20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

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

OR

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

For the fiscal year ended December 31, 2016

OR

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

For the transition period from              to  

OR  

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

Date of event requiring this shell company report,

Commission file number: 001-12440

ENEL AMÉRICAS S.A.

(Exact name of Registrant as specified in its charter)

ENEL AMÉRICAS S.A.

(Translation of Registrant’s name into English)

CHILE

(Jurisdiction of incorporation or organization)

Santa Rosa 76, Santiago, Chile

(Address of principal executive offices)

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

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

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

Title of Each Class	Name of Each Exchange on Which Registered
American Depositary Shares representing Common Stock	New York Stock Exchange
Common Stock, no par value *	New York Stock Exchange
US$ 600,000,000 4.00% Notes due October 25, 2026	New York Stock Exchange
US$ 858,000 6.60% Notes due December 1, 2026	New York Stock Exchange

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

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

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

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

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

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

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

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

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards † provided pursuant to Section 13(a) of the Exchange Act.  ☐ † The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012. Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP ☐	International Financial Reporting Standards as issued by the International Accounting Standards Board ☒	Other ☐

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

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

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:    58,324,975,387

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TABLE OF CONTENTS

		Page
GLOSSARY		4
INTRODUCTION		8
PRESENTATION OF INFORMATION		9
FORWARD-LOOKING STATEMENTS		11
PART I
Item 1.	Identity of Directors, Senior Management and Advisers	12
Item 2.	Offer Statistics and Expected Timetable	12
Item 3.	Key Information	12
Item 4.	Information on the Company	24
Item 4A.	Unresolved Staff Comments	93
Item 5.	Operating and Financial Review and Prospects	93
Item 6.	Directors, Senior Management and Employees	140
Item 7.	Major Shareholders and Related Party Transactions	150
Item 8.	Financial Information	152
Item 9.	The Offer and Listing	154
Item 10.	Additional Information	156
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	169
Item 12.	Description of Securities Other Than Equity Securities	173
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	174
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	174
Item 15.	Controls and Procedures	174
Item 16.	Reserved	175
Item 16A.	Audit Committee Financial Expert	175
Item 16B.	Code of Ethics	175
Item 16C.	Principal Accountant Fees and Services	176
Item 16D.	Exemptions from the Listing Standards for Audit Committees	177
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	177
Item 16F.	Change in Registrant’s Certifying Accountant	178
Item 16G.	Corporate Governance	178
Item 16H.	Mine Safety Disclosure	178
PART III
Item 17.	Financial Statements	179
Item 18.	Financial Statements	179
Item 19.	Exhibits	179

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GLOSSARY

AFP	Administradora de Fondos de Pensiones	A legal entity that manages a Chilean pension fund.
Ampla	Ampla Energia e Serviços S.A.	A publicly held Brazilian distribution company operating in Rio de Janeiro, owned by 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	Enel Green Power Cachoeira Dourada S.A.	Brazilian generation company owned by Enel Brasil, our subsidiary. Formerly known as Centrais Elétricas Cachoeira Dourada S.A.
CAMMESA	Compañía Administradora del Mercado Mayorista Eléctrico S.A.	Argentine autonomous entity in charge of the operation of the Mercado Eléctrico Mayorista (Wholesale Electricity Market), or MEM. CAMMESA’s stockholders are generation, transmission and distribution companies, large users and the Secretariat of Energy.
Chilean Stock Exchanges	Chilean Stock Exchanges	The three principal stock exchanges located in Chile: the Santiago Stock Exchange, the Electronic Stock Exchange and the Valparaíso Stock Exchange.
Chilectra Américas	Chilectra Américas S.A.	A former electricity distribution company that held minority interests in non-Chilean generation companies. Chilectra Américas was created in the context of the reorganization carried out during 2016 and then merged into Enel Américas in December 2016.
CIEN	Enel CIEN S.A.	Brazilian transmission company, wholly-owned by Enel Brasil, our subsidiary. Formerly known as Companhia de Interconexão Energética S.A.
Codensa	Codensa S.A. E.S.P.	Colombian distribution company that operates mainly in Bogotá and is 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	Enel Generación Costanera S.A.	A publicly held Argentine generation company controlled by us. Formerly known as Central Costanera S.A.
CREG	Comisión de Regulación de Energía y Gas	Colombian Commission for the Regulation of Energy and Gas.
CTM	Compañía de Transmisión del Mercosur S.A.	Argentine transmission company and subsidiary of Enel Brasil.

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DCV	Depósito Central de Valores S.A.	Chilean Central Securities Depositary.
DECSA	Distribuidora Eléctrica de Cundinamarca S.A.	Colombian distribution company that merged into Codensa in 2016.
Dock Sud	Central Dock Sud S.A.	Argentine generation company 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, which merged with Codensa in 2016.
El Chocón	Enel Generación El Chocón S.A.	Argentine generation company with two hydroelectric plants, El Chocón and Arroyito, both located in the Limay River, Argentina and our subsidiary. Formerly known as Hidroeléctrica El Chocón S.A.
Emgesa	Emgesa S.A. E.S.P.	Colombian generation company controlled by us.
Endesa Américas	Endesa Américas S.A.	A former electricity generation company that held minority interests in non-Chilean generation companies. Endesa Américas was created in the context of the reorganization carried out during 2016 and then merged into Enel Américas in December, 2016.
Enel	Enel S.p.A.	An Italian energy company with multinational operations in the power and gas markets. A 51.0% beneficial owner of us as of December 31, 2016 and our ultimate parent company.
Enel Américas	Enel Américas S.A.	Our company, a publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, headquartered in Chile, with subsidiaries engaged primarily in the generation and distribution of electricity in Argentina, Brazil, Colombia, and Peru, and controlled by Enel.  Registrant of this Report. Formerly known on an interim basis as Enersis Américas S.A. and prior to that as Enersis S.A.
Enel Brasil	Enel Brasil S.A.	Brazilian holding company and our subsidiary. Formerly known as Endesa Brasil.
Enel Chile	Enel Chile S.A.	A publicly held limited liability stock corporation incorporated under the laws of the Republic of Chile, which holds subsidiaries engaged primarily in the generation and distribution of electricity in Chile controlled by Enel. Formerly known on an interim basis as Enersis Chile.
Enel Distribución Perú	Enel Distribución Perú S.A.	A publicly held Peruvian distribution company, with a concession area in the northern part of Lima, and our subsidiary. Formerly known as Empresa de Distribución Eléctrica de Lima Norte S.A. or Edelnor.

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Enel Generación Perú	Enel Generación Perú S.A.	A publicly held Peruvian generation company and a subsidiary of Enel Américas. Formerly known as Edegel S.A.A.
Enel Generación Piura	Enel Generación Piura S.A.	A publicly held Peruvian generation company with natural gas thermal plants, and our subsidiary. Formerly known as Empresa Eléctrica de Piura S.A. or EEPSA.
Enel Iberoamérica	Enel Iberoamérica, S.R.L.	A wholly-owned subsidiary of Enel and our direct 51.0% owner as of December 31, 2016.
Enel Trading Argentina	Enel Trading Argentina S.R.L	Energy trading company with operations in Argentina, and our subsidiary. Formerly known as Central Comercializadora de Energía S.A. or CEMSA.
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 Termoelétrica Fortaleza S.A.	Brazilian generation company that operates in the state of Ceará. Fortaleza is wholly-owned by Enel Brasil, our subsidiary.
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.
MADS	Ministerio de Ambiente y Desarrollo Sostenible	Colombian Ministry of Environment and Sustainable Development.
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, solar 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 governmental 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.

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UF	Unidad de Fomento	Chilean inflation-indexed, Chilean peso-denominated monetary unit equivalent to Ch$ 26,347.98 as of December 31, 2016.
UTA	Unidad Tributaria Anual	Chilean annual tax unit. One UTA equals 12 Unidad Tributaria Mensual (“UTM”), a Chilean inflation-indexed monthly tax unit used to define fines, among other purposes. As of December 31, 2016, one UTM was equivalent to Ch$ 46,183 and one UTA to Ch$ 554,196.
VAD	Valor Agregado de Distribución	Value added from distribution of electricity.
XM	Expertos de Mercado S.A. E.S.P.	A subsidiary of Interconexión Eléctrica S.A. (“ISA”), a Colombian company that provides system management in real time services in electrical, financial and transportation sectors.

