANEEL published proposals to change the methodology for the fourth tariff cycle which included modifications to the WACC (proposed reduction from 11.36% to 10.85% real rate pre-tax), the regulatory asset base, the X factor and operating costs. After evaluating the contributions from distributors at Public Hearing 023/2014, ANEEL decided to review the proposed 12.26% WACC. As a result, the WACC increased from 11.36% to 12.26% (real rate pre-tax). The new rate was published in the Normative Resolution No. 648/2015 on March 2, 2015, effective retroactively to February 5, 2015. The methodology of the fourth tariff cycle is being applied to all distributors in their ordinary tariff reviews.

Revenue of Tariff Flags

Since January 2015, ANEEL has applied an additional monthly charge to the customers’ tariffs, whenever the marginal cost of the system is higher than the defined marginal cost. The regulated tariff does not recognize

real costs that are beyond the control of the distributors, such as drought. The regulator’s aim is to provide to the consumer with the real cost of generation, considering the anticipated additional tariff rate to the distributor, as described in the chart below, that otherwise would have in the next annual tariff adjustment review.

This mechanism is composed of three main levels: green, yellow and red. Since its creation, the cost ranges and the additional tariffs have been changing according to new expectations of the marginal cost of generation. On January 26, 2016, ANEEL published its latest modification through Note 16/2016, which established two levels within the red criteria. The modification became effective on February 1, 2016.


	Description	Applies when marginal cost (MC) (R$/MWh)	Additional Tariff Rate (R$/MWh)
Green	Favorable generation conditions	MC<211.28	No additional
Yellow	Less favorable generation conditions	211.28£ MC< 422.56	+0.0015
Red level 1	Less expensive generation conditions	422.56£ MC< 610.00	+0.0030
Red level 2	More expensive generation conditions	610.00£ MC	+0.0045

Energy Development Account, “Cuenta de Desarrollo Energético - CDE”

Created by Law 10,438/2002, the CDE is a government fund that aims to promote the development of alternative energy sources, promote globalization of energy services and subsidizes low-income residential customers. The fund is financed through charges included in consumers and generators tariffs and government contributions.

In September 2015, following a judicial pronouncement that suspended the payment of Embrace Association partners’ CDE charges, ANEEL allocated the lost contribution among other customers. The deficits generated by this loss of charges will be included in the next annual distribution tariff adjustment.

ANNEEL reduced the 2016 budget by 36% due to greater efficiency that allowed a reduction in the charge to customers to finance the energy cost in isolated locations.

Governmental Tariff Reduction Plan (Provisional Resolution No. 579/2012)

On September 12, 2012, the Brazilian government’s Provisional Resolution No. 579/2012 reduced tariffs for end customers and defined new concession renewal policies for generation and transmission companies.

In order to reduce the tariff, the Brazilian government proposed to eliminate two sector charges, the Global Reversal Reserve, which are funds to promote expansion in the electricity sector and to indemnify concessions, and the Fuel Consumption Bill, which is a subsidy to thermal generation companies mainly located in the northern region. It also reduced the CDE by 75%. These charges are compensated directly with funds from the Brazilian government.

In addition, this resolution provides new concession renewal policies for generation and transmission companies, with concession contracts expiring before 2017 (20% of the generation companies). Although existing laws provided for the possibility of renewing such concessions, there was no clear guidance on the terms of the renewed concessions. With the new policy, energy purchases charges will be reduced due to the non-recognition of assets already amortized, and therefore if the concession-holders choose to renew under such terms, then they would only be able to recover costs related to operation and maintenance. Affected companies represent 23 GW of hydroelectric capacity and 85,000 kilometers of transmission lines. Approximately 65% of the affected generation companies and all of the affected transmission companies agreed with the new rules.

Legislation containing Provisional Resolution No. 579/2012 was approved by the Brazilian House of Representatives and was sent to the President of Brazil for signature under Law 12,783/2013. The tariff reduction plan aimed at reducing tariffs to end customers by 20% was passed on January 24, 2013 after an extraordinary tariff review of all distribution companies.

At the beginning of 2013, distributors had a deficit between regulated demand and energy suppliers. They were involuntary forced to buy the required energy to serve their regulated customers at the spot market. Due to this imbalance, on March 8, 2013, Presidential Decree No. 7,945/2013 authorized the pass-through of federal resources to distributors in order for them to pay part of the extra energy costs to which they had been involuntary exposed. The extra energy costs not paid by federal resources were recovered via regulated tariffs in 2014 and 2015 as set forth by regulation of ANEEL, as adjusted by the SELIC interest rate.

In 2014, Decree No. 8,203 authorized the use of the CDE to cover part of the additional costs of distribution companies by involuntary exposure to the spot market. Thus, the decree allows the Treasury to anticipate CDE resources.

Extension of Distribution Concession Contracts

Since September 2012, the distribution concessions under the Law 9,074 /1995 may be extended by Brazilian government, one time, for a period of up to 30 years, in order to ensure continuity, efficient service, feasible rates and profitability for the distributors.

On October 20, 2015, ANEEL approved the draft to supplement the Concession Agreement and recommended the extension of the concessions to the Ministry of Mines and Energy. On December 28, 2015, the government extended the deadline for executing those extensions due to their complexity.

Generated Power Distribution

On November 24, 2015, ANEEL, in a public hearing, approved the regulation of Generated Power Distribution through an energy compensation mechanism. Power generation systems can have capacities up to 3MW for hydroelectric systems and up to 5MW for and other sources.

Regulation in Transmission

Transmission lines in Brazil are usually very extensive, since most hydroelectric plants are usually located far away from the large centers of energy consumption. Today, the country’s system is almost entirely interconnected. Only the states of Amazonas, Roraima, Acre, Amapá, Rondônia and a part of Pará still do not have access 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 electricity system provides for the exchange of electricity among the different regions when any region faces problems, such as a reduction in hydroelectric generation due to a drop in its reservoir levels. As the rain 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 energy production to be supplied by generation centers located in a more favorable location.

Any electricity market agent that produces or consumes energy 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.

Similar to distribution companies, transmission companies also have three tariff reviews: (i) an ordinary tariff review every four years; (ii) annual tariff adjustments due to inflation and the annual allowed revenue (a fixed amount paid by consumers and generators); and (iii) extraordinary tariff review.

Environmental Regulation

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

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, XM, which is in charge of the market central dispatch through the National Dispatch Center (“CND” in its Spanish acronym) and the management of the commercial exchange system through the Commercial Exchange System Authority.

The 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 generation capacities of at least 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 CND.

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

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

Energy spot market: short-term daily market

Bilateral contracts: long-term market; and

“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 poor hydrological conditions. The generator who acquires a Firm Energy Commitment (“OEF” in its Spanish acronym) will receive a fixed remuneration during the commitment period, which is described in “— Incentives and Penalties” section below.

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

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

There is one interconnected system, the Colombian NIS, and several isolated regional and smaller systems that provide electricity to specific areas. According to the Colombian Mining and Energy Planning Agency, 96.8% of the Colombian population in 2014 received electricity through the public network.

Principal Regulatory Authorities

The Colombian Ministry of Mines and Energy (“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 is responsible for planning the expansion of the generation and transmission networks.

The Colombian 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 related to policy development.

The Colombian National Planning Department performs the functions of Executive Secretary of the CONPES and therefore is 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 eight experts named by the Colombian President, the MME, the Colombian Ministry of Public Credit and the director of the Colombian National Planning Department 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 non-discriminatory supply of electricity to all regions and sectors of the country).

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

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

The Commercialization Advisory Committee is an advisory entity which assists CREG with the commercial aspects of the Colombian MEM.

The Colombian Superintendence of Industry and Commerce advises the national government and participates in the formulation of policies to promote competition, protect consumers, and protect industrial

property, among others. It also investigates, corrects and sanctions restrictive commercial competition practices, such as antitrust practices, and oversees mergers of companies operating in the same industries in order to prevent excessive concentration or monopolies in certain industries.

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

The Colombian Ministry of Environment and Sustainable Development (“MADS” in its Spanish acronym) is responsible for the management of the environment and renewable natural resources. It is also responsible for guiding and regulating environmental planning as well as developing policies and regulations. Its goal is to recover, preserve, protect, and promote sustainable use of renewable natural resources, the environment of the nation, and to ensure sustainable development, despite the functions assigned to other sectors.

The MADS, together with the Colombian President, aims to develop national environmental and renewable natural resource policies in order 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 Law 142, known as the Public Utility Services Law, and Law 143, which 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.

In 2014, the Colombian government published Renewable Energy Law 1,715/2014, which promotes the development of renewable energy and energy efficiency projects. The law proposes tax reductions for projects involved with renewable energies. Also, it establishes the development of a national fund that promotes research on related topics and defines the methodology for large and small scale self generation.

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, a measure of market concentration, is at least 1,800,

such company becomes subject to monitoring by the Colombian Superintendence of Domestic Public Services. If an electricity generation company’s share of Colombia’s total Firm Energy exceeds 30%, such company may be required to sell its share exceeding the 25% threshold.

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

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

A distribution company can hold over 25% of an integrated company’s equity if the market share of the latter company accounts for less than 2% of the national generation business. A 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

Under Laws 142 and 143 of 1994 economic activities related to the supply of the electricity service are governed by the constitutional principles of free market economic activity, free market private initiative, freedom to enter and leave the market, corporate freedom, free market competition and private property, with regulation and inspection, surveillance and control by the state.

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

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

Dispatch and Pricing

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

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

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

Additionally, the CND plans for the dispatch, which takes into consideration the limitations of the network, as well as other conditions necessary to satisfy the energy demand expected for the following day in a safe, reliable and cost-efficient manner. The cost differences between the “planned dispatch” and the “optimal dispatch” are called “restriction costs”. The net value of such restriction costs is assigned proportionally to all the traders within the Colombian NIS, according to their energy demand, and these costs are passed through to the end customers. Some generators have initiated legal proceedings against the government arguing that recognized prices do not fully cover the costs associated with these restrictions because current regulations do not take into account all the costs of safe, reliable generation. However, CREG believes that Resolution No. 036/2010 modified the remuneration of hydroelectric plants by assigning the opportunity cost to the spot price, which compensated for these costs.

During 2012 and 2013, the “Statute for situations of scarcity in the MEM as part of the operative regulations” was under evaluation. In 2014, CREG published Resolution No. 026/2014 which enacted the Statute, which defines the rules of operation under critical supply conditions.

Since October 2015, Colombia has been affected by El Niño phenomenon, which has reduced rainfall in most of the country, decreasing hydroelectric generation. In order to guarantee the system’s reliability and security, CREG published several temporary regulations regarding the surplus capacity of small plants, limiting exports, changing the regulations of electricity trade in the MEM, among others.

Also, CREG defined a new option for power plants that have OEF commitments and operate with fuels such as diesel or kerosene allowing them to receive a higher price than the scarcity price, which triggers the OEF and is defined in the reliability charge methodology. The price differences are paid by customers.

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 for the energy that it consumes each month without a minimum or maximum. The prices are fixed in Colombian pesos indexed monthly to the Colombian PPI. According to CREG Resolution No. 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 different terms, such as for amounts contracted, demanded with or without a limit, or actually consumed, etc. Prices are denominated in Colombian pesos indexed monthly to the Colombian CPI.

Sales to Other Generation Companies

Generators can sell their energy to other generators through 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: Law 633 of 2000 (tax reform) states that generators must make a contribution of one Colombian peso to the Financial Support Fund for Energy for Unconnected Zones for every kilowatt dispatched on the Wholesale Energy Exchange. This requirement was extended to 2021 by both Law 1,715/2014 in May 2014 and by Decree No. 142/2015 of January 2015.

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. During a transition period that ended in November 2012, the firm energy supply for reliability purposes was assigned proportionally to the declared firm energy of each generator. After the transition period, only the additional firm energy required by the system is allocated by bids. The OEF assignation auctions are oriented to generation projects with construction periods under four years and projects with long construction periods (“GPPS” in its Spanish acronym). In addition, CREG can carry out OEF reconfiguration auctions oriented to adjust the differences between the assigned OEF and expected demand. When demand is higher or lower than expected, CREG can organize auctions in which it can acquire more firm energy, or on the contrary, agents with exceeding OEF can sell their commitments.

During 2011, CREG published resolutions for the assignment of OEF for projects with construction periods under four years for the periods from December 2014 to November 2015 and from December 2015 to November 2016. For the first period, the OEF was assigned proportionally to the existing generators while, for the second period, it carried out an auction to supply the additional OEF on December 27, 2011. Since then it has not been necessary to carry out any auction to supply additional future firm energy requirements.

During 2013, Resolution No. 062/2013 created incentives for thermal plants to back up their OEF with imported natural gas to guarantee their OEF for ten years beginning from 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.

On March 10, 2014, CREG published Resolution No. 022/2014, which defined a transitory regulated revenue in order to motivate the system participants to build an LNG terminal. During 2014, the participants were beginning to contract trading and import agents; however, due to the delay in the construction phase, CREG has allowed thermal generators to comply with their OEF using alternative fuels.

During 2014, CREG adjusted requirements for thermal plants with the ability to utilize multiple fuels in order to allow them to use natural gas instead of petroleum-based liquid fuels. Projects under construction with delayed start dates are now able to exchange the terms of their OEF, under specific conditions, with geothermal power plants in order to include renewable energy (wind since 2011 and biomass since 2013). Through Resolution No. 022/2014, CREG defined a transitory regulated revenue in order to motivate the system participants to build a LNG terminal. The new terminal will be available in December 2016.

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 per MWh. The new projects are Río Ambeima (hydroelectric, 45 MW), Carlos Lleras Restrepo (hydroelectric, 78 MW), San Miguel (hydroelectric, 42 MW), Gecelca 32 (thermal, 250 MW) and Tasajero 2 (thermal, 160 MW). The new assignments were made for a period of twenty years beginning on December 1, 2015.

In addition, on January 26, 2012, the auction was concluded for projects with long construction periods 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 MW by 2017 and thePorvenir 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 auction process conducted in 2008 (Sogamoso and Pescadero-Ituango hydroelectric plants). The process ended with assignment prices below the maximum defined (US$ 15.70 per MWh), and were in connection with Termonorte (US$ 14.90 per MWh);Porvenir II (US$ 11.70 per MWh);Sogamoso and Pescadero-Ituango (US$ 15.70 per 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. 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 Document No. 48/2012 regarding OEF allocation for the period from December 2016 to November 2017. CREG indicated that (i) an auction 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 regarding the execution dates Colombia-Panama interconnection agreement and the processes for importing natural gas. In addition, in July 2012 a reconfiguration auction for the period of December 2012 to November 2013 took place in order to minimize the difference between the assigned OEF and the expected demand for that period.

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$ 0.60 per MWh, which is greater than the reliability load price of December 2012 to November 2013. Projects such asAmbeimaandPorvenir II have lost their OEF.

In 2014, CREG published the Circular 088/2014, indicating that no auction is needed for the period from December 2016 to November 2020.

In 2015, CREG presented the methodology to calculate firm energy for wind plants. The new resolution allows projects without wind measurements for 10 years, to use proxy data in order to calculate the power-wind curve. The results of the approximation must be certified by the National Operations Council.

Also in 2015, CREG declared through Resolution No. 177 /2015 that existing firm energy was enough to supply the expected demand until 2019. For this reason, it assigned OEF to existing plants for the periods 2016-2017, 2017-2018 and 2018-2019. In addition, CREG published the new reliability charge methodology for small plants. According to Resolution No. 138/2015, the reliability charge clearing scheme for small plants will be centralized, as it is for large plants, and small plants must present a firm energy commitment for the reliability charge in order to have OEF assignations. CREG is allowing smalls plants to keep participating on the current remuneration mechanism if the differences between real and programmed generation are greater or lower than 5%. For the first year, the gap was defined as greater or lower 10%.

Electricity Exports and Imports

Andean Nation Community (“CAN” in its Spanish acronym) Decisions 536 of 2002, 720 of 2009, and 757 of 2011, signed by the countries that participate in the Andean Nations Community, 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 energy transfers made from Colombia to Venezuela, through this line, under an agreement between the Presidents of both nations. The agreement allows for estimated transactions of 30 GWh per 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 period 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 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 will pay for the electricity with fuel rather than cash. This interconnection project is estimated to cost US$ 8 billion and includes 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 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 Colombia are (i) CREG No. 002/2012, which attempts to resolve the discrepancies between firm capacity in Panama and the OEF in Colombia; (ii) CREG No. 004/2012, which outlines the exchanges in conditions of rationing; and CREG No. 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 entity 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 related to guarantees.