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INTRODUCTION

As used in this Report on Form 20-F (“Report”), first person personal pronouns such as “we”, “us” or “our” as well as “Enel Américas” and “the Company” refer to Enel Américas S.A. and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries, and jointly-controlled companies and associates is expressed in terms of our economic interest as of December 31, 2016.

We are a Chilean company engaged through our subsidiaries and jointly-controlled companies in the electricity generation and transmission and distribution businesses in Argentina, Brazil, Colombia and Peru. We participate in the generation and transmission businesses mainly through our subsidiaries Costanera, El Chocón and Dock Sud in Argentina, Cachoeira Dourada, Fortaleza and Cien in Brazil, Enel Generación Perú and Enel Generación Piura in Peru and Emgesa in Colombia. In the distribution business, our principal subsidiaries are Edesur in Argentina, Coelce and Ampla in Brazil, Enel Distribución Perú in Peru and Codensa in Colombia. For additional information relating to our main subsidiaries and associates, please see “Item 4. Information on the Company — C. Organizational Structure — Principal Subsidiaries and Affiliates.”

As of the date of this Report, Enel S.p.A. (“Enel”), an Italian energy company with multinational operations in the power and gas markets, owns 51.0% of us as of December 31, 2016 and is our ultimate controlling shareholder.

During 2016, we carried out a reorganization process, which involved the separation of our Chilean and non-Chilean electricity businesses, resulting in us retaining the non-Chilean electricity businesses in South America. From March 1, 2016 until November 30, 2016, we were known as Enersis Américas S.A. (“Enersis Américas”). On December 1, 2016, the Company changed its name to Enel Américas S.A. For additional information relating to the reorganization, please see “Item 4. Information on the Company — A. History and Development of the Company — The 2016 Reorganization.”

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PRESENTATION OF INFORMATION

Financial Information

In this Report, unless otherwise specified, references to “U.S. dollars,” “US$,” are to dollars of the United States of America (“United States”); references to “pesos” or “Ch$” 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; and references to “UF” are to Unidades de Fomento. The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is adjusted daily to reflect changes in the official Consumer Price Index (“CPI”) of the Chilean National Institute of Statistics (Instituto Nacional de Estadísticas or “INE”). The UF is adjusted in monthly cycles. Each day in the period beginning on the tenth day of the current month through the ninth day of the succeeding month, the nominal peso value of the UF is indexed in order to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month. As of December 31, 2016, one UF was equivalent to Ch$ 26,347.98. The U.S. dollar equivalent of one UF was US$ 39.36 as of December 31, 2016, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2016 of Ch$ 669.47 per US$ 1.00. The U.S. dollar observed exchange rate (dólar observado) (the “Observed Exchange Rate”), which is reported by the Central Bank of Chile and published daily on its webpage, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Unless the context specifies otherwise, all amounts translated from Chilean pesos to U.S. dollars or vice versa, or from UF to Chilean pesos, have been carried out at the rates applicable for December 31, 2016.

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 April 25, 2017, one UF was equivalent to Ch$ 26,543.75. The U.S. dollar equivalent of one UF was US$ 40.22 as of the same date, using the Observed Exchange Rate reported by the Central Bank of Chile as of such date of Ch$ 660.04 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, 2016, in the financial statements included in this Report, all operations regarding the former Chilean businesses have been presented as discontinued operations. Therefore, the financial statements for the year ended as of December 31, 2016 include discontinued operations for two months while the financial statements for the years ended December 31, 2015 and 2014 include discontinued operations for twelve months.

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, 2016, 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 (10¹² watts or a trillion watts); references to “GW” and “GWh” are to gigawatts (10⁹ watts or a billion watts) and gigawatt hours, respectively; references to “MW” and “MWh” are to megawatts (10⁶ watts or a million watts) and megawatt hours, respectively; references to “kW” and “kWh” are to kilowatts (10³ watts or a thousand watts) and kilowatt hours, respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. References to “BTU” and “MBTU” are to 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.

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

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

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

Calculation of Economic Interest

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

Rounding

Certain figures included in this Report have been rounded for ease of presentation.  Because of this rounding, it is possible that amounts in tables may not add up to exactly the same amounts as the sum of the entries.

10

FORWARD-LOOKING STATEMENTS

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

• our capital investment program;

• trends affecting our financial condition or results from operations;

• our dividend policy;

• the future impact of competition and regulation;

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

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

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

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

• demographic developments, political events, economic fluctuations and interventionist measures by authorities in the markets in South America where we conduct our businesses;

• hydrology, droughts, flooding and other weather conditions;

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

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

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

• the factors discussed below under “Risk Factors.”

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

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

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PART I

Item 1.Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.Offer Statistics and Expected Timetable

Not applicable.

Item 3.Key Information

A. Selected Financial Data.

The following selected consolidated financial data should be read in conjunction with our consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2016 and 2015 and for each of the years in the three-year period ended December 31, 2016 are derived from our audited consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2014 and 2013, and for the year ended December 31, 2013 are derived from our consolidated financial statements not included in this Report. Our consolidated financial statements were prepared in accordance with IFRS, as issued by the IASB. Pursuant to transitional relief granted by the SEC, selected consolidated financial data as of and for the year ended December 31, 2012 have been omitted as such information cannot be provided on a restated basis to reflect the spin-off of Enel Chile without unreasonable effort or expense.

Amounts are expressed in millions, except for ratios, operating data and data for shares and American Depositary Shares (“ADS”). 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, 2016, has been converted at the U.S. dollar Observed Exchange Rate (dólar observado) for that date of Ch$ 669.47 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:

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	As of and for the year ended December 31,
	2016 (1)			2016			2015			2014			2013
	(US$millions)			(Ch$millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income		7,763			5,197,286			5,301,440			5,206,370			4,528,148
Operating costs(2)		(5,945	)		(3,980,131	)		(4,046,681	)		(3,818,370	)		(3,177,080	)
Operating income from continuing operations		1,818			1,217,155			1,254,758			1,388,000			1,351,068
Financial results(3)		(443	)		(296,711	)		28,287			(213,316	)		(118,899	)
Other gains		12			8,209			(6,566	)		877			4,642
Share of profit (loss) of associates and joint venture accounted for using the equity method		3			1,830			3,333			2,560			980
Income from continuing operations before income tax		1,390			930,484			1,279,812			1,178,121			1,237,791
Income tax expenses, continuing operations		(537	)		(359,369	)		(523,663	)		(425,958	)		(442,455	)
Net Income from continuing operations		853			571,115			756,149			752,163			795,336
Profit after tax from discontinued operations		172			115,130			388,321			215,332			318,065
Net income		1,025			686,245			1,144,469			967,495			1,113,401
Net income attributable to the parent Company		572			383,060			661,587			571,873			658,514
Net income attributable to non-controlling interests		453			303,186			482,883			395,622			454,887
Basic and diluted earnings from continuing operations per average number of shares (Ch$/US$ per share)		0.01			6.13			8.35			8.344			9.49
Basic and diluted earnings from continuing operations per average number of ADS (Ch$/US$ per ADS)		0.46			306.50			417.50			417.20			474.50
Basic and diluted earnings from discontinued operations per average number of shares (Ch$/US$ per share)		0.00			1.57			5.13			3.31			5.08
Basic and diluted earnings from discontinued operations per average number of ADS (Ch$/US$ per ADS)		0.12			78.50			256.50			165.50			254.00
Total basic and diluted earnings per average number of shares (Ch$/US$ per share)		0.01			6.13			8.35			8.34			9.49
Total basic and diluted earnings per average number of ADSs (Ch$/US$ per ADS)		0.46			306.50			417.50			417.00			474.50
Cash dividends per share (Ch$/US$ per share)		0.01			4.64			6.21			6.71			4.25
Cash dividends per ADS (Ch$/US$ per ADS)		0.35			232.24			310.72			335.34			212.51
Weighted average number of shares of common stock (millions)					49,769			49,093			49,093			45,219
Consolidated Statement of Financial Position Data
Total assets		16,851			11,281,556			15,449,154			15,921,322			15,177,664
Non-current liabilities		5,150			3,447,517			2,753,965			4,447,282			3,688,940
Equity attributable to the parent company		6,200			4,150,469			6,026,149			6,201,976			6,168,554
Equity attributable to non-controlling interests		1,680			1,124,780			2,163,659			2,077,243			2,338,911
Total equity		7,880			5,275,249			8,189,808			8,279,219			8,507,464
Capital stock(4)		6,904			4,621,809			5,804,448			5,804,448			5,828,040
Other Consolidated Financial Data
Capital expenditures (CAPEX)(5)		1,242			831,704			1,362,561			1,089,362			774,820
Depreciation, amortization and impairment losses(6)		637			426,214			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$ 669.47 per U.S. dollar, as of December 31, 2016.

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

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

(4) Capital stock represents issued capital.

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

(6) For further detail please refer to Note 28 of the Notes to our consolidated financial statements.

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	As of and for the year ended December 31,
	2016			2015			2014			2013		2012
OPERATING DATA OF SUBSIDIARIES(1)
Edesur (Argentina)
Electricity sold (GWh)		18,493			18,492			17,972			18,110		17,710
Number of customers (thousands)		2,505			2,479			2,464			2,444		2,389
Total energy losses (%)(2)		12.0	%		1162.0	%		1080.0	%	10.8%		10.6%
Ampla (Brazil)
Electricity sold (GWh)		11,181			11,096			11,678			11,025		10,793
Number of customers (thousands)		3,054			2,997			2,876			2,801		2,712
Total energy losses (%)(2)		19.4	%		19.4	%		2030.0	%	19.8%		19.6%
Coelce (Brazil)
Electricity sold (GWh)		11,628			11,229			11,165			10,705		9,865
Number of customers (thousands)		3,890			3,757			3,625			3,500		3,338
Total energy losses (%)(2)		12.5	%		12.5	%		1280.0	%	12.5%		12.6%
Codensa (Colombia)
Electricity sold (GWh)		13,632			13,946			13,660			13,332		12,958
Number of customers (thousands)		3,248			2,865			2,772			2,687		2,588
Total energy losses (%)(2)		7.1	%		7.1	%		720.0	%	7.0%		7.3%
Enel Distribución Perú (Peru)
Electricity sold (GWh)		7,782			7,624			7,339			7,030		6,850
Number of customers (thousands)		1,367			1,337			1,293			1,255		1,203
Total energy losses (%)(2)		7.8	%		8.1	%		820.0	%	8.0%		8.2%
Enel Américas(3)
Installed capacity in Argentina (MW)(4)		4,537			4,502			4,502			4,502		3,632
Installed capacity in Colombia (MW)		3,509			3,460			3,060			2,925		2,914
Installed capacity in Peru (MW)(4)		1,977			1,984			1,949			1,842		1,657
Installed capacity in Brazil (MW)		992			987			987			987		987
Generation in Argentina (GWh)(4)		13,124			15,204			14,390			14,422		11,207
Generation in Colombia (GWh)		14,952			13,705			13,559			12,748		13,251
Generation in Peru (GWh)(4)		8,698			8,801			9,062			8,489		8,570
Generation in Brazil (GWh)		3,665			4,398			5,225			4,992		5,183

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

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

(3) Some information may be different than reported in previous periods. For further details, please refer to “Item 4. Information on the Company – D. Property, Plants and Equipment – Property, Plant and Equipment of Generating Companies.”

(4) As a result of the 2013 capital increase described under “Item 4. Information on the Company – A. History and Development of the Company – History,” we started consolidating Dock Sud in Argentina and Enel Generación Piura in Peru as of April 2013; therefore, 2013 data includes only the nine-month period from April 1, 2013 to December 31, 2013.

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.

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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, 2016, the U.S. dollar Observed Exchange Rate was Ch$ 669.47 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,
2016		645.22		730.31		676.67		669.47
2015		597.10		715.66		654.66		710.16
2014		527.53		621.41		570.34		606.75
2013		466.50		533.95		498.83		524.61
2012		469.65		519.69		486.31		479.96
Month ended
March 2017		650.98		669.52	n.a.			663.97
February 2017		638.35		648.88	n.a.			648.88
January 2017		646.19		673.36	n.a.			646.19
December 2016		649.40		677.11	n.a.			669.47
November 2016		650.72		679.24	n.a.			673.54
October 2016		651.18		670.88	n.a.			651.18

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 25, 2017, the U.S. dollar Observed Exchange Rate was Ch$ 660.04 per US$ 1.00.

Calculation of the appreciation or devaluation of the Chilean peso against the U.S. dollar in any given period is made by determining the percent change between the reciprocals of the Chilean peso equivalent of US$ 1.00 at the end of the preceding period and the end of the period for which the calculation is being made. For example, to calculate the appreciation of the year-end Chilean peso in 2016, one determines the percent change between the reciprocal of Ch$ 710.16, the value of one U.S. dollar as of December 31, 2015, or 0.001408, and the reciprocal of Ch$ 669.47, the value of one U.S. dollar as of December 31, 2016, or 0.001494. In this example, the percentage change between the two periods is 6.1%, which represents the 2016 year-end appreciation of the Chilean peso against the 2015 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.

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The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2012 through December 31, 2016, based on information published by the Central Bank of Chile.

	Ch$ per US$(1)
	PeriodEnd		Appreciation(Devaluation)
	(in Ch$)		(in %)
Year ended December 31,
2016		669.5		6.1
2015		710.2		(14.6	)
2014		606.8		(13.5	)
2013		524.6		(8.5	)
2012		480.0		8.2

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.

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

Governmental authorities have altered monetary, credit, tariff, tax and other policies to influence the course of South American economies, including Argentina, Brazil, Colombia and Peru. Furthermore, even though we do not have investments in Chile, we are a company established under the laws of the Republic of Chile. Therefore, we are subject to changes in Chilean tax, labor and monetary laws, among others. For example, in September 2014, the Chilean government approved a tax reform, which impacted our results. For further details regarding Chilean tax considerations, please refer to “Item 10. Additional Information — E. Taxation.” In addition, the Colombian and Peruvian governments implemented new tax reforms during 2016, which among other things increased income tax rates. Other governmental actions in these South American countries have also involved wage, price and tariff rate controls and other interventionist measures, such as expropriation or nationalization.

In the distribution business, if we do not meet certain minimum service and technical standards, we may lose our concessions.  As of December 31, 2016, we have five concession areas in some of the major urban centers in South America. In some of them, such as Buenos Aires in Argentina and Río de Janeiro in Brazil, given their regulation, economic and financial conditions, it may be difficult to meet certain high standards. If we are unable to meet these regulatory standards, the local electricity regulators may revoke our concessions and reassign them to our competitors.

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.

Because our businesses depend heavily on hydrology, droughts, flooding and other weather conditions may adversely affect our operations and profitability.

Approximately 53% of our consolidated installed generation capacity in 2016 was hydroelectric. Accordingly, extremely dry hydrological conditions 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 influenced rainfall and resulted in droughts, impacting our ability to dispatch energy from our hydroelectric facilities. For example, in Brazil, where 67% of our installed capacity is hydroelectric, the low hydrological contributions recorded since 2014 and the consequent higher thermal dispatch and spot prices, encouraged the authority in making regulatory changes through a modification of the upper price limits. Compared to 2013, the reservoir dam levels are still low. Also, El Niño phenomenon affected Colombian hydrologic conditions between October 2015 and April 2016, leading to a rainfall deficit and high temperatures during that period, 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

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economic effects could be more pronounced. Peru has experienced rain deficits, especially towards the end of 2016. In March 2017, “El Niño Costero” phenomenon in Peru led to unusually heavy rains, which flooded the Santa Eulalia River and resulted in the stoppage of our Callahuanca (81 MW) and Moyopampa (69 MW) hydroelectric plants. Both plants ceased operations on March 16, 2017, and as of the date of this Report, we have not fully completed our assessment of the damages. As a result of this very serious flooding, the Peruvian Ministry of Economy cut the governments’ 2017 economic growth expectations from 3.8% to 3.0%.

Thermal plant operating costs can be considerably higher than those of hydroelectric plants. Our operating expenses increase during these drought periods when thermal plants are used more frequently. 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 and Transmission Business.”

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:

• 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 that 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 water shortages. These water purchases may increase our operating costs and also require us to further negotiate with the local communities.