In June 2012, Interconexión Eléctrica Colombia-Panamá (“ICP” in its Spanish acronym), which is jointly owned by Interconexión Eléctrica de Colombia and the state-ownedEmpresa de Transmisión Eléctrica de Panamá , 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 discussions 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 transactions by harmonizing regulatory frameworks of the member countries in order to connect the electricity networks of the signatory countries in the Pacific area.

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. If demand exceeds supply, auctions take place, if the opposite happens, bilateral negotiations are carried out. Transportation contracts are traded under bilateral negotiation schemes or through auctions.

This regulatory framework is the result of a former proposal that sought to reform the wholesale market for natural gas and ensure that it operates under the principles of transparency and liquidity. This 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.

During 2014, CREG defined the rules for choosing the Market Manager, invited participants for the subsequent selection as natural gas Market Manager, and regulated the creation of trust instruments in their care. In 2015, the gas Market Manager was chosen and started operations. Its main responsibilities are the validation and monitoring of participant registration, the primary and secondary market supply and transport contract registration, and the implementation of long term and short term auctions. During the second half of 2014, and in accordance with the new regulatory framework, work continued on the second phase of marketing natural gas, which describes short and long term gas bilateral supply negotiations and aftermarket supply negotiations as well as transportation.

The third trading process of natural gas took place between September 2015 and November 2015 and this third trading process considered bilateral negotiations given that the supply exceed the demand.

As a result of the implementation of the indexes in Annex IV of CREG Resolution No. 089/ 2013, prices of signed, long-term gas contracts were adjusted in November 2013, yielding an increase of around 25% for gas supply contracts in Guajira. CREG requested that agents resume the discussion to achieve a consensus among all participants in the natural gas chain to introduce tariffs for supply contracts and final rate regulated market.

During 2015, CREG presented the final scheme for supply contract indexation. It considers two methodologies, bilateral negotiation and regulated formula application.

Also, advancements were made in defining the methodology to be used for calculating the discount rate, based on the WACC to be applied in natural gas transmission and distribution, fuel gas and LPG transport via pipelines, transmission and distribution of electricity in the national grid, and the generation and distribution of electricity in areas that are not connected to the Colombian NIS.

Late in 2015, the MME issued regulations related to the reliability and security of natural gas supply; by modifying the definition of essential demand, the order of supply priority and to identify the essential elements for the elaboration of the “Supply Plan for Natural Gas” which is the responsibility of the Mining and Energy Planning Unit. The main objective of this plan is to prepare the sector in case of supply shortages and design the regulatory framework to improve the transport and supply infrastructure.

Regulation of Distribution Companies

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

Distribution Tariff-Setting Process

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

The methodology for remunerating the distribution business segment was defined by CREG in 2008. The WACC was set at 13.9% before taxes for assets operating above 57.5 kV and 13.0% before taxes for assets operating under this threshold. CREG also defined a methodology for the calculation of distribution charges by creating an incentive scheme for administrative, operating and maintenance costs, service quality and energy losses. During 2009, after auditing the information reported by the companies, CREG established the distribution charges applicable until October 2013 or until CREG establishes new distribution charges.

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

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Level 1: less than 1 kV;

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

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

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

The review of distribution charges began in 2013 with the publication of the remuneration methodology proposed by CREG Resolution No. 043/2013. Such bases were augmented by CREG Resolution No. 079/2014 containing the Purposes and Guidelines for the Distribution Remuneration for the period 2015-2019 and CREG Resolution No. 179/2014 that defined a remuneration methodology. According to this, such bases and draft methodology incorporate replacement incentives by including depreciation as part of tariff formula, and an investment plan that will allow the incorporation of newer technology, improve service quality and control energy losses. The new distribution remuneration methodology and charges are expected to be published in during 2016.

Additionally, the CREG has issued Resolutions No. 083/2014 and 112/2014 which define the methodology to calculate the WACC for electricity transmission and distribution as well as natural gas distribution and transport.

Incentives and Penalties

In December 2011, CREG defined a coverage mechanism requiring traders who are the end customers, to guarantee distributors the payment of the regional transmission system and local distribution system tariffs. CREG established that these kinds of traders must use one of the following instruments, in order to provide security of payment to distributors: bank guarantees, stand-by letters of credit letters (either domestic or international) and monthly prepayments. These mechanisms will be in effect for three months after the issuance of the new trading remuneration methodology.

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

The distribution business has tariff incentives contingent on the quality of service. Distributors also have to make compensatory payments to customers when they cannot meet the established continuity criteria. In 2012, CREG established the new quality of service regulation for the regional transmission systems. Specifically, it defined compensations for energy that was not provided and service interruptions in the regional transmission systems.

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

Regulation in Transmission

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

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

The review of regulated transmission charges began in 2013 with the publication of the remuneration bases methodology proposed by CREG Resolution No. 042/2013. Such bases were complemented by the development of the Purposes and Guidelines for the Transmission Remuneration for the period 2015-2019, which was presented in CREG Resolution No. 078/ 2014, and by the draft methodology contained in CREG Resolution No. 178 /2014. This resolution was defined by the MME and seeks to ensure timely expansions and adequate assets. The new transmission remuneration methodology and the new transmission charges are expected to be issued during 2016.

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

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 with 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 most recent trading tariff formula became effective in 2015, as set by CREG Resolution No. 180 /2014. The main changes to this formula were the establishment of a fixed monthly charge covering operating cost plus a variable income for traders covering credit risk, working capital subsidies, and other selling costs. Selling costs have been approved individually for traders during 2015 and 2016. In the case of Codensa, in 2015 CREG published Resolution No. 120/2015 approving Codensa’s selling costs. The new tariff will be applied by January 2016.

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” (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 draft version of the mechanism through Resolution No. 117/2013, and the deadline for consultations has passed. It is expected that the final resolution on MOR will be issued by the end of 2016, and the first auction will be called for by the beginning of next year.

Tariffs to End Customers

The energy trader is responsible for charging the electricity costs to end customers and the transfer of their payments to the industry’s agents. The tariffs applied to regulated customers are calculated according to a

formula established by CREG. This formula reflects the costs of the industry (generation, transmission, distribution), depending on the customer’s connection level, trading losses, constraints, administrative costs, and market operating costs. The pricing formula is currently under review and CREG Resolution No. 135 /2014 establishes the basis of the studies to determine the unit cost formula of providing service to regulated customers. It is expected that the commission will issue the formula during 2016.

There are different factors that affect the final costs of the service. Subsidies and/or contributions are applied according to the socio-economic level of each customer, and when subsidies exceed contributions, the Colombian government compensates for the difference. Another factor that affects the final tariff is the distribution area, which establishes a single distribution tariff for the distribution companies in adjacent geographic zones.

In addition, to subsidize the value of electricity for the most financially vulnerable residential customers residing in the least developed rural areas, the MME established the Social Energy Fund (“FOES” in its Spanish acronym). Decree No. 011/2012 regulates FOES as defined in article 103 of Law 1450 of 2011 (published in 2012). FOES offsets CP$ 46 kWh of the price of electricity for the above mentioned customers.

Renewable Energy and Energy Efficiency

Since 2001, energy efficiency has been promoted in Colombia, through Law 697, which has been the framework for efficiency programs including the program for rational and efficient use of energy. In December 2012, the Colombian Mining and Energy Planning Agency published Resolution No. 0563, which establishes the procedure for the exclusion of sales tax for the programs or activities related to reduced energy consumption and energy efficiency.

On May 13, 2014, the Renewable Law (Law 1,715) was enacted. This new law establishes a general legal framework and created a fund intended to promote the development of non-conventional renewable energy, energy efficiency and programs designed to reduce electricity demand. One of its principal objectives is the progressive replacement of diesel generation in non-interconnected and isolated areas, in order to reduce energy cost and greenhouse gas emissions.

During the second half of 2014, the government worked on several aspects of the regulation, and as a result, in December the MME enacted Decree Nos. 2,492 and 2,469 establishing guidelines for the demand response mechanism and the sale of surplus energy by self-generators.

In 2015, MME enacted Decree No. 2,143 which defines the process agents must undertake in order to receive the tax and tariff benefits established by Law 1715. Regarding this rule, Mining and Energy Planning Agency also published Resolution No. 45 which establishes the procedures to receive the certificate that allows agents to access the benefits regarding taxes and import tariffs.

Environmental Regulation

The environmental framework in Colombia was established by Law 99/1993, which also established the Colombian Ministry of the Environment (now the Colombian 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.

Generation plants that have a total installed nominal capacity above 10 MW are required to contribute to the conservation of the environment. These resources are called “Transfers,” that electricity generation companies give to municipalities and regional environmental authorities, in accordance with article 222 of Law 1450 of 2011, which amended Article 45 of Law 99 of 1993. The amount to transfer is according to the plant’s generation and a tariff established by CREG, which is updated annually.

Law 1,450 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 No. 3,570 established a new regulatory structure for the environment, creating the MADS (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 MADS is the formulation and management of environmental and renewable natural resource policies. In 2012, the MADS published several resolutions. Resolution No. 1,517/2012 established the procedures relating to the Environmental Compensation for Biodiversity Loss while Decree No. 1,640 of 2012 set forth regulations for the planning and management of hydrographic basins. In addition, Resolution No. 1,526/2012 established the procedural requirements for the subtraction of the forest areas protected by Law 2 of 1,959.

In August 2013, the Colombian National Planning Department issued CONPES Document 3,762, a policy text that established guidelines for the identification and prioritization 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.

Due to national discussions about environmental licensing, the MADS enacted Decree No. 2,041/2014 which aims to reduce the timing needed to receive the necessary licenses.

During 2015, MADS issued the Single Regulatory Decree No. 1,076 (Decreto Único Reglamentario) for the environmental sector that compiles all existing decrees on environmental issues in the country.

MADS continued developing regulation to reduce water contamination caused by discharged water and ecological flow. It updated parameters and limits of specific maximum allowable discharges to surface water and public sewer systems.

Resolution No. 909/2008 was enacted increase air quality, to allow energy recovery from waste and/or hazardous waste in thermal generation plants.

The National Environmental License Authority granted licenses toPorvenir II hydroelectric project andCayao liquefaction plant and denied the license to theCañafisto hydroelectric project.

The Mayor’s Office of Bogotá, through its Decree No. 600/2015, established measures to renew the fleet of taxis in 2017 with electric vehicles.

MADS is leading Climate Change issues. MADS has included the Nationally Appropriate Mitigation Action in the Clean Development Mechanism portfolio. Also, MADS belongs to the negotiation team that represents Colombia at the Conferences of Parties. In 2015, the Climate Change unit presented the Intended Nationally Determined Contributions for Colombia and committed to reducing its greenhouse gas emissions by 20% by 2030 and subject to the provision of international support, Colombia could increase its goal from 20% reduction with respect to Business as Usual (“BAU”) to 30% with respect to BAU by 2030.

Peru

Industry Overview

Industry Structure

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

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

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

The energy received by a generator’s customers does not necessarily match with the energy produced by that supplier since the generation plants’ production is allocated by the COES, through a centralized dispatch. The transfer cost is minimized by reviewing the variable production costs of each power plant, regardless of their contractual commitments. The only exception to this rule applies to the natural gas plants, which declare the natural gas price once a year for dispatch purposes. Therefore, there is a short-term market that is also managed by the COES, where an economic balance is made between the energy produced and the demand of the generators’ customers.

The generation plants’ production and the customers’ energy consumption are valued at the hourly marginal cost and the generators that have deficits buy energy from the generators that have surpluses. This principal related to the energy sales balances is also carried out for the capacity. The price of the capacity corresponds to a price regulated by the Energy and Mining Investment Supervisor (“Osinergmin” in its Spanish acronym).

In 2008, due to gas transport and electricity transmission problems, Osinergmin defined a new rule to calculate spot prices. Decree No. 049/2008 established two models, with one of them representing a theoretical dispatch without considering any restrictions and the other considering real dispatch with restrictions. The spot

price is obtained from the theoretical dispatch (known as “ideal marginal cost”), and the additional operating costs resulting from system restrictions are paid through demand from the affected generators through a mechanism established by the authority. The “ideal marginal cost” regime was extended until December 31, 2016. In recent years, the ideal marginal cost has been very similar to the real cost and has not had a relevant impact. The settlements made by the COES also include payments and/or collections for supplementary 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.

The transmission system is made up of transmission lines, substations and equipment for the transmission of electricity from the power plants to the consumption centers or distribution points. Transmission in Peru is defined as all lines or substations with a 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 an option, the customer must 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, at least one year advance notice must be provided.

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, as of December 31, 2014, 92.9% of the population obtained electricity through the public network.

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, Supreme Decree No. 030-2012-EM amended the articles of organization and defined the activities of MINEM and the Natural Gas Management Department.

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

Osinergmin 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 is responsible for promoting competition, protecting customer rights and safeguarding all forms of intellectual property.

The General Electricity Authority 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 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 as 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 No. 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 No. 020/1997), the Electricity Import and Export Regulation (Supreme Decree No. 049/2005), the Antitrust Law for the Electricity Sector (Law 26,876/1997), the law that regulates the activity of Osinergmin (Law 26,734/1996, together with Law 27,699/2002) ), and Decree Law No. 1,221/2015 that improves electricity distribution regulation to promote electricity access in Peru.

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.

Law 29,852/2012 and Regulation No. 021-2012-EM created the Hydrocarbons Energy Security System and the Fund of Social Energy Inclusion. 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), 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 manage the Fund of Social Energy Inclusion, which directs funds to the mass usage of natural gas to vulnerable sectors, (ii) develop new energy sources like photovoltaic cells, solar panels, etc., and (iii) supply liquefied petroleum gas to vulnerable sectors.

Law 29,969/2012 provides for the universal usage of natural gas. State electricity distributors are authorized to carry out natural gas programs, including the distribution of natural gas in their concession area. They are also able to associate with companies specializing in the development of gas distribution projects. Within a maximum period of three years from the start of the gas distribution, MINEM will start the process of promoting private investment by granting gas distribution concessions through 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) the guarantee of energy security, (ii) the transport of ethane to southern Peru; and (iii) the construction of regional pipelines in Huancavelica, Junín, and Ayacucho and their connection to existing gas pipelines.

Law 1,221/2015 enacted on September 24, 2015, will be applied during 2016, and once implemented, the main modifications are:

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In the distribution tariffs, the VAD and the internal rate of return calculations will be defined for each distribution company with over 50,000 customers.

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The MINEM will define a responsibility technical area (“ZRT” in its Spanish acronym) for each distributor, given its operation areas. The investments in the ZRT, which can be carried out either by a distributor or by a third party, should be approved by the distributor. Investment and audited costs (with a cap) will be recognized through the VAD.

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The VAD will include a technology innovation charge and/or a distribution energy efficiency component. The VAD will also be adjusted to encourage improvements of service quality.

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Distributors will be obligated to guarantee their regulated demand for 24 months.

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

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

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

Limits and Restrictions

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

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

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

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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 No. 080-2012-OS/CD 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 28,832/2006 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 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

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 electricity generation capacity in the system in the near future. MINEM recommended the construction of new electricity plants that would serve as backup to guarantee the flow of electricity to the system, avoiding blackouts. As a result, the Peruvian Investment Promotion Agency carried out a public bid in August 2010, seeking to secure investments for three projects located inReserva Fría de Talara,Trujillo andIlo that would add another 800 MW to the system. The bid resulted in two of the projects being awarded:Reserva Fría de Talara (200 MW, for EEPSA, an Enersis subsidiary and Ilo (400 MW, for Enersur, an unrelated company). These plants receive regular payments for being permanently available to operate and provide energy to the SEIN whenever the COES calls on them and will also be reimbursed for the fuel costs incurred for generating electricity. The Trujillo

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generation facility was later replaced by the Eten generation facility and awarded toPlanta de Reserva Fría de Generación de Eten S.A. (200 MW).

On March 21, 2013, Peruvian Investment Promotion Agency held an international public tender to promote private investments in the Hydroelectric Plant project (MollocoHydroelectric Plant—280 MW), which is located in the hills of theArequipa region. It was awarded to the Corsan Corviam – Engevix – Enex partnership.