• Thermal power plants that burn 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 generally increases the risk of producing a higher level of pollutants.

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

The distribution business is also affected by weather conditions such as moderate temperatures that might decrease heating or air conditioning use, affecting energy consumption. Even with extreme temperatures, demand can increase significantly within a short period of time, which could affect service and result in stoppages which bring the additional risk of being subject to fines by the authorities. Depending on weather conditions, results obtained by our distribution business can vary significantly from year to year.

Governmental regulations may adversely affect our businesses.

Our businesses and the tariffs we charge to our customers are subject to extensive regulation, which may adversely affect our profitability. For example, governmental authorities in any of the countries in which we operate may impose material rationing policies during droughts or prolonged failures of power facilities, which may adversely affect our business, results of operations and financial condition.

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 was the case with Edesur, our Argentine distribution subsidiary, between 2008 and January 2017, with our Brazilian distribution subsidiaries during part of 2014, and currently with Codensa, our Colombian distribution company, whose tariff review was expected to occur by 2015, but which has not occurred as of the date of this Report. 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, El Quimbo’s original commencement date of October 7, 2015 was affected and commercial operations could not begin until November 16, 2015. On December 15, 2015, the Colombian Constitutional Court declared Decree 1979/2015 unconstitutional due to the injunction issued by the Administrative Tribunal of Huila still being in effect. As a

17

result, Emgesa suspended operations at El Quimbo on December 16, 2015. On January 10, 2016, El Quimbo resumed its operations following a favorable court decision.

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

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

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

Our electricity generation subsidiaries are supervised by their local regulatory entities and may be subject to 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 failures are not within their control.

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 the credit agreements of our subsidiary Enel Generación Piura 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 Brasil as a consequence of the economic and political situation that Brazil and especially the distribution sector, is dealing with.

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

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

We are involved in litigation proceedings.

We are currently involved in various litigation proceedings, which could result in unfavorable decisions or financial penalties against us. We will continue to be subject to future litigation proceedings, which could cause material adverse consequences to our business.

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 33.3 of the Notes to our consolidated financial statements.

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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 be withheld by governmental authorities and therefore its processing time may be longer than expected.  

The approval of these environmental impact studies may be withheld by governmental authorities and therefore their processing time may be longer than anticipated.  The projects that require consultation with local stakeholders in their evaluation process may be rejected or their development may be impeded or slowed down. Our stakeholders may also seek injunctive or other relief, which could negatively impact us if they are successful. Moreover, projects that do not require consultation with local stakeholders may be subject to intervention or suffer continuous resistance, delaying their approval process or development.

In addition to environmental considerations, considerations, 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, construction delays, strikes, adverse weather conditions, natural disasters, civil unrest, accidents, or other unforeseen events. For example, many of our power plants have been delayed by years in relation to their original planning and design. 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 impact us negatively, our business, results of operations and financial condition could be adversely affected.

Most of the countries have adopted rules of consultation with local stakeholders in the preliminary phase of the evaluation process to avoid any risk of conflict and minimize the plant impacts. Plants built before the adoption of these rules that were not submitted to local consultation may face opposition from several stakeholders, such as ethnic groups, environmental groups, land owners, farmers, local communities and political parties, among others. The management of these conflicts may result in plant stoppages without generation and in legal costs. For example, El Quimbo hydroelectric project in Colombia faced constant demands from the public during its construction period, 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 (SO₂) and nitrogen oxide (NO), 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 be abandoned, causing our share prices to drop and hindering our ability to attract and retain valuable employees, any of which could result in an impairment of our goodwill with stakeholders.

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

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

Financial and political events in other parts of the world could also adversely affect our business. For example, the 2016 presidential election in the United States considerably increased the volatility of financial markets worldwide based on the uncertainty of political decisions. New United States policies could affect world markets and global trade and result in renewed volatility, especially in commodity prices.  Moreover, instability in the Middle East or in any other major oil producing region could result in

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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 that we have benefited from to date.

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

South American economic fluctuations 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 Brazil. Brazil has experienced political instability due to corruption scandals, occurring in 2015 and thereafter, involving several government officials, including the President of Brazil, who was impeached and finally forced to end her mandate in 2016. This has led to a deterioration of the Brazilian economy, which recorded a second consecutive year of recession with a GDP reduction of 3.6%. In 2016, 36% of our operating revenues and 22% of our operating income came from Brazil.

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 as shareholders, including extraordinary capital increases. For further details regarding financial support provided to our Brazilian subsidiaries, please refer to “Item 7. Major Shareholders and Related Party Transactions — B. Related Party Transactions.”

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, which could adversely affect the value of our securities.

We may be unable to enter into suitable 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.

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

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 Brazil by the Water National Authority (“ANA” in its Portuguese acronym), in Colombia by the Ministry of Environment, Housing and Territorial Development (“MAVDT” in its Spanish acronym), and in Peru by the Water National Authority (“ANA” in its Spanish 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, water for human consumption is the first priority before any other use. In Peru, the concessions are granted for indefinite periods and could be revoked 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.

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

Even though the functional currency of our financial statements was in Chilean pesos until December 31, 2016 and is now the U.S. dollar as of January 1, 2017, our subsidiaries generate revenues in Argentine pesos, Nuevos Soles, Brazilian reais and Colombian pesos.

We generally have been and will continue to be materially exposed to currency fluctuations of our local currencies against the U.S. dollar because of time lags and other limitations to peg our tariffs to the U.S. dollar. For information on changes to our functional currency, 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 — e. Critical Accounting Policies.”

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.

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

We have economic exposure to fluctuations in the market prices of certain commodities as a result of the long-term energy sales contracts into which we have entered.  Indeed, 14.6% of our expected annual generation is sold under contracts with at least ten year terms and 18.8% is sold under contracts with at least five year terms. 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 influence over us and may have a different strategic view for our development than that of our minority shareholders.

Enel beneficially owns 51.0% of our share capital as of December 31, 2016. Enel, our ultimate controlling shareholder, has the power to determine the outcome of substantially all material matters that require shareholders’ votes, in accordance with Chilean corporate law, such as the election of the majority of our board members and, subject to contractual and legal restrictions, adoption of our dividend policy. Enel also exercises significant influence over our business strategy and operations. Its interests may in some cases differ from those of our minority shareholders. For example, Enel conducts its business operations in the field of renewable energy in non‑Chilean South American countries through Enel Green Power S.p.A. in which we have no equity interest. Certain conflicts of interest affecting Enel in these matters may be resolved in a manner that is different from interests of our company or our minority shareholders.

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

Our primary facilities include power plants, transmission and distribution assets. Our facilities may be damaged by earthquakes, flooding, fires, and other catastrophic disasters arising from natural or accidental human causes, as well as acts of vandalism, riot, and terrorism. A catastrophic event could cause 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 Enel Generación Perú’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.

In March 2017, “El Niño Costero” phenomenon in Peru led to unusually heavy rains, which flooded the Santa Eulalia River and resulted in the stoppage of our Callahuanca (81 MW) and Moyopampa (69 MW) hydroelectric plants. Both plants ceased operations on March 16, 2017, and as of the date of this Report, we have not fully completed our assessment of the damages.  As a result of this very serious flooding, the Peruvian Ministry of Economy cut the governments’ 2017 economic growth expectations from 3.8% to 3.0%.

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

As of December 31, 2016, our consolidated interest-bearing debt totaled Ch$ 2,884 billion.

Our consolidated interest-bearing debt had the following maturity profile:

• Ch$ 498 billion in 2017;

• Ch$ 825 billion from 2018 to 2019;

• Ch$ 508 billion from 2020 to 2021; and

• Ch$ 1,053 billion thereafter.

Set forth below is a breakdown by country for debt maturing in 2017:

• Ch$ 204 billion for Colombia;

• Ch$ 204 billion for Brazil;

• Ch$ 80 billion for Peru;

• Ch$ 3 billion for Argentina; and

• Ch$ 7 billion for Chile.

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

In the event that we or any of our significant subsidiaries breach any of these material contractual provisions, our debtholders may demand immediate repayment, and a significant portion of our indebtedness could become due and payable. For example, Ampla has been facing 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 a deterioration of cash flows and EBITDA, as other distribution companies in the Brazilian market. This required Ampla to renegotiate some of its financial covenants between December 2015 and January 2016, in order to avoid a breach of contract. There is an additional risk of covenant noncompliance if the economic environment in Brazil continues to worsen. In March 2016, as a consequence of Ampla’s deteriorated creditworthiness, we guaranteed Ampla’s US$ 75 million three-year bank term loan. Later, in July 2016, we also granted intercompany loans to Enel Brasil to provide them with financial stability. For further details, please refer to “Item 7. Major Shareholders and Related Party Transactions — B. Related Party Transactions.”

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 the country in which we operate with the highest refinancing risk. As of December 31, 2016, third-party debt of our Brazilian subsidiaries amounted to Ch$ 640 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 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 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

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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.

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.

The relative illiquidity and volatility of the Chilean securities market and its dependence on economic conditions in Latin America and other parts of the world 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 or other developed countries. The low liquidity of the Chilean market may impair the ability of shareholders to sell shares, or holders of ADSs to sell shares of our common stock withdrawn from the ADS program, into the Chilean market in the amount and at the price and time they wish to do so. Also, the liquidity and the market for our shares or ADSs may be affected by a number of factors including variations in exchange and interest rates, the deterioration and volatility of the markets for similar securities and any changes in our liquidity, financial condition, creditworthiness, results and profitability.

In addition, Chilean securities markets may be affected to varying degrees by economic and market conditions and developments in Latin American countries, other emerging markets and elsewhere in the world. Although economic conditions in such countries may differ significantly from economic conditions in Chile, investors’ reactions to developments in any of these other countries may have an adverse effect on the market value and the liquidity of securities for Chilean issuers. An increase in the perceived risks associated with investing in South American countries and elsewhere in the world could lessen capital flows to Chile and adversely affect the Chilean economy in general, and the interests of investors in our shares or ADSs in particular.

We cannot give assurance that the price or the liquidity of our shares or ADSs will not be negatively affected by events in Latin American markets or the global economy in general.

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 investments 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.

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.

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IT Systems are 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 our image and our relationship with the community. In the last few years, global cyber-attacks on security systems, treasury operations, and IT Systems have intensified worldwide. We are exposed to cyber- 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. We are exposed to several types of cyber-attacks, including denial-of-service attacks that may affect the accessibility of our services to our users and attacks that may affect our domain name systems, preventing the use of certain useful web pages and applications.

We have suffered cyber-attacks in the past.  Further cyber-attacks may occur and may affect us adversely in the future.

Item 4.Information on the Company

A. History and Development of the Company.

History

We are a publicly held limited liability stock corporation headquartered in Chile and organized on June 19, 1981 under the laws of the Republic of Chile. Since January 1983, we have been registered in Santiago with the SVS under Registration No. 0175. We also have been registered with the SEC under the commission file number 001-12440 since October 19, 1993. We are legally referred to by our full name Enel Américas S.A. as well as by the abbreviated name “Enel Américas.”

Our shares are listed and traded on the Chilean Stock Exchanges and our ADSs are listed and traded on the NYSE.

Our contact information in Chile is:

Contact Person: Nicolás Billikopf

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

Telephone: (56-2) 2353-4628

Web site: www.enelamericas.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. As of December 31, 2016, we had 11,014 MW of installed capacity and 14.1 million distribution customers. Our installed capacity is comprised of 105 generation units in the four countries in which we operate, of which 53% are hydroelectric power plants. As of December 31, 2016, we had consolidated assets of Ch$ 11,282, billion and operating revenues of Ch$ 5,197 billion.

Since June 2009, our controlling shareholder has been the Italian company Enel, which currently holds a beneficial ownership of 51.0% of our shares as of December 31, 2016. Enel is an energy company with multinational operations in the power and gas markets, with a focus on Europe and Latin America. Enel operates in over 30 countries across four continents, produces energy through a net installed capacity of 84 GW and distributes electricity and gas through a network covering 1.9 million kilometers. With over 61 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enel publicly trades on the Milan Stock Exchange.

We are one of the largest publicly listed companies in the electricity sector in South America. We trace our origins to Compañía Chilena de Electricidad Ltda. (“CCE”), which was formed in 1921 as a result of the merger of Chilean Electric Tramway and Light Co., founded in 1889, and Compañía Nacional de Fuerza Eléctrica (“CONAFE”), with operations dating back to 1919. In 1970, the Chilean government nationalized CCE. During the 1980s, the sector was reorganized through the Chilean Electricity Law, known as the Decree with Force of Law Number 1 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. changed its name to Enersis S.A. (“Enersis”), and became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A. (“Chilectra” and currently known as Enel Distribución Chile S.A.). In the 1990s, we diversified into non‑Chilean electricity generation, transmission and distribution. Subsequent to the 2016 Reorganization (see below), we no longer hold Chilean electricity assets, but only electricity generation, transmission and distribution assets in four other non‑Chilean countries in South

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America. We began our international operations in 1992 with our investment in Edesur, an Argentine electricity distribution company. That same year, we expanded our international operations with an 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.  In 2005, Enel Brasil was formed to manage all the generation, transmission and distribution assets held in Brazil; namely, Ampla, Fortaleza, CIEN, Cachoeira Dourada and Coelce. As of December 31, 2016, we had a 99.3% beneficial interest in Enel Brasil, which increased from 84.4% as a consequence of the “2016 Reorganization.”

In 2006, in order to achieve synergies in Peru, we merged Edegel (currently known as Enel Generación Perú) 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, our Colombian generation subsidiary. As of December 31, 2016, we held a 48.5% beneficial interest in Emgesa. Pursuant to a shareholders’ agreement, we control Emgesa and therefore consolidate it. For more information regarding the control and consolidation of Emgesa, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

In October 2009, Enel Generación Chile purchased an additional 29.4% of Enel Generación Perú, formerly known as Edegel from Generalima, a Peruvian subsidiary of Endesa Spain. With this transaction, Enel Generación Chile increased its economic interest in Enel Generación Perú from 33.1% to 62.5%. As of December 31, 2016, our beneficial interest in Enel Generación Perú was 83.6%. In October 2009, we also acquired an additional 24% of our Peruvian subsidiary, Enel Distribución Perú, formerly known as Edelnor, increasing our beneficial ownership stake. As of December 31, 2016, we had a 75.7% economic interest in Enel Distribución Perú.

In June 2012, Endesa Spain, our parent company at the time, proposed a capital increase in our Company through in-kind contributions from all of its equity interests in 25 companies in the five South American countries in which we operate. The rest of the shareholders had 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 (US$ 6 billion at that time) capital increase consisted of Ch$ 1,714 billion (US$ 3.6 billion at that time) of in-kind contributions from Endesa Spain and Ch$ 1,132 billion (US$ 2.4 billion at that time) in cash from minority shareholders (the “2013 capital increase”). We began consolidating Enel Generación Piura, formerly known as Piura, Enel Trading Argentina, formerly known as 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, directly or indirectly through our subsidiaries, including the following transactions:

• On January 14, 2014, we submitted a voluntary public offer for the acquisition of shares from the shareholders of our subsidiary Coelce.  The investment amounted to Ch$ 133 billion. As a consequence of this transaction which closed in May 2014, we hold a 64.9% economic interest in Coelce. Following the 2016 Reorganization process and as of December 31, 2016, we hold a 73.7% economic interest in Coelce.

• 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 Enel Generación Perú. The total investment amounted to Ch$ 243 billion (equivalent to US$ 413 million at that time). As result of this transaction, which closed in September 2014, we increased our economic interest in Enel Generación Perú to 58.6%, and after the 2016 Reorganization process, to 83.6%.

• On November 30, 2016, our subsidiary Enel Brasil presented the best offer for the acquisition of 94.8% shares of Celg Distribuição S.A. (“CELG”) in a tender process organized by the Brazilian Government through Banco Nacional do Desenvolvimento (“BNDES”). CELG is a Brazilian distribution company located in the state of Goias. The financial offer amounted to R$ 2,187 million (equivalent to US$ 640 million at that time). The acquisition took place on February 14, 2017, after the approval of the antitrust authority, Conselho Administrativo de Defesa Econômica (“CADE”), and the sectorial regulator, Agência Nacional de Energia Elétrica (“ANEEL”).