Services provided by generation, transmission, and distribution companies must 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 receive this payment, plants have to be part of the reserve margin established annually by Osinergmin. The capacity ranking is constructed in base of firm capacity of every power plant connected to the system and their relative efficiency (ordered by variable costs). Only plants included in the ranking as required to cover the peak demand plus the reserve margin receive the 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. However, the line has not operated continuously because of regulatory issues. In 2014, electricity exports to Ecuador totaled 12.7 GWh In 2015, the electricity exports net amounted to 54.3 GWh.

Internal regulations were also approved for the application of CAN Decision 757, which establishes that when bilateral electricity transactions are carried out with other CAN countries, the Economic Operation Committee of the SEIN should send weekly reports to the MINEM and to Osinergmin demonstrating that priority has been given to supplying the domestic market (Supreme Decree No. 011-2012-EM).

The governments of Peru and Chile have established a bilateral working group to discuss energy matters. The purpose of the working group is to identify and take advantage of the potential synergies between the two countries. At the request of the presidents of both nations, the working group is expected to propose a framework for an agreement 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 of Distribution Companies

Bids for Supplying Regulated Customers

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

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

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Distribution Tariffs to End Customers

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

Distribution Tariff-Setting Process

The VAD is set every four years. Osinergmin classifies companies into groups, according to “typical distribution areas”, based on economic factors that group companies with similar distribution costs due to population density, which determines equipment requirements in the network.

Actual return on investment for a distribution company depends on its performance relative to the standards chosen by the Osinergmin for a theoretical model company. The tariff system allows for a greater return for distribution companies that are more efficient than the model company. Tariff studies are performed by the Osinergmin and distribution companies. Preliminary tariffs are calculated as a weighted average of the results of the Osinergmin commissioned study and the companies’ study, with the results of the Osinergmin’s study bearing twice the weight of the companies’ study. Preliminary tariffs are then tested to ensure that they provide an average actual annual internal rate of return between 8% and 16% on the replacement cost of electricity-related distribution assets.

The most recent process of distribution tariff setting has been in effect since November 2013 and will be in effect until October 2017.

Regulatory Charges

The regulatory charges applied to the energy sales in distribution activities are:

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The contribution to regulatory authorities (Osinergmin, MINEM), which represents 1% of total sales.

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The FOSE created to promote permanent access to the public electricity service for low-income residential customers. This fund established a cross subsidy system among customers that benefits customers with monthly consumption below 100 kWh through fixed and proportional discounts.

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The rural electrification charge is a contribution for promoting the efficient and sustainable electrification development in rural, isolated or frontier areas of the country. The contribution of the electricity customers is of 0.002 UIT (a tax unit) per MWh billed, with the exception of those which are not served by the SEIN.

Incentives and Penalties

Law 28,832 and Supreme Decree No. 052-2007-EM (“General Regulations of the Supply Auctions”) state that if auctions are called for with an anticipation of over three years, distributors will receive payment incentives which will be added to the generator price of the auctions, and then passed through to customers. This incentive cannot be higher than 3% of the tariffs applied.

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

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

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the national grid that connects principal transmission with the distribution network or that connect directly to certain end customers. Law 28,832 also defined “guaranteed transmission systems” and “supplementary transmission systems”, applicable to projects commissioned after the enactment of that law. Guaranteed system lines are the result of a public bid and supplementary system lines are freely constructed and exploited as private projects. Principal and guaranteed system lines are 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 supplementary 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 established in the Environmental Law (Law 28,611/2005) and in the Regulation for Environmental Protection regarding Electricity Activities (Supreme Decree No. 029-94-EM). 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.

NCRE, referred to in Peruvian regulations as Renewable Energy Resources (“RER” in its Spanish Acronym), for electricity generation are considered to be from the following sources: biomass, wind, solar, geothermal and tidal sources, as well as hydroelectric plants with an installed capacity lower than 20 MW.

In 2008, the authority issued regulations to promote the use of NCRE. The principal investment incentives established by these regulations are (i) an objective percentage of national electricity consumption, set every five years, to be covered NCRE generation, excluding hydroelectric plants (for the first five-year period, this percentage is 5%); (ii) through tenders of energy to be covered by NCRE, the investor awarded the tender is guaranteed a firm price for the energy injected into the system during the supply contract period of up to 20 years; and (iii) priority in the dispatch of load and access to transmission and distribution networks.

The first NCRE tender was carried out in two steps. The first auction was held in June, 2009 for 1,314 GWh per year, of which 570 GWh was awarded to three wind farms projects, 173 GWh was awarded to four solar plants projects, 143 GWh was awarded to two biomass plants projects and 1,084 GWh was awarded to 19 mini-hydroelectric plants. The second auction was held in March, 2010 for 427 GWh per and 11.7 GWh was award to a biomass thermal plant project and two mini hydroelectric project for 92 GWh.

The second NCRE tender was held in August, 2011 for 1,300 GWh per year intended to non-hydroelectric sources. Out of 21 initiatives proposed, 473 GWh were awarded to three projects.

The third NCRE tender was held in December, 2013, with the objective to provide 1,300 GWh per year of hydroelectric power and 320 GWh of biomass derived electricity. Nineteen mini hydroelectric plant projects with individual capacities below 20 MW were awarded to supply 1,268 GWh.

The fourth NCRE tender was held in December, 2015, with the objective to provide 1,300 GWh to both the interconnected and isolated systems. In addition, 450 GWh per year are required from mini hydroelectric projects with a maximum capacity of 20 MW each. The results were published by the end of January 2016 and 1,741 GWh were awarded to the following projects: three wind farms (739 GWh), two solar power plant projects (523 GWh), two biomass thermal plant projects (30 GWh) and six small hydroelectric plant projects (449 GWh).

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

Law 29,968/2012 created the National Environmental Certification Service for Sustainable Investments (“SENACE” in its Spanish acronym), a specialized public organization with technical autonomy and a separate legal constitution, which reports to the Peruvian Ministry of the Environment. This organization is responsible for reviewing and approving detailed environmental impact studies of public, private or mixed capital investment projects, whether national or multi-regional, that involve activities, construction and other commercial and service activities whose characteristics, importance and/or location can result in significant environmental impacts, with the exception of those expressly excluded by Supreme Decree No. with the consenting vote of the Council of Ministers.

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

Raw Materials

For information regarding our raw materials, please see “Item 11. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

C.	Organizational Structure.

Principal Subsidiaries and Affiliates

We are part of an electricity group controlled by the Italian company, Enel, our ultimate parent company, which beneficially owns 60.6% of us through wholly-owned Spanish subsidiaries. Enel publicly trades on the Milan Stock Exchange. It is headquartered in Italy and is primarily engaged in the energy sector, with a presence in 32 countries across four continents, mainly in Europe and Latin America, and generating electricity from power plants with over 89 GW of net installed capacity. Enel provides service to more than 61 million customers through its electricity and gas businesses through distribution networks of 1.9 million kilometers.

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Enersis Américas’ Organizational Structure⁽¹⁾

As of December 31, 2015 (assuming the spin-off of Enersis Chile S.A. had occurred as of such date)

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

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The companies listed in the following table were consolidated by us as of December 31, 2015. In the case of subsidiaries, our economic interest is calculated by multiplying our percentage economic interest in a directly held subsidiary by the percentage economic interest of any entity in the chain of ownership of such ultimate subsidiary.


Principal Subsidiaries and Country of Operations	% Economic Ownership of Enersis		Consolidated Assets of Each Main Subsidiary		Operating Income of Each Main Subsidiary
	(in %)		(in billions of Ch$)
Electricity Generation and Transmission
Electricity Generation
Fortaleza (Brazil)		84.38		151,222		159,052
Cachoeira Dourada (Brazil)		84.17		121,390		91,563
Dock Sud (Argentina)⁽¹⁾		57.14		172,911		69,963
EEPSA (Peru)		96.50		130,528		58,093
Electricity Transmission
CIEN (Brazil)		84.38		214,341		55,534
Electricity Distribution
Ampla (Brazil)		92.03		1,402,340		1,026,680
Edesur (Argentina)		71.61		634,854		607,345
Edelnor (Peru)		75.54		773,983		562,046
Coelce (Brazil)⁽²⁾		64.86		836,903		810,184
Codensa (Colombia)		48.39		1,049,139		884,467

(1)	Figures correspond to Inversora Dock Sud S.A., an investment vehicle through which we hold our 40.2% economic interest in Dock Sud.

(2)	As a consequence of a tender offer completed in 2014 our shareholding increased from 49.2% to 64.9%.

Generation and Transmission Segment

The following companies include certain generation and transmission companies consolidated by us as of December 31, 2015 (marked with an asterisk), as well as other companies in which we have an interest.

Cemsa (Argentina)*

Cemsa’s principal activities are the trading of electricity and fuels. Cemsa has signed several agreements with Argentine electricity power stations to support its supply contracts. The power stations that provide Cemsa’s electricity supply contracts are: Costanera, Dock Sud, Centrales Térmicas del Noroeste S.A., and El Chocón. Endesa Américas indirectly holds 45.0% of Cemsa and our economic interest in Cemsa is 82.0%.

Dock Sud (Argentina)*

Dock Sud owns and operates an 870 MW generation facility consisting of two plants. Dock Sud’s power station has four gas turbines and one steam turbine. Two of the gas turbines and the steam turbine comprise a combined-cycle power plant. In 2015, Dock Sud generated 3,799 GWh. We own 57.1% of Inversora Dock Sud S.A., an investment vehicle through which we hold Dock Sud. Our economic interest in Dock Sud is 40.2%.

Costanera (Argentina)

Costanera is a publicly-held Argentine electricity generation company, with 2,304 MW of total installed capacity in Buenos Aires. Costanera consists of six steam turbines with an aggregate capacity of 1,131 MW which burn oil and gas, and two natural gas combined-cycle facilities with a total capacity of 1,173 MW. Costanera was acquired from the Argentine government after the privatization of Servicios Eléctricos del Gran Buenos Aires S.A. Endesa Américas owns 75.7% of Costanera’s shares, and we own a 45.4% economic interest.

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El Chocón (Argentina)

El Chocón is an Argentine electricity generation company. It has two hydroelectric power stations with an aggregate installed capacity of 1,328 MW located between Neuquén and Río Negro provinces, in the Comahue Basin in southern Argentina. A 30-year concession, which expires in 2023, was granted by the Argentine government to our subsidiary, Hidroinvest S.A., which bought 59.0% of El Chocón’s shares in July 1993 during the privatization process. Endesa Américas operates El Chocón for a fee pursuant to an operating agreement with a term equal to the duration of the concession. Endesa Américas beneficially holds 65.4% of El Chocón, and our economic interest is 39.2%.

Cachoeira Dourada (Brazil)*

Cachoeira Dourada owns and operates a run-of-the-river hydroelectric plant using the flows from the Paranaiba River, located in the State of Goias, consisting of ten generating units totaling 665 MW of installed capacity. Cachoeira Dourada began its operations in 1997, and as of December 31, 2015, had a concession that expires in 2027. Enel Brasil has a 99.8% ownership interest in Cachoeira Dourada and our economic interest is 84.2%.

CIEN (Brazil)*

CIEN is a Brazilian transmission and trading company that is wholly-owned by Enel Brasil. It transmits electricity through its two transmission lines that connect Argentina and Brazil, covering a distance of 500 kilometers, with a total interconnection capacity of 2,100 MW. As of December 31, 2015, CIEN-Line 1 had a concession that expires in 2020, and CIEN-Line 2 had a concession that expires in 2022. CIEN consolidates CTM and TESA, which operate the Argentine side of the interconnection line with Brazil. Our economic interest in CIEN is 84.4%.

Enel Brasil (Brazil)*

In 2005, Enel Brasil was formed in order to manage all Brazilian generation, transmission and distribution assets that Enel Latinoamérica owns in conjunction with us, Endesa Américas and Chilectra Américas. Enel Brasil consolidates operations of two generation companies (Cachoeira Dourada and Fortaleza), the transmission company CIEN, as well as two distribution companies (Ampla and Coelce). Endesa Américas owns 37.1% of Enel Brasil’s shares, and we beneficially own an 84.4% economic interest.

Fortaleza (Brazil)*

Fortaleza owns and operates a 322 MW natural gas combined-cycle power plant, with a capacity to generate one-third of the electricity requirements of the State of Ceará, a state with a population of 8.8 million people. As of December 31, 2015, Fortaleza had a concession that expires in 2031. Fortaleza is wholly-owned by Enel Brasil, and we hold an 84.4% economic interest.

Emgesa (Colombia)*

Emgesa has a total installed generating capacity of 3,459 MW, of which 87% is from hydroelectric power plants and 13% is from thermoelectric power plants. Empresa de Energía de Bogotá S.A. directly holds a 51.5% equity interest in Emgesa. Endesa Américas beneficially owns 26.9% of Emgesa’s shares and has 31.3% of the voting rights. However, due to a transfer of 25.1% of the voting rights in Emgesa from us, to Endesa Américas and a related shareholders’ agreement, Endesa Américas holds a majority of the voting rights and is allowed to appoint the majority of the Board members and, therefore, controls Emgesa. We beneficially own 37.7% of Emgesa. For more information, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

Edegel (Peru)*

Edegel, an electricity generation company, owns and operates seven hydroelectric plants and two thermal plants, with a consolidated installed capacity of 1,685 MW. In October 2009, Endesa Américas purchased an

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additional 29.4% stake in Edegel from Generalima, S.A.C., one of our subsidiaries, and as a result of this transaction, increased its ownership interest from 33.1% to 62.5%. In September 2014, we acquired a 39.0% stake that Inkia Americas Holdings Limited held in Generandes Perú S.A., a company that held a 54.2% stake of Edegel. With this transaction, we increased our economic interest in Edegel from 37.5% to 58.6%.

Edegel holds 80% of the shares of Chinango S.A.C. and Peruana de Energía S.A.A. (an unaffiliated entity) owns the remaining 20% of the shares.

EEPSA (Peru)*

EEPSA has 298 MW of generation capacity, consisting of two thermal plants, Malacas and Malacas II, both of which are located in the province of Talara-Piura, which operate using locally produced natural gas. We beneficially own 96.5% of EEPSA.

Distribution Segment

The following companies include distribution companies consolidated by us as of December 31, 2015.

Edesur (Argentina)

Ampla (Brazil)

Ampla is the second largest electricity distribution company in the State of Rio de Janeiro, Brazil, in terms of number of customers and annual energy sales. Ampla is mainly engaged in the distribution of electricity to 66 municipalities located in the State of Rio de Janeiro, and serves 2.9 million customers in a concession area of 32,615 square kilometers. As of December 31, 2015, Ampla had a concession that expires in 2026. We have a 92.0% economic interest in Ampla.

Coelce (Brazil)

Coelce is the sole electricity distributor of the State of Ceará, located in the northeastern part of Brazil, and serves over 3.7 million customers within a concession area of 148,825 square kilometers. As of December 31, 2015, Coelce had a concession that expires in 2027. Prior to 2014, our economic interest in Coelce was of 49.2%, and as a result of the voluntary tender offer completed in May 2014, our shareholding increased to 64.9%.

Codensa (Colombia)

Codensa is a Colombian electricity distribution company that serves a concession area of 14,456 square kilometers in Bogotá and 96 other municipalities of the provinces of Cundinamarca, Tolima and Boyacá, serving approximately 2.8 million customers. Our economic interest in Codensa, held directly and indirectly through Chilectra Américas, is 48.4%, which represents 57.2% of the voting rights in Codensa, and as a result of this and pursuant to a shareholders’ agreement we appoint the majority of Codensa’s Board members, and therefore, have control over Codensa. For more information regarding the control and consolidation of Codensa, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

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Edelnor (Peru)

Edelnor, a Peruvian electricity distribution company, operates in a concession area of 1,517 square kilometers. It has an exclusive concession to distribute electricity in the northern part of the Lima metropolitan area, as well as some provinces in the Lima region, including Huaral, Huaura, Barranca and Oyón, and the adjacent province of Callao. As of December 31, 2015, Edelnor distributed electricity to approximately 1.3 million customers. We hold a 75.5% economic interest in Edelnor.

Selected Related and Jointly-Controlled Companies

Yacylec (Argentina)

Yacylec is an Argentine electricity transmission company. As of December 31, 2015, Yacylec had a concession that expires in 2088. The Yacylec transmission system consists of:

•

Three 500 kV transmission lines, 4 kilometers each in length, from the Hidroeléctrica Yaciretá power station to the Rincón de Santa María transformer station.

•

The 500 kV Rincón de Santa María transformer station, located in the province of Corrientes.

•

A 500 kV transmission line (296 kilometers long) from the Rincón de Santa María transformer station to the Resistencia transformer station, and an expansion of the Resistencia transformer station, located in the province of Chaco.

•

A communications system.

Our economic interest in Yacylec is 22.2%.

D.	Property, Plant and Equipment.

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

Property, Plant and Equipment of Generating Companies

We conduct our generation and transmission businesses directly and through our subsidiaries, Endesa Américas and Enel Brasil. Endesa Américas combines revenues from other non-wholly-owned generation companies in Argentina, Colombia and Peru, which in turn own 26 additional generation power plants. We conduct our Brazilian operations through Enel Brasil and consolidate revenues from two generation power plants. In addition, we directly consolidate revenues from two other non-wholly-owned generation companies, which own two generation power plants, one in Argentina and one in Peru. As a result, we have an aggregate of 30 power plants in South America. Through Enel Brasil, we also own and operate a transmission system consisting of two 500 kilometer 2,100 MW transmission lines that link Rincón de Santa María in Argentina with Itá in the State of Santa Catarina in Brazil.

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

Our electricity generation facilities are insured against damage due to earthquakes, fires, floods, other acts of god (but not for droughts, which are notforce majeure risks, and are not covered by insurance) and from damage due to third-party actions, based on the appraised value of the facilities as determined from time to time by an independent appraiser. Based on geological, hydrological and engineering studies, management believes

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that the risk of an event with a material adverse effect is remote. Claims under our generating subsidiaries’ insurance policies are subject to customary deductibles and other conditions. We also maintain business interruption insurance providing coverage for the failure of any of our facilities for a period of up to 24 months, including the deductible period. The insurance coverage taken for our property is approved by each company’s management, taking into account the quality of the insurance companies and the needs, conditions and risk evaluations of each generating facility, and is based on general corporate guidelines. All insurance policies are purchased from reputable international insurers. We continuously monitor and meet with the insurance companies in order to obtain what we believe is the most commercially reasonable insurance coverage.

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

Installed Capacity
As of December 31,

Country/Company

Power Plant Name

Power Plant Type

2015

2014

2013

(in MW)

Argentina

Costanera⁽¹⁾

Costanera Steam Turbine

Steam Turbine/Natural Gas+Fuel Oil

1,131

Costanera Combined Cycle II

Combined Cycle/Natural Gas+Diesel Oil

851

Buenos Aires Combined Cycle I

Combined Cycle/Natural Gas

322

Total

2,304

El Chocón

Chocón

Reservoir

1,200

Arroyito

Pass-through

128

Total

1,328

Dock Sud

Dock Sud CC

Combined Cycle/Natural Gas+Diesel Oil

798

Dock Sud TG

Gas Turbine/Natural Gas+Diesel Oil

Total

870

Total capacity in Argentina

4,502

Brazil

Cachoeira Dourada

Pass-through

665

Fortaleza

Combined Cycle/Gas

322

Total capacity in Brazil

987

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			Installed Capacity As of December 31,
Country/Company	Power Plant Name	Power Plant Type	2015		2014		2013
			(in MW)
Colombia
Emgesa
	Guavio	Reservoir		1,213		1,213		1,213
	Paraíso	Reservoir		276		276		276
	La Guaca	Pass-through		325		325		325
	Termozipa	Steam Turbine/Coal		236		236		236
	Cartagena	Steam Turbine/Natural Gas		208		208		208
	Minor plants⁽²⁾	Pass-through		57		57		77
	Betania	Reservoir		541		541		541
	Dario Valencia⁽³⁾	Pass-through		150		150		50
	Salto II⁽⁴⁾	Pass-through		35		35		—
	Laguneta⁽⁵⁾	Pass-through		18		18		—
	Quimbo⁽⁶⁾	Reservoir		400		—		—

Total capacity in Colombia				3,459		3,059		2,926

Peru
Edegel
	Huinco⁽⁷⁾	Pass-through		268		247		247
	Matucana⁽⁸⁾	Pass-through		137		137		133
	Callahuanca⁽⁷⁾	Pass-through		84		80		80
	Moyopampa⁽⁷⁾	Pass-through		69		66		66
	Huampani	Pass-through		30		30		30
	Santa Rosa^(7)(9)(10)	Gas Turbine/Diesel Oil		419		413		305
	Ventanilla⁽⁷⁾	Combined Cycle/Natural Gas		484		485		485

	Total			1,491		1,458		1,346
Chinango
	Yanango	Pass-through		43		43		43
	Chimay⁽⁷⁾	Pass-through		152		151		151

	Total			195		194		194
EEPSA	Malacas^(11)(12)	Gas Turbine/Natural Gas+Diesel Oil		298		297		302

	Total			298		297		302

Total capacity in Peru				1,984		1,949		1,842

Consolidated capacity				10,932		10,497		10,257

(1)	Values for 2013, 2014 and 2015 were modified and correspond to values reported to CAMMESA (Argentina TSO).

(2)	Minor plants have an aggregate capacity of 57 MW. As of December 31, 2015 and 2014, Emgesa owned and operated three minor plants: Charquito (19.5 MW), El Limonar (18 MW) and Tequendama (19.5 MW). In March 2014, the San Antonio (19.5 MW) plant was decommissioned.

(3)

In November 2013, the Dario Valencia power plant began commercial operations with 50 MW of installed capacity. During 2014 unit 1 (January) and unit 5 (April) also began commercial operations, adding 100 MW of capacity. This power plant is part of the Salaco Hydroelectric project, together with the El Limonar, El Salto II and Laguneta power plants.

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(4)	In June 2014, the El Salto II (35 MW) power plant began commercial operations.

(5)	In December 2014, the Laguneta (18 MW) power plant began commercial operations.

(6)	In November 2015, El Quimbo (400 MW) power plant began commercial operations.

(7)	The variation in the installed capacity of this power plant in 2015 was the result of tests performed by COES.

(8)	The Matucana power plant increased its installed capacity by 4 MW in June 2013 and by 4 MW in July 2014 as a result of tests performed by COES.

(9)	The variation in the installed capacity of this power plant in 2014 was the result of tests performed by COES.

(10)	In October 2013, unit TG 7 (121 MW) of the Santa Rosa power plant was decommissioned and in December 2014 it began commercial operations again.

(11)	As a result of the 2013 capital increase, we began consolidating EEPSA as of April 2013. In August 2014, unit TG 1 (11.7 MW) of the Malacas power plant was decommissioned.

(12)	Includes the installed capacity (193 MW) of the Reserva Fría de Talara power plant.

As of December 31, 2015, we received the ISO 14,001 certification for 96.3% of our installed capacity in South America, which included all of our generation facilities that produced 99.1% of the total annual generation in accordance with the this standard.

Property, Plant and Equipment of Transmission and Distribution Companies

We have significant interests or investments in electricity distribution. The description for each distribution company is included in this “Item 4. Information on the Company.” The table below describes our main equipment used for our distribution business, such as transmission lines, substations, distribution networks and transformers.

We are insured against damage to substations, transformers that are within the substations, the distribution network that is less one kilometer from the substations and administrative buildings. Risks covered include losses caused by fires, explosions, earthquakes, floods, lightning, damage to machinery and other such events. Insurance policies include liability clauses, which protect our companies from complaints made by third parties.

Transmission lines and the equipment attached to them do not qualify as insurable assets for property damage, although they have insurance policies including civil liability clauses for damages against third parties caused by these transmission installations. These criteria apply in the case of the Argentina-Brazil interconnection line, our main transmission asset, for which there is insurance coverage for damage to the assets and civil liability for the Garabí conversion station, the Argentina/Brazil connection substations and up to one kilometer of lines from the substations. Only third-party liability coverage is applicable for the rest of the transmission lines.

TABLE OF DISTRIBUTION FACILITIES

General Characteristics


	Location		Concession Area		Transmission Lines⁽¹⁾
	Location		Concession Area		2015		2014		2013
			(in km²)		(in kilometers)
Edesur		Argentina		3,309		1,120		1,115		1,115
Ampla		Brazil		32,615		2,401		2,351		2,363
Coelce		Brazil		148,920		5,316		5,069		4,875
Codensa⁽²⁾		Colombia		14,456		1,247		1,247		1,247
Edelnor		Peru		1,517		573		534		501

Total				200,818		10,657		10,316		10,101

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(1)	The transmission lines consist of circuits with voltages in the 27-220 kV range.

(2)	The concession area figure differs from previous disclosures. Amounts were updated following a review in 2014 of the territorial area of municipalities, conducted by National Administrative Department of Statistics (“DANE” in its Spanish acronym).

Power and Interconnection Substations and Transformers⁽¹⁾


	Year ended December 31,
	2015						2014						2013
	Number of Substations		Number of Transformers		Capacity (MVA)		Number of Substations		Number of Transformers		Capacity (MVA)		Number of Substations		Number of Transformers		Capacity (MVA)
Edesur		71		180		12,424		70		174		11,949		67		170		11,599
Ampla		117		220		4,725		117		225		4,658		117		223		4,695
Coelce		111		179		2,955		108		175		2,807		106		170		2,620
Codensa		61		238		9,448		61		233		8,955		61		231		8,875
Edelnor		35		84		3,806		35		81		3,621		33		76		3,325

Total		395		901		33,357		391		888		31,990		384		870		31,114

(1)	Voltage of these transformers is in the range of 500 kV (high voltage) and 7 kV (medium voltage).

Distribution Network — Medium and Low Voltage Lines⁽¹⁾


	Year ended December 31,
	2015				2014				2013
	Medium Voltage		Low Voltage		Medium Voltage		Low Voltage		Medium Voltage		Low Voltage
					(in Kilometers)
Edesur		7,872		17,018		7,577		16,541		7,417		16,021
Ampla		35,211		18,394		34,649		17,858		34,000		17,858
Coelce		84,290		50,223		83,318		49,718		82,244		48,951
Codensa		20,266		28,270		20,016		28,136		19,902		27,825
Edelnor		4,484		22,267		4,308		21,819		4,191		21,402

Total		152,123		136,172		149,868		134,072		147,754		132,057

(1)	Medium voltage lines: 7 kV - 34.5 kV; low voltage lines: 380-110 V.

Transformers for Distribution⁽¹⁾


	Year ended December 31,
	2015				2014				2013
	Number of Transformers		Capacity (MVA)		Number of Transformers		Capacity (MVA)		Number of Transformers		Capacity (MVA)
Edesur		20,487		6,159		22,155		6,062		22,912		5,918
Ampla		120,387		4,858		118,358		4,666		115,024		4,483
Coelce		145,686		4,806		142,837		4,719		140,336		4,655
Codensa		69,490		9,379		68,594		9,147		67,727		8,710
Edelnor		10,758		1,774		10,532		1,699		10,368		1,617

Total		366,808		26,976		362,476		26,293		356,367		25,383

(1)	Voltage of these transformers is in the range of 34.5 kV (medium voltage) and 110 V (low voltage).

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Project Investments

The total investment for each project described below was translated into Chilean pesos at the exchange rate of Ch$ 710.16 per U.S. dollar, the U.S. dollar Observed Exchange Rate as of December 31, 2015. Budgeted amounts include connecting lines that could eventually be owned by third parties and paid as tolls, unless otherwise indicated.

Investment Projects Completed during 2015

El Quimbo Hydroelectric Project (Colombia)

El Quimbo hydroelectric project is located in the province of Huila, southeast of Bogotá, using the flows of the Magdalena and Suaza Rivers, upstream of the Betania power plant. The project has two generation units and a total installed capacity of 400 MW. The estimated average generation is 2,216 GWh per year, with a flooded reservoir area of 8,250 hectares.

On October 6, 2015, the Colombian government enacted the Decree No. 1979/2015, which authorizes energy generation for El Quimbo starting from October 7, 2015. On November 16, 2015, El Quimbo began its commercial operations. On December 15, 2015, the Colombian Constitutional Court declared Decree No. 1979/2015 unconstitutional on the grounds that the injunction issued by the Administrative Tribunal of Huila was still in effect. Emgesa therefore suspended operations of El Quimbo as of midnight on December 16, 2015. On January 10, 2016 at midnight, El Quimbo resumed its commercial operations following a court decision allowing El Quimbo to restart operations on a temporary basis.

This project was financed primarily with external sources, through local and international bonds. The estimated total investment accrued as of December 31, 2015 was Ch$ 683,879 million.

Projects Under Development

We continuously analyze different growth opportunities in the countries in which we participate. Currently, we are studying and assessing our project portfolio, focusing on constructing smaller, less invasive power plants. These plants are constructed faster, allow greater flexibility to activate or deactivate according to system needs, and are generally more acceptable to area residents. Additionally, an additional focus will be placed on the development of renewable technologies. Thus, the expected start-up for each project is continuously assessed and will be defined based on the commercial opportunities and our financing capacity to fund these projects. The most relevant projects in the pipeline are as follows:

Generation and Transmission Business

Curibamba Hydroelectric Project (Peru)

Curibamba consists of a 188 MW run-of-the-river power plant and a 134 km transmission line that will connect it to SEIN at the Pachachaca substation (220 kV). This power plant will be located 385 km northeast of Lima, which is upstream from the Chimay hydroelectric power plant (province of Junín), and will use the waters of the Comas and Uchubamba Rivers through an 8.1 km penstock.

During 2015, we continued with the bidding process for the project’s main contracts (civil works, equipment supply and electrical interconnection), and we started the studies required for obtaining prior permits to the project construction.

Currently, the project has a generation concession for the power plant, an approved Environmental Impact Study, and compliance certificates stating the non-existence of archaeological remains, both for the power plant and the transmission line.

In January 2015, the Peruvian Ministry of Energy and Mining approved the 2015—2024 Binding Transmission Plan. The connection of the power plant is being reviewed as the 2015—2024 Binding Transmission Plan allows the project to be connected to a closer substation. During 2015, the Pre-Operation

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Study for the connection to the Yanango Substation, located 40 km from the project, was approved as well as the extension of the validity of the environmental impact study of the power plant. We anticipate our participation in hydroelectric bids that the Peruvian government expects to hold in the future and are currently pending of tender date.

The construction is expected to start in 2016 and last until 2021 as per the timeline in the definitive concession schedule. The construction is expected to last until 2021. This project is being financed primarily with internally generated funds, with an estimated total investment of Ch$ 424,321 million, of which Ch$ 18,177 million has been accrued as of December 31, 2015.

Distribution Business

Argentina

In 2015, Edesur invested Ch$ 145 billion in over 513 construction works, enabling an increase in the power carried by the network by 475 MVA. These increases are due to the repowering of Bosques, Caballito, Calzada, Gerli, Gutiérrez, Pérez Galdós, Piñeyro, Santa Rita, Sarandí and Transradio substations. These construction works are complemented by their respective medium voltage distribution networks.

In addition, the installation of medium voltage cables for the three 35 MVA substations acquired in 2014 and located in Azcuénaga, Liniers and Santa Rita were finalized.

For medium and low voltage, 83 transformation centers were installed and/or renovated.

In 2015, Edesur implemented the following contingency plans to cope with extreme temperatures that affected energy consumption: the “2015 Winter Plan” and “2015-2016 Summer Plan”, which established contingency plans, preventive and corrective maintenance of facilities and networks, deepening communication plans, plans of allocation and reallocation of human resources to emergency conditions and implementation of the Emergency Center to manage movement, availability and fuel supplies for generators.

During 2015, a new control and data acquisition systems were installed, which allows monitoring and remote operations of high voltage facilities and equipment of high/high voltage substations and high/medium voltage substations (SCADA system).

In addition, the first stage of the STM system (SCADA for the medium voltage network) was developed and it is expected to begin production in 2016.

Brazil

In 2015, Ampla invested a total of Ch$ 158 billion, allocated to implementing new connections, improving the quality of distribution networks and carrying out projects to reduce energy losses. Ampla invested in control systems, through the use of technology and social activities.

Coelce invested Ch$ 89 billion targeted at satisfying network and connection needs of clients and to support the recent sustained growth in demand in the State of Ceará.