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 40.3% of our shares) to Enel Iberoamérica, a subsidiary of Enel. In December 2016, Enel Iberoamérica absorbed Enel Latinoamérica through a merger; as a result, Enel continues to be our ultimate controlling shareholder.

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The 2016 Reorganization

During 2016, our shareholders carried out a reorganization process to separate the Chilean businesses from the non-Chilean businesses (the “2016 Reorganization”).

The first phase of the 2016 Reorganization involved the separation of the respective Chilean and non-Chilean electricity generation, transmission and distribution businesses of Empresa Nacional de Electricidad S.A. (“Endesa Chile”), Chilectra and Enersis by means of a “demerger” under Chilean law and the subsequent distribution of the shares of the newly created entities to each company’s respective shareholders (collectively, the “Spin-Offs”). Following the approvals of the Spin-Offs by the shareholders of Enersis, Endesa Chile and Chilectra at their extraordinary shareholders’ meetings held on December 18, 2015, the “demerger” or separation of the  businesses occurred on March 1, 2016 and the Spin-Offs were completed in April 2016, with the creation and public listing of the shares of the newly incorporated entities: Enersis Chile S.A. (“Enersis Chile”), Endesa Américas S.A. (“Endesa Américas”) and Chilectra Américas S.A. (“Chilectra Américas”). As a result of the Spin-Offs: (i) Endesa Chile spun-off Endesa Américas, which held the non-Chilean businesses of Endesa Chile, (ii) Chilectra spun-off Chilectra Américas, which held the non-Chilean businesses of Chilectra and (iii) Enersis spun-off Enersis Chile, now Enel Chile S.A., which holds the Chilean businesses of Enersis.

The second phase of the 2016 Reorganization involved the merger between the companies holding the non‑Chilean assets. On September 28, 2016, the respective shareholders of Enersis Américas, Endesa Américas and Chilectra Américas approved the merger of Endesa Américas and Chilectra Américas with and into Enersis Américas, with Enersis Américas continuing as the surviving company. The merger combined the non-Chilean generation, transmission and distribution businesses under a single holding company, with the aim of contributing to the simplification of the corporate structure of the group and providing benefits such as subsidiary cash leakage reduction, strategic interest alignment and increased decision-making and operational efficiencies. The merger became effective on December 1, 2016. As a consequence of the merger, we issued 9,232,202,625 new shares, of which 872,333,871 shares were deemed reacquired and held as treasury stock, which will be cancelled as a result of the approval of the cancellation by the shareholders at the ESM on April 27, 2017. As a result, our ultimate controlling shareholder, Enel, currently owns 51.0% of our outstanding shares (including treasury stock) and will own 51.8% of our outstanding stock after the cancellation.

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

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 the distribution business, related to network reliability, capacity improvement and new technology developments such as smart meters.

For the 2017-2019 period, we expect to make capital expenditures of Ch$ 2,755 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, Plants and Equipment — Projects Under Development.”

The table below sets forth the expected capital expenditures for the 2017-2019 period and the capital expenditures incurred in 2016, 2015 and 2014:

	Estimated 2017-2019		2016		2015		2014
	(in millions of Ch$)
Capital expenditures(1)		2,754,744		831,704		1,362,561		1,089,362

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

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In the past, we reported a five‑year estimate of future capital expenses. However, while our planned investments go beyond the three years highlighted in this table, we are now reporting three years to be aligned with Enel’s three-year industrial plan that was disclosed in November 2016. For further information, please refer to “Item 4. Information on the Company — D. Property, Plants and Equipment. — Project Investments” and “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations.”

Capital Expenditures 2016, 2015 and 2014

In the generation 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. During 2016, we invested Ch$ 30 billion in a new 51 MW unit “TG-6” for the Malacas thermal power plant, owned by Enel Generación Piura in Peru, to substitute for the Mitsubishi non-operating units (TG1, TG2 and TG3) and to increase generation using available LNG. We expect the unit will begin operating in 2017.

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 headquartered in Chile, but with consolidated operations only in Argentina, Brazil, Colombia, and Peru. Our core businesses are electricity generation and transmission and electricity distribution.

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

	Year ended December 31,
	2016			2015			2014			Change2016 vs. 2015
	(in millions of Ch$)									(in %)
Generation and Transmission Business in Argentina		207,605			212,136			167,630			(2.1	)
Enel Generación Costanera		92,633			100,857			75,194			(8.2	)
Enel Generación El Chocón		28,241			40,005			30,174			(29.4	)
Dock Sud		86,363			69,963			61,606			23.4
Other		368			1,311			656			(71.9	)
Generation and Transmission Business in Brazil		387,094			305,830			437,883			26.6
EGP Cachoeira Dourada		192,912			91,563			158,965			110.7
Fortaleza		159,477			159,052			210,793			0.3
Enel CIEN (1)		52,179			55,534			67,700			(6.0	)
Other (1)		(17,474	)		(319	)		425		n.a.
Generation and Transmission Business in Colombia		778,880			778,768			753,385			0.0
Emgesa (1)		778,880			778,768			753,385			0.0
Generation and Transmission Business in Peru		458,974			437,887			401,705			4.8
Enel Generación Perú (1)		396,805			382,877			354,003			3.6
Enel Generación Piura		65,145			58,093			50,849			12.1
Other (1)		(2,976	)		(3,083	)		(3,147	)		(3.5	)
Other Generation and Transmission Business reportable segment		—			141			3,126			(1.0	)
Total Generation and Transmission Business reportable segment		1,832,554			1,734,762			1,763,729			5.6
Distribution Business in Argentina		664,100			607,345			371,412			9.3
Edesur		664,100			607,345			371,412			9.3
Distribution Business in Brazil		1,684,139			1,836,864			1,969,226			(8.3	)
Ampla		879,499			1,026,680			1,092,282			(14.3	)
Coelce		804,640			810,184			876,944			(0.7	)
Distribution Business in Colombia		923,912			884,467			982,771			4.5
Codensa		923,912			884,467			982,771			4.5
Distribution Business in Peru		585,196			562,046			478,700			4.1
Enel Distribución Perú		585,196			562,046			478,700			4.1
Total Distribution Business reportable segment		3,857,347			3,890,722			3,802,109			(0.9	)
Less: Consolidation adjustments and non-core activities		(492,615	)		(324,045	)		(358,608	)		52.0
Total Revenues		5,197,286			5,301,439			5,207,230			(2.0	)

(1) Figures differ from those previously reported due to reclassifications within the country.

For further information related to our revenues and total income see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 32.2 of the Notes to our consolidated financial statements.

Electricity Generation Business

As of December 31, 2016, electricity generation represented 32% of our operating revenues and 55% of our operating income before consolidation adjustments.

In 2016, our consolidated electricity sales were 50,575 GWh and our production was 40,439 GWh, a 4.3% increase and a 4.0% decrease respectively, compared to 2015. Our total installed capacity in 2016 was 11,014 MW, an 81 MW increase compared to 2015.

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

	Year ended December 31,
	2016		2015		2014
Argentina
Number of generating units(1)		29		25		25
Installed capacity (MW)(2)		4,537		4,502		4,502
Electricity generation (GWh)		13,124		15,204		14,390
Energy sales (GWh)		13,312		15,770		15,276
Brazil
Number of generating units(1)		13		13		13
Installed capacity (MW)(2)		992		987		987
Electricity generation (GWh)		3,665		4,398		5,225
Energy sales (GWh)		9,448		6,541		7,108
Colombia
Number of generating units(1)(3)		36		36		32
Installed capacity (MW)(2)(3)		3,509		3,460		3,060
Electricity generation (GWh)		14,952		13,705		13,559
Energy sales (GWh)		18,015		16,886		15,773
Peru
Number of generating units(1)		27		27		27
Installed capacity (MW)(2)(4)		1,977		1,984		1,949
Electricity generation (GWh)		8,698		8,801		9,062
Energy sales (GWh)		9,800		9,283		9,916
Total
Number of generating units(1)		105		101		97
Installed capacity (MW)(2)		11,014		10,933		10,498
Electricity generation (GWh)		40,439		42,109		42,237
Energy sales (GWh)		50,575		48,480		48,073

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

(2) 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 Argentina, four diesel engines entered into commercial operations in July 2016.