Colombia

In 2015, Codensa invested Ch$ 108 billion, of which Ch$ 61 billion was used for the expansion mainly focused on connections to new clients and networks to improve service quality. In addition, Ch$ 47 billion was invested in projects meant to ensure the sustainability of the distribution business, meet load increases, comply with legal requirements, provide corrective maintenance, improve public lighting infrastructure, invest in systems and communications.

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Peru

In 2015, Edelnor invested Ch$ 98 billion, representing an increase of 13% in comparison to 2014. The most important investments were the extension of capacity of transformation substations and transmission lines including works for the new Malvinas, Philadelphia and Comas substations (Ch$ 29 billion), the extension and strengthening of medium and low voltage networks (Ch$ 26 billion), the extension of capacity in feeders in medium and low voltage (Ch$ 6 billion), the assistance/electrification of new projects for the extension of electric networks in shanty towns (Ch$ 6 billion), the safety improvement in facilities (Ch$ 11 billion), the improvement in public lighting infrastructure (Ch$ 2 billion) and other investments focused on reducing commercial losses (Ch$ 3 billion).

Major Encumbrances

Costanera’s supplier debt with Mitsubishi Corporation (“MC”) corresponds to the remaining payments on equipment purchased from MC in November 1996, which was refinanced in October 2014. The value of the assets pledged to secure this debt was Ch$ 10.8 billion as of December 31, 2015. Additionally, Costanera has granted liens in favor of Credit Suisse in guarantee of a loan, which were valued at Ch$ 3.1 billion as of December 31, 2015.

Climate Change

In recent years, the countries in which we operate have seen an increase of developments related to NCRE and strategies to combat climate change. This has required both the public and private sectors to adopt strategies in order to comply with the new environmental requirements, as evidenced by legal obligations at the local level, commitments assumed by countries at the international level, and the demanding requirements of the international markets.

NCREs provide energy with minimal environmental impact and with almost no CO₂ emissions. They are therefore considered technological options that strengthen sustainable energy development as they supplement the production of traditional generators.

The Callahuanca hydroelectric power station (80.2 MW in operation since 1938) is the NCRE facility that we own, and which has contributed clean and renewable energy to its national grid. Regarding the development of CO₂ emission reduction mechanisms, the projects in the Clean Development Mechanism (“CDM”) circuit were as follows:

Ventanilla Conversion from Single-Cycle to Combined-Cycle Power Generation Project: On June 20, 2011, the UNFCCC approved the registration of this project in Peru as a CDM for 7 years, which term is subject to renewal, which recognizes that it may verify and trade the greenhouse gas emissions that it will be avoided during its useful life.

On October 31, 2013, the Ventanilla Conversion from Single-Cycle to Combined-Cycle Power Generation Project obtained the registration/verification under the Voluntary Emission Reductions (“VER”) + standard. A total amount of 2,496,494 tons of CO₂ were avoided during the period of October 19, 2006 through June 19, 2011. As a result, Edegel received credit for 2,496,494 tons of CO₂ emissions in the form of pre-CDM VERs. Additionally, in June 2014, 7,314 tons of CO₂of VERs were negotiated at a value of €0.5 per tons of CO₂as part of the voluntary neutralization policy of the group.

The Rehabilitation of the Callahuanca Hydroelectric Power Station Project: On January 4, 2008, the UNFCCC approved the registration of this project in Peru as a CDM for 7 years, which term is subject to renewal, which recognizes that it may verify and trade the greenhouse gas emissions that it will be avoided during its useful life.

On July 7, 2008 the Rehabilitation of the Callahuanca Hydroelectric Power Station Project obtained the registration/verification under the VER + standard. A total amount of 19,951 tons of CO₂ were avoided during 2007. As a result, Edegel received credit for 19,949 tons of CO₂ emissions in the form of pre-CDM VERs.

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Detail of CDM Projects Processed in 2015


CDM project	Company/country	Position as of December 31, 2015	Emission factor (tons CO₂e/MWh)	Approximate emissions avoided (tons CO₂e/year)⁽¹⁾

Ventanilla Conversion from Single-Cycle to Combined-Cycle Power Generation Project	Edegel (Peru)	Registered with the Executive Authority of the UNFCCC since 2011. CDM procedure implemented.	0.454	407,296

Ventanilla Conversion from Single-Cycle to Combined-Cycle Power Generation Project	Edegel (Peru)	Registered with the VER + Standard (Voluntary Standard) since October 2013.	0.454	407,296

Rehabilitation of the Callahuanca hydroelectric power station	Edegel (Peru)	Registered with the Executive Authority of the UNFCCC since 2008. CDM procedure implemented.	0.449	18,189

Rehabilitation of the Callahuanca hydroelectric power station	Edegel (Peru)	Registered with the VER + Standard (Voluntary Standard) since July 2008.	0.449	18,189

(1)	Obtained from the PDD (Project Design Document) of each project.

It is expected that our climate change guidelines will be similar to the current Enel group climate change guidelines as part of our commitment to combat climate change.

In compliance with the group climate change guidelines, Edegel has secured the certification of its carbon footprint for a fourth time. The Spanish Association of Standards and Certification (Asociación Española de Normalización y Certificación or “AENOR”), an independent certification authority, acknowledged the validity of the methodology. Acknowledgement by AENOR includes verification of the group’s carbon footprint reports from 2009 to 2014. A carbon footprint is the sum of all greenhouse gases (“GHGs”) produced by a company in the course of its business activity. The first step involves measuring our carbon footprint.

The tools used to calculate emissions in Edegel include audits at its facilities. This enables Edegel to monitor carbon footprint in all installations associated with the generation of electrical energy. Calculating the carbon footprint also enables Edegel to identify phases of its activities with the greatest potential to reduce emissions.

As part of the process of calculating our carbon footprint, we plan to obtain a GHG inventory, including direct emissions associated with activities controlled by us. We also plan to obtain a GHG inventory of indirect emissions, which are not generated through sources we control but are consequences of our activities.

Item 4A.

Unresolved Staff Comments

None

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Item 5.

Operating and Financial Review and Prospects

A.	Operating Results.

General

The following discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in Item 18 in this Report, and “Selected Financial Data,” included in Item 3 herein. Our audited consolidated financial statements as of December 31, 2015 and 2014 and for the three years ended December 31, 2015 have been prepared in accordance with IFRS, as issued by the IASB.

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

We are an electricity company that owns and operates generation, transmission and distribution companies in Argentina, Brazil, Colombia and Peru. Virtually all of our revenues, income and cash flows come from the operations of our subsidiaries, jointly-controlled companies and associates in these countries.

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

Our diversification strategy aims to balance the impact of significant changes in one country with opposing changes in other countries, or within generation and distribution, in order to reduce, as much as practicable, the adverse impact of variations in the main factors that affect our consolidated operating results. The impact of these factors on us, for the years covered by this Report, is discussed below.

While we directly own less than 21.6% of the equity interests and 25.1% of the voting rights of Emgesa as of the date of this Report, Emgesa is regarded as our subsidiary because of Endesa Américas’ control over Emgesa. Endesa Américas directly owns 26.9% of the equity interest and 31.3% of the voting rights of Emgesa (through the ownership of shares with voting rights). Although Endesa Chile directly owns less than 50% of the equity interest and the voting rights of Emgesa, Endesa Américas is deemed to exercise control over Emgesa as a result of the transfer of 25.1% of the voting rights to Endesa Américas by us and pursuant to a shareholders’ agreement with Empresa de Energía de Bogotá S.A (which owns 51.5% of the equity interest in Emgesa) signed on August 27, 1997. The transfer of the voting rights originated with a prior owner of the 21.6% equity interest and has been continued with each subsequent owner (currently Enersis Américas). The shareholders’s agreement along with the voting rights transferred to Endesa Américas, gives it the right to appoint a majority of Emgesa’s Board members and, therefore Endesa Américas consolidates Emgesa in its consolidated financial statements.

On October 23, 1997, Enersis and Chilectra acquired 48.4% of the equity interest in Codensa through an international public bidding process held by the Colombian government. The remaining interest is held by EEB. As of the date of this Report, we own 48.4% of the equity interest and 57.2% of the voting rights of Codensa (through the ownership of shares with voting rights) both directly and indirectly through our ownership of Chilectra Américas. While we own less than 50% of the equity interests, Codensa is regarded as our subsidiary because of our voting rights. Pursuant to a shareholders’ agreement with EEB (which owns 51.6% of the equity interest in Codensa) signed on October 23, 1997, we have the right to appoint the majority of Codensa’s Board members and, therefore, we continue to consolidate Codensa in our consolidated financial statements.

Since April 1, 2013, we have consolidated certain companies contributed by Endesa Spain to us in connection with our 2013 capital increase, which affected the comparison of results of operations for the years ended December 31, 2014 and 2013.

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a.	Generation and Transmission Business

Our electricity generation and transmission business is conducted in Argentina through Costanera, El Chocón and Dock Sud, in Brazil through Cachoeira Dourada, Fortaleza and CIEN in Colombia through Emgesa, and in Peru through Edegel and EEPSA. A substantial part of our generation capacity depends on the hydrological conditions prevailing in the countries in which we operate. Our installed capacity as of December 31, 2015, 2014 and 2013 was 10,932 MW, 10,497 MW and 10,257 MW, respectively. In those years, our hydroelectric installed capacity represented 53.0%, 51.1% and 50.9% of our total installed capacity, respectively. See “Item 4. Information on the Company – D. Property, Plant and Equipment.”

Hydroelectric generation was 22,171 GWh, 22,439 GWh and 20,979 GWh in 2015, 2014 and 2013, respectively. Our hydroelectric generation in 2015 was 1.2% lower than in 2014 mainly due to less favorable hydrological conditions in Brazil and Colombia, partially offset by better hydrological conditions in Argentina and Peru.

In the countries in which we operate, hydrological conditions can range from very wet to extremely dry. In between these two extremes, there are a wide range of possible hydrological conditions. For instance, a new year of drought has very different impacts on our business, depending on whether it follows several years of drought or a period of abundant rainfall. On the other hand, a good hydrological year has less marginal impact if it comes after several wet years than after a prolonged drought.

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

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

Hydrological conditions in Colombia vary significantly throughout the different regions and depend on geographical conditions and topography. There are two rainfall patterns. One is characterized by two rainy periods separated by a drier season, that is observed in the Andean region and in the center of the country, the most populated area and the center of economic activity, where all our hydroelectric plants, except the Guavio plant, are located. The second pattern is characterized by a rainy season followed by a drier season, which is observed in the Orinoquia region (eastern part of the country), where our largest hydroelectric plant, Guavio (1,213 MW), is located and its hydrological conditions are influenced by the Amazon.

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

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

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Hydrological conditions affect electricity market prices, generation costs, spot prices, tariffs and the mix of hydroelectric or thermal generation, which is constantly being defined by the market operator to minimize the operating cost of the entire system. Pass through hydroelectric generation is almost always the least expensive method to generate electricity and normally has a marginal cost close to zero. However, authorities might assign a cost for the use of water of reservoirs, which may lead to hydroelectric generation not necessarily being the lowest marginal cost. The cost of thermal generation does not depend on hydrological conditions but instead on international commodity prices for LNG, coal, diesel and fuel oil.

Spot prices primarily depend on hydrological conditions and commodity prices. Under most circumstances, abundant hydrological conditions lower spot prices while dry conditions normally increase prices. Spot market prices affect us because we purchase electricity in the spot market in case that we have deficits between our contracted energy sales and our generation, and we sell electricity in the spot market if we have electricity surpluses.

There are many other factors that may affect operating income, including the level of contracted sales, purchases/sales in the spot electricity market, commodity prices, energy demand, technical and unforeseen problems that can affect the availability of our thermal plants, plant locations in relation to urban demand centers, and transmission system conditions, among others.

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

Argentina is a controlled market, with a defined remuneration scheme and no energy and commodity trading. Market prices are unrelated to hydrological conditions or commodity prices. There is no electricity market since free bilateral trading has been suspended. As a consequence, El Chocón sells most of its energy to the market operator at the regulated price, which is not affected by hydrological conditions and its results depend mainly on the amount of electricity it generates. In 2015, El Chocón’s generation increased, resulting in a higher operating income than during the same period in 2014, primarily as a result of better hydrological conditions in the Comahue region. Hydrological conditions were better during 2014 than 2013 for El Chocón but because of the devaluation of the Argentine peso in relation to the Chilean peso, operating income was similar to that in 2013. Costanera and Dock Sud are thermal plants, and therefore their operating results depend on their own thermal generation.

In Brazil, there is an electricity relocation mechanism that provides financial protection against hydrological risks for hydroelectric generators. The market operator defines which hydroelectric plants generate electricity to minimize the system cost and the generators with deficits buy energy from the generators with surpluses at a defined price, the marginal operating cost is set annually by ANEEL. All hydroelectric generators that participate in the Electricity Reallocation Mechanism (“MRE” in its Portuguese acronym), participate in the overall hydroelectric generation dispatched in proportion to their assured energy, regardless their contracted sales. Since 2014, drought has affected all hydroelectric generators that participate in the MRE, and the overall hydroelectric generation system has not been able to cover the assured energy; therefore, hydroelectric generators, including our subsidiaries, buy additional energy in the spot market, at higher prices. Operating results of Cachoeira Dourada were adversely affected in 2014 and 2015 compared to 2013. However, during 2015, Cachoeira Dourada reduced its exposure to the spot market with a positive impact in operating results. Operating income was negatively affected by devaluation of the Brazilian real in relation to the Chilean peso in 2015, and positively by its appreciation in 2014. Fortaleza is a thermal plant, and its results depend mainly on its thermal generation, its generation costs, energy purchase cost and its commercial policy.

In Colombia, hydrological conditions in 2015 and 2014 were influenced by El Niño phenomenon which resulted in drought conditions for the whole system with very high spot prices. However, hydrological conditions affecting our Guavio hydroelectric plant were wet, allowing Emgesa to compensate for the lower hydroelectric generation of its other hydroelectric plants affected by the drought in 2015. In 2014, Emgesa increased its

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hydroelectric generation compared to 2013. In 2015 and 2014, Emgesa increased its contracted sales and was able to sell its surpluses on the spot market at higher prices, positively affecting Emgesa’s operating income in both years. Operating income was negatively affected by the devaluation of the Colombian peso in relation to the Chilean peso in 2015, and positively by its appreciation in 2014.

In Peru, since 2013, hydrological conditions have been better than the historical average, allowing slightly higher hydroelectric generation, which combined with a drop in commodity prices, the slowing economic growth rate and delays in mining projects, has resulted in electricity oversupply, and even lower spot prices. In 2015, Edegel generated more energy than its contracted sale requirements, despite a decrease in its thermal generation, due to the lower demand of one of its main mining customers. Edegel’s energy surplus is sold on the spot market at a lower price, with negative impact on operating income, which was partially offset by appreciation of the Peruvian sol in relation to the Chilean peso in 2015. Operating income in 2014 was higher than in 2013, mainly due to higher physical sales to regulated customers and being able to purchase energy on the spot market at lower prices. EEPSA is a thermal plant, and its results depend mainly on its generation, its generation costs, energy purchase costs and its commercial policy.

b.	Distribution Business

Our electricity distribution business is conducted in Argentina through Edesur, in Brazil through Ampla and Coelce, in Colombia through Codensa, and in Peru through Edelnor. For the year ended December 31, 2015, electricity sales increased by 1.6% compared to 2014, totaling 62,838 GWh. Currently, our distributors serve important South American cities, providing electricity to over 13 million customers. These companies face growing electricity demand, partly because of demographic growth and partly because of higher consumption, which obliges them to continually invest in their facilities.

In the distribution business, revenues are mainly derived from the resale of electricity purchased from generators. Revenues associated with distribution include the recovery of the cost of electricity purchased and the resulting revenue from the “Value Added from Distribution,” or VAD, which is associated with the recovery of costs and the return on the investment with respect to the distribution assets, plus the physical energy losses permitted by the regulator. Other revenues derived from our distribution services consist of charges for new connections and the maintenance and rental of meters, among others.

Among the key factors that impact financial results in the distribution business are regulations. This is especially true when the actions adopted by government authorities define or intervene with directly regulated customer tariffs, or affect the price at which distributors can buy their energy. Our ability to buy electricity relies highly on generation availability and to a lesser degree on regulation. In addition, we are focusing on reducing physical losses, especially those due to illegally tapped energy, and improving our collectability indices and our efficiency. The ability to buy electricity relies highly on generation availability and government regulation.

c.	Selective Regulatory Developments

The regulatory framework governing our businesses in the countries in which we operate has a material effect on our operating results. In particular, regulators set (i) energy prices in the generation business, taking into consideration factors such as fuel costs, reservoir levels, exchange rates, future investments in installed capacity and demand growth, and (ii) distribution tariffs taking into account the costs of energy purchases paid by distribution companies (which distribution companies pass on to their customers) and the “VAD, all of which are intended to reflect investment and operating costs incurred by distribution and generation companies and to allow our companies to earn a regulated level of return on their investments and guarantee service quality and reliability. The earnings of our electricity subsidiaries are determined to a large degree by regulators, mainly through the tariff setting process.

The distribution tariff setting processes are carried out according to calendars defined by the regulators in each country. For example, in Colombia, Codensa’s tariff review is currently in progress and it is expected to

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conclude in 2016. In Peru, Edelnor’s tariffs will be reviewed in 2017, and in the case of Coelce and Ampla, the next review is expected in 2019. Each of these reviews presents its own particularities and challenges, since tariff reviews seek to capture distribution efficiency and economies of scale based on economic growth.

In Argentina, the Argentine Secretary of Energy published Resolutions No. 95/2013, No. 529/2014 and No. 482/2015, which set forth a regulated remuneration schedule for generators. In addition, the Secretary of Energy published several Resolutions, including Resolutions No. 250/2013 and No. 32/2015, oriented to increase distributor’s revenues to finance their higher operating costs since the tariff has been unchanged since 2008. On January 27, 2016, the Ministry of Energy and Mining enacted Resolution No. 6/2016 allowing increases in the tariff for the period February 2016 to April 2017.

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

d.	Economic Conditions

Macroeconomic conditions, such as changes in employment levels and inflation or deflation in the countries in which we operate may have a significant effect on our operating results. Macroeconomic factors, such as the variation of a local currency against the U.S. dollar, may impact our operating results, as well as our assets and liabilities, depending on the amounts denominated in U.S. dollars. For example, a devaluation of local currencies against the U.S. dollar increases the cost of capital expenditure plans. For additional information, see “Item 3. Key Information — D. Risk Factors — Foreign exchange risks may adversely affect our results and the U.S. dollar value of dividends payable to ADS holders.” and “— South American economic fluctuations may affect our results from operations and financial condition as well as the value of our securities.”

In order to determine whether Argentina could be qualified as a hyperinflationary economy, we have considered the behavior of historical and projected inflation, along with other indicators established in IAS 29, Financial Reporting in Hyperinflationary Economies. We have also taken into consideration various analyses and studies issued by international agencies such as the International Practices Task Force of the SEC Regulations Committee, which have suggested that Argentina is not currently a hyperinflationary economy. In addition, we have checked with our peers in Argentina and, in that context, have noted that publicly held Argentine companies which adopted IFRS have not introduced adjustments to reflect inflation since the date of their transition to IFRS. In brief, we have not observed objective verifiable data leading to a conclusion that the Argentine economy should be considered a hyperinflationary economy in accordance with the indicators set forth in IAS 29.

Local Currency Exchange Rate

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

As of December 31, 2015, our consolidated debt totaled Ch$ 2,464 billion, of which 15.4% was denominated in U.S. dollars, 48.0% in Colombian pesos, 22.7% in Brazilian reais, 11.8% in Peruvian soles, 1.2% in Argentine pesos and 1.0% in Chilean pesos (including the Chilean UF, which is inflation-indexed).

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


	Local Currency U.S. Dollar Exchange Rates
	2015				2014				2013
	Average		Year End		Average		Year End		Average		Year End
Argentina (Argentine pesos per U.S. dollar)		9.25		13.04		8.11		8.55		5.48		6.52
Brazil (Brazilian reais per U.S. dollar)		3.34		3.90		2.35		2.66		2.16		2.34
Colombia (Colombian pesos per U.S. dollar)		2,748		3,149		1,997		2,392		1,870		1,927
Peru (Peruvian soles per U.S. dollar)		3.18		3.41		2.84		2.99		2.70		2.80
Chile (Chilean pesos per U.S. dollar)		654.66		710.16		570.40		606.75		495.18		524.61

Sources: Central banks of each country.

For the year ended December 31, 2015, our revenues were Ch$ 5,301 billion or US$ 8.1 billion, of which 38.0% was generated in Brazil, 29.6% in Colombia, 17.0% in Peru and 15.4% in Argentina.

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


	Foreign currency translation gains (losses)
	2015 ThCh$			2014 ThCh$			2013 ThCh$
Argentina		(77,204,771	)		(3,627,084	)		(3,190,880	)
Colombia		(160,522,082	)		(120,301,154	)		285,100
Brasil		(428,619,742	)		38,871,966			(74,547,700	)
Peru		23,681,916			67,649,223			716,176
Chile		(1,872,994	)		21,777,698			13,410

Total		(644,537,673	)		4,370,648			(76,723,893	)

The financial statements of foreign companies with functional currencies other than the Chilean peso are translated as follows: (i) for assets and liabilities, the prevailing exchange rate on the closing date of the financial statements is used; (ii) for items in the comprehensive income statement, the average exchange rate for the period is used; and (iii) equity remains at the historical exchange rate from the date of acquisition or contribution, and retained earnings at the average exchange rate at the date of origination.

The following table sets forth the closing and average local currencies per Chilean peso exchange rates for the years indicated:


	Local Currency Chilean Peso (Ch$) Exchange Rates
	2015				2014				2013
	Average		Year End		Average		Year End		Average		Year End
Argentina (Argentine pesos per Ch$)		0.01412		0.01824		0.01423		0.01394		0.01105		0.01240
Brazil (Brazilian reais per Ch$)		0.00509		0.00558		0.00412		0.00437		0.00436		0.00449
Colombia (Colombian pesos per Ch$)		4.19673		4.47257		3.50421		3.92279		3.77226		3.67624
Peru (Peruvian soles per Ch$)		0.00486		0.00480		0.00498		0.00493		0.00546		0.00532
Sources: Central banks of each country.

Calculation of the appreciation or devaluation of foreign currencies against the Chilean peso for one period with respect to the previous one is made by determining the percentage change between the reciprocals of the average values of Chilean pesos per any given foreign currency. It is a measure of the percent change in two periods in the amount of foreign currency needed to exchange for one Chilean peso. A positive percent change

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means that the foreign currency appreciated with respect to the Chilean peso. A negative percent change means that the foreign currency devaluated with respect to the Chilean peso.

The following table shows the appreciation or devaluation of 2015 versus 2014 and 2014 versus 2013 for the closing and average local currencies per Chilean peso:


	Appreciation/(Devaluation) per Chilean Peso (Ch$)
	2015/2014						2014/2013
	Average			Year End			Average			Year End
Argentine pesos		0.8	%		-23.6	%		-22.3	%		-11.0	%
Brazilian reais		-19.1	%		-21.7	%		5.7	%		2.9	%
Colombian pesos		-16.5	%		-12.3	%		7.6	%		-6.3	%
Peruvian soles		2.4	%		2.7	%		9.6	%		8.1	%

In the analysis of results of operations included below, when the impacts of the appreciation or devaluation are significant, they are disclosed and explained below.

Argentina

As a result of the Argentine economic crisis in the early 2000s and the significant governmental intervention in the electricity sector in 2002, we have not received dividends from our Argentine subsidiaries Costanera, Edesur, El Chocón and Dock Sud since 2000, 2009, 2012 and 2013 (the year in which Dock Sud became our subsidiary), respectively. In 2011, we recognized a Ch$ 5.4 billion goodwill impairment charge for Costanera and a Ch$ 115.4 billion infrastructure and goodwill impairment charge for Edesur. Additional economic deterioration of Argentina, or of our subsidiaries that operate in that country, is not expected to have any material effect on our financial and operating results. For more information, see “Item 5. Operating and Financial Review and Prospects. — B. Liquidity & Capital Resources.”

Our Argentine operations do not affect our consolidated liquidity. Our Argentine cash and cash equivalents were Ch$ 46.2 billion as of December 31, 2015, which represents 3.9% of our total cash and cash equivalents. Of the total Argentine cash and cash equivalents, 97.2% is denominated in local currency, and the remaining 2.8% is denominated in U.S. dollars. Our Argentine debt was Ch$ 69.5 billion as of December 31, 2015, representing 2.8% of our total debt. Of the total Argentine debt, 43.4% is denominated in local currency, and the remaining 56.6% is denominated in U.S. dollars. The currency translation effect of converting the statements of comprehensive income from the Argentine peso to the Chilean peso led to a 0.8% increase in the amount in Chilean pesos in 2015 compared to 2014. A default by any of our Argentine subsidiaries on their indebtedness would not affect us since we do not have any debt agreements that include cross default provisions that could be triggered by any Argentine or any other non-Chilean subsidiary’s default. For more information, see “Item 5. Operating and Financial Review and Prospects. — B. Liquidity & Capital Resources.”

The Argentine government avoided increasing electricity distribution tariffs to end customers, and seasonal prices remained fixed in Argentine peso until January 2016. From February 2016, seasonal price was calculated based on the operational programming, dispatch and price calculations, reflecting the actual energy cost and reducing subsidies. On the other hand, generators’ tariffs are also regulated based on defined fixed and variable remuneration. In the recent past, due to tariff controls, revenues of electric utility companies do not always cover their operating costs. Argentine authorities have created a new mechanism to improve the financial situation of these companies in recognition that their performance is directly related to the regulatory framework. For more detail, see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Argentina.”

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e.	Critical Accounting Policies

Critical accounting policies are defined as those that reflect significant judgments and uncertainties which would potentially result in materially different results under different assumptions and conditions. We believe that our most critical accounting policies with reference to the preparation of our combined financial statements under IFRS are those described below.

For further detail of the accounting policies and the methods used in the preparation of the consolidated financial statements, see Notes 2 and 3 of the Notes to our consolidated financial statements.

Impairment of Long-Lived Assets

During the year, and principally at year end, we evaluate whether there is any indication that an asset has become impaired. Should any such indication exist, we estimate the recoverable amount of that asset to determine, where appropriate, the amount of impairment. In the case of identifiable assets that do not generate cash flows independently, we estimate the recoverability of the cash generating unit to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

Notwithstanding the preceding paragraph, in the case of cash generating units to which goodwill or intangible assets with an indefinite useful life have been allocated, a recoverability analysis is performed routinely at each period end.

The recoverable amount is the greater of (i) the fair value less the cost needed to sell the asset and (ii) the value in use. “Value in use” is defined as the present value of the estimated future cash flows. In order to calculate the recoverable value of property, plant and equipment, goodwill and intangible assets, that form part of a cash generating unit, we use value in use criteria in nearly all cases.

To estimate the value in use, we prepare future pre-tax cash flow projections based on the most recent budgets available. These budgets incorporate management’s best estimates of cash generating units’ revenues and costs using sector projections, past experience and future expectations.

In general, these projections cover the next five years, estimating cash flows for subsequent years by applying reasonable growth rates, between 3.1% and 11.1%, which are not increasing nor do they exceed the average long-term growth rates for the particular sector and country.

These cash flows are discounted at a given pre-tax rate in order to calculate their present value. This rate reflects the cost of capital of the business and the geographical area in which the business is conducted. The discount rate is calculated taking into account the current time value of money and the risk premiums generally used by market participants for the specific business activity and the country involved.

The pre-tax nominal discount rates applied in 2015, 2014 and 2013 are as follows:


		Year ended December 31,
		2015				2014				2013
Country	Currency	Minimum		Maximum		Minimum		Maximum		Minimum		Maximum
		(in %)
Argentina	Argentine peso		32.7		39.4		23.3		38.9		39.2		44.4
Brazil	Brazilian reais		11.1		21.1		9.7		22.7		9.0		18.8
Colombia	Colombian peso		8.5		15.1		8.0		13.3		8.5		14.2
Peru	Peruvian sol		7.3		13.5		7.3		14.3		7.3		13.9

If the recoverable amount is less than the net carrying amount of the cash generating unit, the corresponding impairment loss provision is recognized for the difference, and charged to “Reversal of impairment loss (impairment loss) recognized in profit or loss” in the consolidated statement of comprehensive income.

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Impairment losses recognized for an asset in prior periods are reversed when its estimated recoverable amount changes, increasing the asset’s value with a credit to earnings, limited to the asset’s carrying amount if no adjustment had occurred. In the case of goodwill, any adjustments made are not reversible.

Litigation and Contingencies

We are currently involved in certain legal and tax proceedings. As discussed in Note 24 of the Notes to our consolidated financial statements as of December 31, 2015, we have estimated the probable outflows of resources for resolving these claims to be Ch$ 187 billion. We have reached this estimate after consulting our legal and tax advisors who are defending us in these matters and after an analysis of potential results, assuming a combination of litigation and settlement strategies.

Hedge Revenues Directly Linked to the U.S. Dollar

We have established a policy to hedge the portion of our revenues directly linked to the U.S. dollar by obtaining financing in U.S. dollars. Exchange differences related to this debt, as they are cash flow hedge transactions, are charged net of taxes to an equity reserve account that forms part of Other Comprehensive Income and recorded as income during the period in which the hedged cash flows are realized. This term has been estimated at ten years.

This policy reflects a detailed analysis of our future U.S. dollar revenue streams. Such analysis may change in the future due to new electricity regulations limiting the amount of cash flows tied to the U.S. dollar.

Pension and Post-Employment Benefit Liabilities

We have various defined benefit plans for our employees. These plans pay benefits to employees at retirement and use formulas based on years of service and the compensation of the participants. We also offer certain additional benefits for particular retired employees.

The liabilities shown for the pensions and post-employment benefits reflect our best estimate of the future cost of meeting our obligations under these plans. The accounting applied to these defined benefit plans involves actuarial calculations which contain key assumptions including employee turnover, life expectancy, retirement age, discount rates, the future level of employee compensation and benefits, the claims rate under medical plans and future medical costs. These assumptions change as economic and market conditions vary and any change in any of these assumptions could have a material effect on the reported results from operations.

The effect of an increase of one percentage in the discount rate used to determine the present value of the post-employment defined benefits would decrease the liability by Ch$ 32.6 billion, Ch$ 46.8 billion and Ch$ 42.0 billion as of December 31, 2015, 2014 and 2013, respectively, and the effect of a decrease of one percentage in the rate used to determine the present value of the post-employment defined benefits would increase the liability by Ch$ 38.0 billion, Ch$ 56.7 billion and Ch$ 49.3 billion as of December 31, 2015, 2014 and 2013, respectively.

Recent Accounting Pronouncements

Please see Note 2.2 of the Notes to our consolidated financial statements for additional information regarding recent accounting pronouncements.

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2.	Analysis of Results of Operations for the Years Ended December 31, 2015 and 2014.