(4) In Colombia, El Quimbo entered into commercial operations in November 2015, adding 400 MW of capacity and in December 2016, El Guavio increased its capacity by 50 MW after some capacity tests.

In the electricity industry, it is common to divide the business into hydroelectric and thermoelectric generation because each type of generation has significantly different variable costs. Thermoelectric generation requires the purchase of fuel, which generally leads to higher variable costs than the hydroelectric generation from reservoirs or rivers that generally has minimal variable costs. Of our total consolidated generation in 2016, 55.8% was from hydroelectric sources, and 44.2% was from thermal sources. 

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

CONSOLIDATED GENERATION BY TYPE OF ENERGY (GWh)

	Year ended December 31,
	2016				2015				2014
	Generation		%		Generation		%		Generation		%
Hydroelectric		22,550		55.8		22,171		52.7		22,439		53.1
Thermal		17,889		44.2		19,938		47.3		19,798		46.9
Total generation		40,439		100		42,109		100		42,237		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.

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.

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,
	2016				2015				2014
	Sales		%		Sales		%		Sales		%
Regulated customers		18,702		37.0		17,937		37.0		17,125		35.6
Unregulated customers		13,619		26.9		9,605		19.8		10,503		21.8
Total contracted sales(1)		32,321		63.9		27,543		56.8		27,627		57.4
Electricity pool market sales		18,254		36.1		20,938		43.2		20,446		42.5
Total electricity sales		50,575		100		48,481		100		48,073		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

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year, we take into consideration the available statistical information concerning rainfall, hydrological levels, and the capacity of key reservoirs. In addition to limiting contracted sales, we may adopt other strategies including installing temporary thermal capacity, negotiating lower consumption levels with unregulated customers, negotiating with other water users and including pass-through cost clauses in contracts with customers. (For further details about hydrological conditions and their effects on our business, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company — a. Generation and Transmission Business.” 

Seasonality

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

The generation 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. In Brazil due to its tropical weather, rainfall is mostly concentrated in summer from November through May, and it is lightest during the winter. The months with the most precipitation in our operating area in Colombia are typically April and May as well as October and November. The months with the most precipitation in Peru are typically November through March.

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

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

Operations in Argentina

We participate in electricity generation in Argentina through our subsidiaries Costanera, El Chocón and Dock Sud, with an aggregate of 29 power units with a total installed capacity of 4,537 MW. Costanera owns eleven thermal units, with a total installed capacity of 2,304 MW, El Chocón owns nine hydroelectric units and four diesel engines, with a total installed capacity of 1,364 MW, and Dock Sud owns five thermal units with a total installed capacity of 870 MW. Our hydro and thermal generation units in Argentina represented 14.4% of the Argentine National Interconnected System’s (“Argentine NIS”) installed capacity in 2016.

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. By December 2016, the total aggregate capacity of these units was 2,273 MW (868 MW from Manuel Belgrano, 865 MW from San Martín and 540 MW from Vuelta de Obligado).

As of December 31, 2016, Costanera’s installed capacity accounted for 6.8% 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 4.0% of the installed capacity in the Argentine NIS as of December 31, 2016. El Chocón has a 30-year non-renewable 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 — Argentine Electricity Regulatory Framework”). Also, Costanera has an agreement with El Chocón to operate four diesel engines belonging to El Chocón with a total installed capacity of 36 MW, which are located in our Costanera thermal plant and began operating during 2016.

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Dock Sud’s installed capacity of 870 MW accounted for 2.6% of the total installed capacity in the Argentine NIS as of December 31, 2016. 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, Plants and Equipment—Property, Plant and Equipment of Generating Companies.”

Our total generation in Argentina amounted to 13,124 GWh in 2016. According to CAMMESA, our generation market share was approximately 9.6 % of the total electricity production in Argentina during 2016.

Our hydroelectric generation in Argentina accounted for nearly 17.2% of our total generation in 2016, reaching 2,256 GWh, a decrease of 30.3% compared to the previous year. This was mainly due to lower hydrological levels in the Limay River in 2016 compared to 2015 average levels as a result of less precipitation during the winter months. Our thermal generation in Argentina accounted for 82.8% of our total generation in 2016, reaching 10,868 GWh, a decrease of 9.2% compared to the previous year. This was mainly due to unscheduled maintenance of the Costanera power plant.

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

ELECTRICITY GENERATION IN ARGENTINA (GWh)

	Year ended December 31,
	2016				2015				2014
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (El Chocón)		2,256		17.2		3,238		21.3		2,632		18.3
Thermal generation (Costanera y Dock Sud)(1)		10,868		82.8		11,966		78.7		11,758		81.7
Total generation		13,124		100		15,204		100		14,390		100

(1) Includes diesel engines from El Chocón

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

ELECTRICITY GENERATION AND PURCHASES IN ARGENTINA (GWh)

	Year ended December 31,
	2016				2015				2014
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		13,124		98.6		15,204		96.4		14,390		94.2
Electricity purchases		188		1.4		566		3.6		886		5.8
Total(1)		13,312		100		15,770		100		15,276		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:

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ELECTRICITY SALES PER CUSTOMER SEGMENT IN ARGENTINA (GWh)

	Year ended December 31,
	2016				2015				2014
	Sales		% of Sales Volume		Sales		% of Sales Volume		Sales		% of Sales Volume
Contracted sales		350		2.6		588		3.7		904		5.9
Non-contracted sales(1)		12,962		97.4		15,182		96.3		14,372		94.1
Total electricity sales		13,312		100		15,770		100		15,276		100

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

ELECTRICITY SALES PER SUBSIDIARY IN ARGENTINA (GWh)

	Year ended December 31,
	2016		2015		2014
Costanera		5,713		8,168		7,051
El Chocón		2,574		3,801		3,391
Dock Sud		5,025		3,802		4,834
Total		13,312		15,770		15,276

As of December 31, 2016, 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, 2016, El Chocón had 24 contracts with unregulated customers and no contracts with distribution companies. 

For the year ended December 31, 2016, 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 0.6% during 2016. The total electricity demand was 132,949 GWh in 2016, 131,998 GWh in 2015 and 126,397 GWh in 2014. 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 2016, our major competitors in Argentina are: (1) the state controlled company Enarsa (with an installed capacity of 1,720 MW), (2) the nuclear unit “NASA” (with an installed capacity of 1,107 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 six power plants connected to the Argentine NIS with a total installed capacity of 2,858 MW (50.6% 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 2,268 MW, competes with us with six power plants, of which 612 MW is hydroelectric and 1,656 MW is thermal.

Operations in Brazil

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

As of December 2016, we had a total installed capacity of 992 MW in Brazil, representing 0.6% of the total installed capacity of the Brazilian system.

Cachoeira Dourada is a hydroelectric company consisting of ten generation units with a total installed capacity of 665 MW, located in southern Brazil.

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.

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

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During 2016, our thermal generation decreased compared to prior years due to both scheduled and unscheduled maintenance. Our hydroelectric generation was slightly higher than 2015 as a result of favorable hydrological conditions in 2016.

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

ELECTRICITY GENERATION IN BRAZIL (GWh)

	Year ended December 31,
	2016				2015				2014
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (Cachoeira Dourada)		2,093		57.1		2,057		46.8		2,741		52.5
Thermal generation (Fortaleza)		1,572		42.9		2,342		53.2		2,484		47.5
Total		3,665		100		4,398		100		5,225		100

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

ELECTRICITY GENERATION AND PURCHASES IN BRAZIL (GWh)

	Year ended December 31,
	2016				2015				2014
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		3,665		38.8		4,398		67.2		5,225		73.5
Electricity purchases		5,784		61.2		2,142		32.8		1,883		26.5
Total(1)		9,448		100		6,540		100		7,108		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 2016, Cachoeira had energy sale contracts with 22 distribution companies for a total of 705 GWh and 56 unregulated customers for a total of 5,557 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,
	2016				2015				2014
	Sales		% of Sales Volume		Sales		% of Sales Volume		Sales		% of Sales Volume
Contracted sales		6,262		97.9		2,754		85.7		3,634		93.1
Non-contracted sales		137		2.1		461		14.3		269		6.9
Total electricity sales(1)		6,399		100		3,215		100		3,903		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, 2016, Cachoeira Dourada’s principal unregulated customers were (ordered by energy contracted): Ferbasa, Volkswagen and General Motors.