I. Analysis of Results from Continuing Operations

Revenues from Continuing Operations

Generation and Transmission Business

The following table sets forth the electricity sales of our subsidiaries and the corresponding changes for the years ended December 31, 2015 and 2014:


	Electricity sales during the year ended December 31,
	2015		2014		Change			Change
	(in GWh)							(in %)
Costanera (Argentina)		8,168		7,051		1,117			15.8
El Chocón (Argentina)		3,801		3,391		410			12.1
Dock Sud (Argentina)		3,802		4,834		(1,032	)		(21.3	)
Cachoeira Dourada (Brazil)		3,215		3,903		(688	)		(17.6	)
Fortaleza (Brazil)		3,326		3,205		121			3.8
Emgesa (Colombia)		16,886		15,773		1,113			7.1
Edegel (Peru)		8,633		9,320		(687	)		(7.4	)
EEPSA (Peru)		650		596		54			9.1

Total		48,481		48,073		408			0.8

Distribution Business

The following table sets forth the electricity sales of our subsidiaries, by country, and their corresponding variations for the years ended December 31, 2015 and 2014:


	Electricity sales during the year ended December 31,
	2015		2014		Change			Change
	(in GWh)				(in %)
Edesur (Argentina)		18,492		17,972		520			2.9
Ampla (Brazil)		11,547		11,678		(131	)		(1.1	)
Coelce (Brazil)		11,229		11,165		64			0.6
Codensa (Colombia)		13,946		13,660		286			2.1
Edelnor (Peru)		7,624		7,338		286			3.9

Total		62,838		61,813		1.025			1.6

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The following table sets forth the revenues from continuing operations, by business segment and company for the years ended December 31, 2015 and 2014:


	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business
Costanera (Argentina)		100,857			75,194			25,663			34.1
El Chocón (Argentina)		40,005			30,174			9,831			32.6
Dock Sud (Argentina)		69,963			61,606			8,357			13.6
Cemsa (Argentina)		2,270			1,281			989			77.2
Cachoeira Dourada (Brazil)		91,563			158,965			(67,402	)		(42.4	)
Fortaleza (Brazil)		159,052			210,793			(51,741	)		(24.5	)
CIEN (Brazil)		58,667			70,800			(12,133	)		(17.1	)
Emgesa (Colombia)		778,756			753,373			25,383			3.4
Edegel (Peru)		382,453			353,795			28,658			8.1
EEPSA (Peru)		58,093			50,849			7,244			14.2
Other		(6,917	)		(3,961	)		(2,956	)		74.6

Total		1,734,762			1,762,869			(28,107	)		(1.6	)

Distribution Business
Edesur (Argentina)		607,345			371,412			235,933			63.5
Ampla (Brazil)		1,026,680			1,092,282			(65,602	)		(6.0	)
Coelce (Brazil)		810,184			876,944			(66,760	)		(7.6	)
Codensa (Colombia)		884,468			982,771			(98,303	)		(10.0	)
Edelnor (Peru)		562,046			478,700			83,346			17.4

Total		3,890,723			3,802,109			88,614			2.3
Less: consolidation adjustments and non-core activities		(324,045	)		(358,608	)		34,563			(9.6	)

Total		5,301,440			5,206,370			95,070			1.8

Generation and Transmission Business: Revenues from Continuing Operations

In Argentina, revenues from Costanera increased by Ch$ 25.7 billion or 34.1% in 2015, comprised principally of Ch$ 8.8 billion due to tariff increases related to Resolution No. 482/2015, Ch$ 5.6 billion due to 1,195 GWh higher thermal dispatch, and Ch$ 3 billion related to its combined-cycle availability contracts executed with the Secretary of Energy. Revenues from El Chocón also increased by 32.6%, or Ch$ 9.8 billion, mostly due to Ch$ 7.6 billion related to 607 GWh higher hydroelectric dispatch because of improved hydrological conditions and Ch$ 2.6 billion attributable to higher tariffs related to Resolution No. 482/2015. In addition, revenues from Dock Sud also increased by 13.6% or Ch$ 8.4 billion principally due to a Ch$ 7.3 billion increase in energy sales, mainly due to higher tariffs related to Resolution No. 482/2015.

In Brazil, revenues from Cachoeira Dourada decreased by Ch$ 67.4 billion, or 42.4%, in 2015, mainly due to a Ch$ 37.1 billion decrease as a consequence of a lower price on the spot market and a Ch$ 30.3 billion decrease due to the devaluation of Brazilian real in relation to the Chilean peso, which resulted in a 19.1% decline in Chilean peso in 2015 as compared to 2014. Revenues from Fortaleza decreased by 24.5% or Ch$ 51.7 billion for the year 2015 as a result of a Ch$ 40.2 billion decrease due to devaluation of Brazilian real and a Ch$ 11.6 billion decline of the price on the spot market. Revenues from CIEN decreased by 17.1% or Ch$ 12.1 billion mainly due to devaluation of Brazilian real that resulted in Ch $ 12.9 million lower revenues.

Revenues from Emgesa in Colombia increased by Ch$ 25.4 billion, or 3.4%, in 2015, due to Ch$ 60.2 billion higher physical sales of 1,113 GWh, mainly contracted sales, and Ch$ 90.2 billion increase related to

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higher sales price on the spot market as a result of drought caused by El Niño phenomenon. These increases were partially offset by a Ch$ 124.1 billion loss due to the devaluation of Colombian peso in relation to the Chilean peso, which resulted in a 16.5% decline in terms of Chilean peso in 2015 as compared to 2014.

Revenues from Edegel in Peru grew by 8.1%, or Ch$ 28.7 billion in 2015. The appreciation of the Peruvian sol in relation to the Chilean peso resulted in a 2.4% increase in revenues, or Ch$ 52.8 billion compared to 2014. This was partly offset by a Ch$ 19.1billion decrease from 687 GWh of lower physical sales primarily to distribution companies, and a Ch$ 4.8 billion decrease due to lower spot prices because of lower demand. In EEPSA, revenues were 14.2%, or Ch$ 7.2 billion, higher than in 2014 mainly due to Ch$ 7.6 billion increase due to the appreciation of the Peruvian sol.

Distribution Business: Revenues from Continuing Operations

Revenues from Edesur in Argentina increased by Ch$ 235.9 billion, or 63.5% in 2015, mainly due to a Ch$351.5 billion increase related to the application of Resolution No. 32/2015, which was comprised of: (i) Ch$ 305.9 billion of anon-recurring revenues to finance the expenses and investments associated with the normal public electricity energy distribution service; (ii) Ch$ 34.0 billion due to the recognition as revenues from PUREE funds beginning on February 1, 2015; and (iii) Ch$ 11.6 billion of additional revenues due to recognition in January 2015 of costs not transferred to tariff. In 2014, Edesur also recorded extraordinary revenues of Ch$ 144.3 billion as a result of the application of Resolution No. 250/2013, which recognized costs not transferred to tariff between October 2013 and December 2014.

Revenues from Ampla, in Brazil, decreased by Ch$ 65.6 billion, or 6.0% in 2015, mainly due to the devaluation of the Brazilian real in relation to the Chilean peso of Ch$ 208.2 billion, partially offset by Ch$ 142.6 billion higher revenues from operations mainly composed by (i) Ch$ 83.5 billion increase due to 11% greater average sale price due to tariff adjustments, (ii) Ch$ 50 billion mainly due to regulatory revenues and (iii) Ch$ 16.3 billion greater revenues due to higher tolls. Revenues from Coelce decreased by Ch$ 66.8 billion, or 7.6%, in 2015, mainly due to the devaluation of Brazilian real of Ch$ 167.1 billion, partially offset by (i) Ch$ 57.5 billion increase due to 9% greater average sale price due to tariff adjustments and (ii) Ch$ 31 billion mainly due to regulatory revenues.

Revenues from Codensa decreased by Ch$ 98.3 billion, or 10.0%, in 2015, mainly due to Ch$162.1 billion related to the devaluation of the Colombian peso in relation to the Chilean peso, which was partially offset by (i) Ch$ 33.9 billion due to 5% increase of the average sale price due to tariff adjustments, (ii) Ch$ 14.2 billion higher physical energy sales of 286 GWh mainly due to greater commercial and industry activity and (iii) Ch$ 10.2 billion higher other distribution services.

In Peru, revenues from Edelnor increased by Ch$ 83.4 million in 2015, mainly attributable to higher sales of Ch$ 80.4 billion due to (i) Ch$ 51.9 billion, or 11%, higher average sale prices due to tariff adjustments, (ii) Ch$ 17.9 billion higher physical energy sales of 286 GWh and (iii) Ch$ 10.6 billion due to the appreciation of the Peruvian sol in relation to the Chilean peso.

Total Operating Costs from Continuing Operations

Total operating costs from continuing operations consist primarily of energy purchases from third parties, fuel consumption, depreciation, amortization and impairment losses, maintenance costs, tolls paid to transmission companies, employee salaries and administrative and selling expenses.

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The following table sets forth the consolidated operating costs in Chilean pesos and, as a percentage of total consolidated operating costs from continuing operations, for the years ended December 31, 2015 and 2014:


	Year ended December 31,
	2015				2014
	(in millions of Ch$)		(in %)		(in millions of Ch$)		(in %)
Energy purchases		1,885,916		46.6		1,824,003		47.8
Fuel consumption		258,114		6.4		205,534		5.4
Transportation costs		245,813		6.1		265,185		6.9
Other raw materials and combustibles		387,358		9.6		336,947		8.8
Other expenses⁽¹⁾		488,529		12.0		463,729		12.2
Employee benefit expense and other⁽¹⁾		420,597		10.4		333,898		8.7
Depreciation, amortization and impairment losses⁽¹⁾		360,354		8.9		389,073		10.2

Total Operating Cost from Continuing Operations		4,046,681		100.0		3,818,369		100.0

(1)	Corresponds to selling and administration expenses

The following table sets forth our total operating costs (excluding selling and administrative expenses) from continuing operations by business segment and company for the years ended December 31, 2015 and 2014:


	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business
Costanera (Argentina)		4,598			6,777			(2,179	)		(32.2	)
El Chocón (Argentina)		4,574			8,427			(3,853	)		(45.7	)
Dock Sud (Argentina)		43,266			34,976			8,290			23.7
Cemsa (Argentina)		1,018			203			815			401.5
Cachoeira Dourada (Brazil)		17,396			72,988			(55,592	)		(76.2	)
Fortaleza (Brazil)		111,229			158,318			(47,089	)		(29.7	)
CIEN (Brazil)		3,126			3,343			(217	)		(6.5	)
Emgesa (Colombia)		321,529			220,303			101,226			45.9
Edegel (Peru)		151,046			133,735			17,311			12.9
EEPSA (Peru)		26,124			20,916			5,208			24.9
Other		(5,965	)		(6,298	)		(333	)		(5.3	)

Total		677,941			653,688			24,253			3.7

Distribution Business
Edesur (Argentina)		157,387			161,995			(4,608	)		(2.8	)
Ampla (Brazil)		804,701			707,301			97,400			13.8
Coelce (Brazil)		581,689			606,422			(24,733	)		(4.1	)
Codensa (Colombia)		500,572			547,594			(47,022	)		(8.6	)
Edelnor (Peru)		379,015			315,116			63,899			20.3

Total		2,423,364			2,338,428			84,936			3.6
Less: consolidation adjustments and non-core activities		(324,103	)		(360,447	)		(36,344	)		(10.1	)

Total		2,777,202			2,631,669			145,533			5.5

Generation and Transmission Business: Operating Costs from Continuing Operations

In Argentina, operating costs decreased by Ch$ 2.2 billion, or 32.2% and Ch$ 3.9 billion, or 45.7% in Costanera and El Chocón respectively, mainly due to lower energy purchases in Costanera by Ch$ 2.3 billion and in El Chocón Ch$ 2.2 billion both because of the termination of sale contracts, which were not renewed under the actual regulation. Operating costs of Dock Sud rose by Ch$ 8.3 billion, or 23.7%, in 2015, mainly due to higher

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fuel consumption of Ch$ 7.8 billion, which was ultimately reimbursed by CAMMESA in the scheme remuneration.

In Brazil, operating costs of Cachoeira Dourada decreased by Ch$ 55.6 billion, or 76.2%, in 2015, mainly due to a lower spot average purchase price equivalent of Ch$ 37.8 billion and devaluation of the Brazilian real in relation to the Chilean peso that implied Ch$ 11.2 billion of lower costs. Operating costs of Fortaleza decreased by Ch$ 47.1 billion, or 29.7%, in 2015, mainly due to lower average purchase price amounting Ch$ 31.1 billion lower costs and the devaluation of the Brazilian real that resulted in Ch$ 17.8 billion decrease. Operating costs of CIEN decreased by Ch$ 0.2 billion, or 6.5%, in 2015, mainly due to other variable procurement and services expenses.

In Colombia, operating costs of Emgesa increased by Ch$ 101.2 billion, or 45.9%, in 2015, mainly attributable to Ch$ 95.2 billion higher energy purchases due higher spot prices, which in turn was as a result of the drought, and Ch$ 35.4 billion related to 550 MWh higher thermal generation. These increases were partially offset by a Ch$ 36.5 billion gain due to the devaluation of the Colombian peso in relation to the Chilean peso.

In Peru, operating costs of Edegel rose by Ch$ 17.3 billion, or 12.9%, in 2015, mainly due to a Ch$ 20.0 billion higher cost related to the appreciation of the Peruvian sol in relation to the Chilean peso. This increase was partially offset by a Ch$ 2.8 billion decrease related to lower spot prices. In EEPSA, operating costs increased by Ch$ 5.2 billion or 24.9% in 2015, mainly due to a Ch$ 3.1 billion increase due to the appreciation of the Peruvian sol and Ch$ 2.1 billion due to higher transportation costs.

Distribution Business: Operating Costs from Continuing Operations

In Argentina, Edesur’s operating costs decreased by Ch$ 4.6 billion, or 2.8% in 2015, mainly to lower energy purchases explained by a Ch$ 14.5 billion reduction related to lower average energy purchase prices partially offset by Ch$ 8.7 billion higher energy physical purchases and Ch$ 1.2 billion higher costs because of the appreciation of the Argentine peso in relation to the Chilean Peso.

In Brazil, operating costs of Ampla increased by Ch$ 97.4 billion, or 13.8%, in 2015, mainly due to Ch$ 175.3 billion higher energy purchase prices related to the drought, and Ch$ 58 billion higher regulatory costs, which was partially offset by Ch$ 134.8 billion lower costs related to the devaluation of the Brazilian real in relation to the Chilean peso. In Coelce, operating costs decreased by Ch$ 24.7 billion, or 4.1%, in 2015, due to depreciation of Brazilian real, which resulted in Ch$ 115.6 billion lower costs, which was partially offset by Ch$ 50.8 billion higher energy purchases due to higher purchase prices because of the drought and Ch$ 31 billion higher other procurement expenses related to higher regulatory costs.

In Codensa, operating costs decreased by Ch$ 47.0 billion, or 8.6%, in 2015, mainly due to the devaluation of the Colombian peso in relation to the Chilean peso that resulted in Ch$ 90.4 billion lower costs, which was partially offset by (i) Ch$ 28.1 billion higher energy purchase due to Ch$ 17.8 billion related to a 4.9% higher purchase price and Ch$ 10.3 billion increased physical energy purchases due to greater demand and (ii) Ch$ 9.3 billion higher transportation expenses.

Operating costs of Edelnor increased by Ch$ 63.9 billion, or 20.3%, in 2015, mainly due to Ch$ 43.8 billion increase attributable to 14% higher energy prices due to the incorporation of new contract as result of the latest energy bids and Ch$ 8.2 billion increased physical energy purchases. In addition, due to the appreciation of the Peruvian sol in relation to the Chilean peso, operating costs increased by Ch$ 7.4 billion.

Selling and Administrative Expenses from Continuing Operations

Selling and administrative expenses relate to salaries, compensation, administrative expenses, depreciation, amortization and impairment losses, and office materials and supplies.

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The following table sets forth our consolidated selling and administrative expenses, as a percentage of total consolidated selling and administrative expenses from continuing operations, for the years ended December 31, 2015 and 2014:


	Year ended December 31,
	2015		2014
	(in %)
Selling and Administrative Expenses as a Percentage of Total Selling and Administrative Expenses
Other expenses		38.5		39.1
Employee benefit expense and other		33.1		28.1
Depreciation, amortization and impairment losses		28.4		32.8

Total		100		100

The following table sets forth the selling and administrative expenses by business segment and company for the years ended December 31, 2015 and 2014:


	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business
Costanera (Argentina)		75,887			54,715			21,172			38.7
El Chocón (Argentina)		8,422			7,408			1,014			13.7
Dock Sud (Argentina)		23,387			17,165			6,222			36.3
Cemsa (Argentina)		2,507			1,912			595			31.1
Cachoeira Dourada (Brazil)		12,194			14,124			(1,930	)		(13.7	)
Fortaleza (Brazil)		12,956			15,481			(2,525	)		(16.3	)
CIEN (Brazil)		19,503			25,336			(5,833	)		(23.0	)
Emgesa (Colombia)		84,362			83,435			927			1.1
Edegel (Peru)		91,751			78,902			12,849			16.3
EEPSA (Peru)		14,305			12,345			1,960			15.9
Other		(3,149	)		(1,944	)		1,205			(62.0	)

Total		342,125			308,879			33,246			10.8

Distribution Business
Edesur (Argentina)		346,183			260,646			85,537			32.8
Ampla (Brazil)		195,556			201,135			(5,579	)		(2.8	)
Coelce (Brazil)		127,584			153,142			(25,558	)		(16.7	)
Codensa (Colombia)		148,308			173,202			(24,894	)		(14.4	)
Edelnor (Peru)		75,326			72,598			2,733			3.8
Other		1,383			1,250			128			10.2

Total		894,340			861,973			32,367			3.7
Less: consolidation adjustments and non-core activities		33,015			15,849			17,166			108.3

Total		1,269,480			1,186,701			82,779			7.0

Selling and administrative expenses from continuing operations increased by Ch$ 82.8 billion, or 7.0%, in 2015 as compared to 2014, as explained below.

In Argentina, selling and administrative expenses of Costanera increased by Ch$ 21.2 billion primarily due to higher payroll expenses of Ch$12.7 billion following increases in the workforce and in wages and benefits and higher depreciation and impairment loss expenses of Ch$ 5.3 billion. In Dock Sud, selling and administrative

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expenses increased by Ch$ 6.2 billion in 2015 as compared to 2014 mainly due to higher depreciation of Ch$ 5.8 billion and higher payroll expenses of Ch$ 2.1 billion resulting from increases in wages and benefits. In Edesur, selling and administrative expenses increased by Ch$ 85.5 billion mainly due to higher payroll expenses of Ch$ 72.9 billion, following increases in wages and benefits, higher other expenses of Ch$ 10.5 billion due to contractor costs and higher depreciation expenses of Ch$ 2.5 billion.

In our Brazilian and Colombian subsidiaries, selling and administrative expenses decreased mainly related to the favorable currency translation effect of converting the Brazilian real and Colombian peso to the Chilean peso, respectively.

In Peru, selling and administrative expenses of Edegel increased by Ch$12.9 billion in 2015 as compared to 2014, mainly attributable to higher depreciation expense and impairment losses of Ch$ 7.3 billion, higher other expenses related contract services of Ch$ 3.7 billion and higher payroll expenses of Ch$ 1.8 billion.

Operating Income from Continuing Operations

The following table sets forth our operating income from continuing operations by business segment and company for the years ended December 31, 2015 and 2014:


	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business
Costanera (Argentina)		20,372			13,702			6,670			48.7
El Chocón (Argentina)		27,009			14,339			12,670			88.4
Dock Sud (Argentina)		3,310			9,465			(6,155	)		(65.0	)
Cemsa (Argentina)		(1,255	)		(834	)		(421	)		50.5
Cachoeira Dourada (Brazil)		61,973			71,853			(9,880	)		(13.8	)
Fortaleza (Brazil)		34,867			36,994			(2,127	)		(5.7	)
CIEN (Brazil)		36,038			42,121			(6,083	)		(14.4	)
Emgesa (Colombia)		372,865			449,635			(76,770	)		(17.1	)
Edegel (Peru)		139,656			141,158			(1,502	)		(1.1	)
EEPSA (Peru)		17,664			17,588			76			0.4
Other		2,197			4,281			(2,084	)		(48.7	)

Total		714,696			800,302			(85,606	)		(10.7	)

Distribution Business
Edesur (Argentina)		103,775			(51,229	)		155,004			302.6
Ampla (Brazil)		26,423			183,846			(157,423	)		(85.6	)
Coelce (Brazil)		100,911			117,380			(16,469	)		(14.0	)
Codensa (Colombia)		235,588			261,975			(26,388	)		(10.1	)
Edelnor (Peru)		107,705			90,986			16,727			18.4
Other		(1,383	)		(1,250	)		(133	)		10.6

Total		573,019			601,708			(28,689	)		(4.8	)
Less: consolidation adjustments and non-core activities		(32,956	)		(14,010	)		(18,946	)		135.2

Total		1,254,759			1,388,000			(133,241	)		(9.6	)

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Other Results from Continuing Operations

The following table sets forth the other results from continuing operations for the years ended December 31, 2015 and 2014:


	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Financial results
Financial income		294,770			251,122			43,648			17.4
Financial costs		(385,455	)		(432,314	)		46,859			(10.8	)
Results from indexed assets and liabilities		(9,266	)		(13,630	)		4,364			(32.0	)
Net foreign currency exchange gains (losses)		128,238			(18,494	)		146,732			n.a.

Total		28,287			(213,316	)		241,603			n.a.

Other
Other gains (losses)		(6,566	)		877			(7.443	)		n.a.
Share of the profit of associates and joint ventures accounted for using the equity method		3,333			2,560			773			30.2

Total		(3,233	)		3,437			(6,670	)		n.a.

Total other results		25,054			(209,879	)		234,933			n.a.

Financial Results from Continuing Operations

Our net financial result in 2015 was a net gain of Ch$ 28.3 billion in 2015, a Ch$ 241.6 billion increase compared to 2014.

This improvement was mainly explained by a Ch$ 146.7 billion increase in non-recurring foreign currency exchange gain differences, mainly due to Ch$ 141.6 billion positive foreign exchange rate differences related to accounts receivable denominated in U.S. Dollars from the Vuelta de Obligado thermal plant (“VOSA”). This plant was financed through the contribution of outstanding debts of CAMMESA owed to our Argentine generation subsidiaries. These contributions were returned with interest according to the agreement (recorded as a financial income as explained below) and recognized in U.S. Dollars, based on the exchange rate existing as of the date on which the agreement was signed. In December 2015, a technical report confirmed that the gas plant passed all operational tests; therefore, we accounted for the effects of the dollarization of the receivables considering the current exchange rate between the Argentine peso and the U.S. Dollar.

Financial costs decreased by Ch$ 46.9 billion in 2015 as compared to 2014, mainly due to (i) Ch$ 68.7 billion lower financial costs in Ampla and Coelce as result of the revaluation of their non-amortized assets at the end of the concessions at their new replacement values, and (ii) Ch$18.2 billion lower financial costs due to the currency translation effect of converting from the various functional currencies of our foreign subsidiaries to the Chilean peso, particularly our Brazilian subsidiaries. These decreases were offset by higher financial costs in Edesur and Costanera of Ch$ 40.0 billion, mainly due to higher outstanding debt balances with CAMMESA.

In addition, financial income increased by Ch$ 43.6 billion in 2015 as compared to 2014, mainly due to (i) Ch$ 57.1 billion higher non-recurring interest accrued in accounts receivable from VOSA, (ii) Ch$ 38.6 billion higher non-recurring income due to a waiver of interest payments for the debt that Edesur and Costanera owe to CAMMESA related to the application of Resolution No. 1208/2015, (iii) Ch$ 37.6 billion higher financial income in Ampla and Coelce due to the revaluation of their non-amortized assets at the end of the concessions at their new replacement values and (iv) Ch$ 19.9 billion higher interest income in Ampla and Coelce accrued due to regulated assets and liabilities. These increases were partially offset by lower income from investments and other financial securities of Ch$ 23.1 billion and the non-recurring income recorded in 2014 of Ch$ 84.5 billion from a debt restructuring agreed between Costanera and Mitsubishi Corporation (“MC”) in October 2014.

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Income Taxes

Total income tax expenses increased by 22.9% in 2015 or Ch$ 97.7 billion as compared to 2014, mostly due to higher tax expenses as a result of higher taxable income as compared to the previous year of Ch$ 53.1 billion in El Chocón, Ch$ 21.1 billion in Coelce, Ch$ 11.9 billion in DockSud, Ch$ 8.0 billion in Edelnor and Ch$ 4.3 billion in Edesur.

The effective tax rate was 40.9% in 2015 and 36.2% in 2014, mainly as result of: (i) higher taxes due to the devaluation of the Chilean peso in terms of the U.S. dollar considering that a significant portion of the balance of our foreign investments is denominated in U.S. dollars for tax purposes, which was the currency used to pay for the acquisition of those investments. The tax currency of Enersis Américas S.A. is also the Chilean peso, as further explained below.

In 2015, the Chilean peso depreciated against the U.S. dollar, thereby increasing the tax bases of our foreign investments and increasing the current income tax expense in 2015 as compared to 2014. The tax legislation in Chile states that the tax accounts of companies owning foreign investments in a currency other than the Chilean peso are price-level restated for tax purposes according to the changes in the foreign currency exchange rate at the date of the financial statements. Variations in that regard also generate changes in the tax bases of those investments, and have income tax consequences when calculating the current income tax (currently reported as exchange gains/losses as for tax return purposes). The related tax effect is recognized as “Current tax provision/ benefit”. While the effect of the price-level restatement also impacts the tax basis of the investment, thus impacting its outside basis difference, the Company was unable to recognize the corresponding effects to deferred tax assets/ liabilities, since the conditions for such recognition under IAS 12 were not met at the balance sheet date. Therefore, this concept corresponds to a permanent difference that is reflected in the income tax statutory-to-effective rate reconciliation presented in Note 34 of our consolidated financial statements under the line item “Price level restatement for tax purposes (investments in subsidiaries, associates and joint ventures and equity)”.

The following table sets forth the tax effect of rates applied in other countries that creates a difference between the domestic tax rates in Chile and tax rates (22.5% for 2015 and 21% for 2014) enacted in each foreign jurisdiction:


	Tax Rates (%)						Tax effect of rates applied in other countries
	2015			2014			2015 ThCh$			2014 ThCh$
Argentina		35.00	%		35.00	%		(35,876,093	)		7,239,770
Brazil		34.00	%		34.00	%		(26,523,564	)		(41,357,762	)
Colombia		39.00	%		34.00	%		(89,366,919	)		(84,883,915	)
Peru		28.00	%		30.00	%		(13,049,116	)		(21,030,440	)

								(164,815,693	)		(140,032,347	)

The reconciling tax effect in Argentina increased during 2015, compared to 2014 due to higher taxable income in the subsidiaries El Chocón and Edesur, mainly as a result of an increase in taxable income obtained from new resolutions issued by the market regulator. The effective tax rate was 27.67% in 2015 and (48.9)% in 2014, mainly explained by (i) an increase in revenues in our subsidiary Edesur related to the application of Resolution No. 32/2015 which resulted in net income for financial purposes and a reduction in the tax loss carryforwards; and (ii) an increase in results from operations in our subsidiary DockSud as compared to the net loss recognized in 2014.

The reconciling tax effect in Brazil produced by the operations decreased in 2015, compared to the prior year, due to lower taxable income in our Brazilian subsidiaries as a consequence of decreased revenues due to lower local electricity demand. The effective tax rate was 31.98% in 2015 and 26.21% in 2014, as a result of a

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lower tax benefit (SUDENE) recognized in 2015 as compared to 2014 in our subsidiary Coelce. The SUDENE is a tax benefit granted to entities that obtain approval for the implementation of new projects or for expansion or diversification of existing projects, which are key for the development of the Northeast of Brazil, and corresponds to a 75% reduction in the corporate income tax expense and is calculated on profit from operations. This tax benefit produces a decrease in the effective tax rate when compared with the statutory tax rate.

With regards to Colombia, the reconciling tax effect increased slightly in 2015, as compared to 2014, due to an increase in the local enacted tax rate that occurred in 2015 to 30.00%. The effective tax rates for Colombia were 38.00% in 2015 and 31.92% in 2014, due to lower tax benefits obtained as a result of lower capital expenditures incurred by our subsidiary Emgesa in the construction of the El Quimbo power plant in 2015 as compared to 2014. This tax benefit is granted to encourage investments in revenue-producing assets, and applies 30% of the invested amount as a deduction in calculated taxable income. This tax benefit is considered a permanent difference that result in an effective tax rate lower than the statutory tax rate, since the depreciable tax basis of the asset is its gross amount.

The reconciling tax effect in Peru decreased in 2015, as compared to prior year, due to a decrease in the local enacted tax rate in 2015. The effective tax rate was 29.89% in 2015 and 13.93% in 2014. The lower effective tax rate in 2014 is related to the tax reform implemented in Peru which effected a progressive reduction in the tax rates. The effect of changes in tax rates was recognized in 2014 as a decrease in the effective tax rate for the year. Such non-recurrent tax effect did not occur in 2015.

Net Income

The following table sets forth our consolidated net income from continuing operations before income taxes, income taxes and net income from continuing operations for the periods indicated.


	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Operating income		1,254,758			1,388,000			(133,242	)		(9,6	)
Other results		25,054			(209,879	)		234,933			111.9

Income from Continuing Operations before income taxes		1,279,812			1,178,121			101,691			8.6
Income taxes		(523,663	)		(425,958	)		(97,705	)		22.9

Net Income from continuining operations		756,149			752,163			3,986			0.5
Income from discontinued operations		388,321			215,332			172,989			80.3

Net income attributable to:		1,144,470			967,495			176,975			18.3
Net income attributable to the parent company		661,587			571,873			89,714			15.7
Net income attributable to non-controlling interests		482,883			395,622			87,261			22.1

II. Analysis of Results from Discontinued Operations

Revenues from Discontinued Operations

Generation and Transmission Business

The following table sets forth the physical electricity sales of Endesa Chile and its subsidiaries and the corresponding changes for the years ended December 31, 2015 and 2014:

Years ended December 31,

2015

2014

Change

(in GWh)

(in %)

Endesa Chile and subsidiaries

23,558

21,157

2,401

11.3

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Distribution Business

The following table sets forth the physical electricity sales of Chilectra Chile and the corresponding changes for the years ended December 31, 2015 and 2014:

Years ended December 31,

2015

2014

Change

(in GWh)

(in %)

Chilectra Chile

15,893

15,690

203

1.3

The following table sets forth our revenues from discontinued operations by business for the years ended December 31, 2015 and 2014:


	Years ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business
Endesa Chile and subsidiaries		1,543,812			1,220,566			323,246			26.5

Distribution Business
Chilectra Chile and subsidiaries		1,257,732			1,127,893			129,839			11.5

Non-electricity business and combination adjustments		(404,137	)		(300,952	)		(103,185	)		34.3

Total revenues from discontinued operations		2,397,407			2,047,507			349,964			17.1

Generation and Transmission Business: Revenues

Revenues from Endesa Chile increased by Ch$ 323.2 billion, or 26.5% in 2015 compared to 2014, mainly due to (i) Ch$153.6 billion as a result of 16.0% increase in average energy sale prices, (ii) Ch$ 88.9 billion increased physical sales of 2,401 GWh, or 11.3%, due to both increased contractual sales, especially to distributors, and increased sales in the spot market, and (iii) Ch$ 69.9 billion of higher revenues contributed by GasAtacama, which has been consolidated by Endesa Chile since May 2014.

Distribution Business: Revenues

Revenues from Chilectra Chile increased by Ch$ 129.8 billion, or 11.5%, in 2015 compared to 2014. This increase is a result of (i) higher energy sales of Ch$ 115.1 billion, mainly due to Ch$ 7.1/MWh (10.7%) increase of the tariff to regulated clients due to regular indexed cost adjustment in the tariff, which accounted for Ch$ 105.4 billion of the increase and (ii) Ch$ 16.4 billion higher revenues from other services, mainly related to tolls charged to generating companies and rental and maintenance of street lighting and network installments. The number of customers rose by approximately 43,500 in 2015, compared to 2014, totaling approximately 1,780,800.

Operating Costs from Discontinued Operations

Total operating costs consist primarily of energy purchases from third parties, fuel purchases, tolls paid to transmission companies, depreciation, amortization and impairment losses, maintenance costs, employee salaries and administrative and selling expenses.

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The following table sets forth our operating costs in Chilean pesos, and as a percentage of our consolidated operating costs from discontinued operations for the years ended December 31, 2015 and 2014:


	Years ended December 31,
	2015				2014
	(in millions of Ch$)		(in %)		(in millions of Ch$)		(in %)
Energy purchases		860,203		45.9		788,421		47.3
Fuel consumption		327,503		17.5		305,480		18.3
Transportation costs		182,453		9.7		151,949		9.1
Depreciation, amortization and impairment losses⁽¹⁾		150,147		8.0		141,623		8.5
Other fixed costs⁽¹⁾		125,849		6.7		110,321		6.7
Employee benefit expense and others⁽¹⁾		115,551		6.2		104,836		6.3
Other variable procurement and services		111,826		6.0		63,553		3.8

Total operating costs from discontinued operations		1,873,532		100.0		1,666,182		100.0

(1)	Corresponds to selling and administration expenses.

The following table sets forth our operating costs (excluding selling and administrative expenses) from discontinued operations by business for the years ended December 31, 2015 and 2014.


	Years ended December 31,
	2015			2014		Change		Change
	(in millions of Ch$)							(in %)
Generation and Transmission Business
Endesa Chile and subsidiaries		880,891			750,213		130,678		17.4


Distribution Business
Chilectra Chile and subsidiaries		983,733			855,758		127,975		15.0

Non-electricity business activities and combination adjustments		(382,639	)		(296,569</

Enel Americas (ENIA) 20-F/A2015 FY Annual report (foreign) (amended)