Fortaleza has its entire output dedicated to one 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:

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FORTALEZA’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

	Year ended December 31,
	2016				2015				2014
	Sales		%ofSales Volume		Sales		%ofSales Volume		Sales		%ofSales Volume
Contracted sales		2,998		98.3		3,128		94.0		2,903		90.6
Non-contracted sales		51		1.7		198		6.0		302		9.4
Total electricity sales		3,049		100		3,326		100		3,205		100

Operations in Colombia

We participate in electricity generation in Colombia through our subsidiary Emgesa. As of December 31, 2016, Emgesa operated 36 generation units, with a total installed capacity of 3,509 MW, of which 3,065 MW was from hydroelectric plants and 444 MW was from thermoelectric plants. According to Expertos de Mercado S.A. E.S.P. (“XM”), a Colombian company that provides system management in real time services in electrical, financial and transportation sectors, our hydroelectric and thermal generation plants represented 21.1% of the country’s total electricity generation capacity as of December 2016. For information on the installed generation capacity for each of our Colombian subsidiaries, see “Item 4. Information on the Company — D. Property, Plants and Equipment—Property, Plant and Equipment of Generating Companies.” 

Approximately 87% 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 22.8% in 2016. 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 2016, our hydroelectric generation represented 93.8% of our total generation and thermal generation represented the remaining 6.2%. The higher hydroelectric generation in 2016 is mainly due to El Quimbo’s generation, which began operating in November 2015. In 2016, hydrological conditions were more favorable compared to 2015, although both years were below the historical averages in Colombia. 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 9% higher, the Magdalena River (Betania) was 6.2% lower and the Bogotá River (Cadena Nueva) was 9.3% higher. For the year ended December 31, 2016, our hydroelectric generation increased by 14.8% compared to 2015.

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

ELECTRICITY GENERATION IN COLOMBIA (GWh)

	Year ended December 31,
	2016				2015				2014
	Generation		%		Generation		%		Generation		%
Hydroelectric generation		14,031		93.8		12,223		89.2		12,627		93.1
Thermal generation		920		6.2		1,482		10.8		932		6.9
Total generation		14,952		100		13,705		100		13,559		100

During 2016, Emgesa used 286 kilotons of coal for its coal-fired plant, Termozipa, which was obtained from 22 local suppliers compared to the 554 kilotons used during 2015. This lower consumption can be explained by lower thermal generation as result of better hydrological conditions in 2016 compared to 2015, when El Niño climate phenomenon led to drier hydrology in Colombia.

During 2016, Emgesa held a new tender for the supply of domestic coal to support the Reliability Payment associated with the Termozipa power plant for the 2017-2019 period, which was awarded to 24 local suppliers. The local coal price has remained below the export price as high transport costs make it difficult for domestic coal to compete in the export market. This trend is expected to continue in the Colombian coal market.

In 2016, Emgesa held a tender for the supply of fuel oil to support the Reliability Payment associated with the Cartagena power plant for the 2017-2019 period. The contract was awarded to Petromil, a significant player in the local fuel oil supply market. In 2016, the Cartagena power plant consumed 116 kilotons of fuel oil, primarily supplied from Petromil with domestic product and 8.6 kilotons imported from other suppliers.

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

ELECTRICITY GENERATION AND PURCHASES IN COLOMBIA (GWh)

	Year ended December 31,
	2016				2015				2014
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		14,952		82.2		13,705		80.2		13,559		85.3
Electricity purchases		3,244		17.8		3,384		19.8		2,333		14.7
Total(1)		18,196		100		17,089		100		15,892		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 remained virtually unchanged during 2016, increasing 0.2%. Total electricity consumption was 66,317 GWh in 2016, 66,173 GWh in 2015 and 63,570 GWh in 2014. 

Colombia has an agreement with Ecuador to provide an interconnection between the electricity systems of both countries. During 2016, Colombian electricity generators sold 43.9 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 0.8 GWh in 2016.

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,
	2016				2015				2014
	Sales		% ofSales Volume		Sales		% of Sales Volume		Sales		% of Sales Volume
Contracted sales		13,329		74.0		12,505		74.1		10,969		69.5
Non-contracted sales		4,686		26.0		4,381		25.9		4,804		30.5
Total electricity sales(1)		18,015		100		16,886		100		15,773		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 2016, Emgesa served 468 customers, of which 452 were unregulated customers and 16 were distribution and trading companies. Emgesa’s sales to our Colombian distribution subsidiary, Codensa, accounted for 46% of our total contracted sales with regulated customers in 2016. Electricity sales to the five largest unregulated customers represented 21% of total contracted sales with unregulated customers.

For the year ended December 31, 2016, principal distribution customers were: Codensa (our subsidiary), Electrificadora del Caribe (“Electricaribe”), Empresas Públicas de Medellín (“EPM”), Centrales Eléctricas del Norte de Santander (“CENS”) and Empresa de Energía de Boyacá (“EBSA”).

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 2,988 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 2,069 MW), which includes Termoflores and Epsa; and Gecelca (with an installed capacity of 1,204 MW).

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Operations in Peru

We participate in electricity generation in Peru through our subsidiaries Enel Generación Perú (formerly known as Edegel S.A.A.) and Enel Generación Piura (formerly known as Empresa Eléctrica de Piura S.A.). We operate a total of 27 generation units in Peru, with a total installed capacity of 1,977 MW. As of December 2016, Enel Generación Perú owns 18 hydroelectric units, with a total installed capacity of 787 MW, and the remaining 787 MW consists of 7 thermal units. Enel Generación Piura owns two thermal units with an aggregate installed capacity of 293 MW.

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 16.4% of the country’s total electricity generation capacity as of December 31, 2016.

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

According to the Committee of Economic Operation of the Peruvian System (“COES” in its Spanish acronym), we generated 18.3% of total Peruvian electricity production in 2016.

Hydroelectric generation represented 47.9% of total production of our Peruvian generation subsidiaries in 2016. In the case of Enel Generación Perú, in 2016, hydrological levels were lower than their historical averages in the rivers that supply Enel Generación Perú’s hydroelectric power plants. According to COES, hydrological levels of the Rimac River Basin (Huinco, Matucana, Callahuanca, Moyopampa and Huampaní) were 8.9% lower than the historical average; hydrological levels of the Tulumayo River (C.H. Chimay) were 13.7% lower than the average and hydrological levels of the Tarma River (C.H. Yanango) were 23.7% lower than the average.  On the other hand, thermal generation increased compared to 2015, mainly due to a higher electricity demand and the lower hydroelectric generation as discussed above.

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

ELECTRICITY GENERATION IN PERU (GWh)

	Year ended December 31,
	2016				2015				2014
	Generation		%		Generation		%		Generation		%
Hydroelectric generation (Enel Generación Perú)		4,170		47.9		4,653		52.9		4,439		49.0
Thermal generation (Enel Generación  Perú and Enel Generación Piura)		4,529		52.1		4,148		47.1		4,623		51.0
Total generation		8,698		100		8,801		100		9,062		100

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

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

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

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

	Year ended December 31,
	2016				2015				2014
	(GWh)		%		(GWh)		%		(GWh)		%
Electricity generation		8,698		88.8		8,801		94.8		9,062		91.4
Electricity purchases		1,101		11.2		482		5.2		854		8.6
Total		9,800		100		9,283		100		9,916		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 9.4% in 2016 compared to 2015, amounting to 43,679 GWh.

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

ENEL GENERACION PERÚ’S ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

	Year ended December 31,
	2016				2015				2014
	Sales		% of Sales Volume		Sales		% of Sales Volume		Sales		% of Sales Volume
Contracted sales(1)		8,734		96.1		7,971		92.3		8,719		93.6
Non-contracted sales		358		3.9		662		7.7		601		6.4
Total electricity sales		9,091		100		8,633		100		9,320		100

(1) Includes sales to distribution companies without contracts.

Enel Generación Perú’s electricity sales increased by 5.3% in 2016 compared to 2015, mainly due to higher sales to regulated customers. In 2016, Enel Generación Perú had energy contracts with eight regulated customers and 21 unregulated customers and sales to unregulated customers represented 57.6% of Enel Generación Perú’s total contracted sales.

For the year ended December 31, 2016, Enel Generación Perú’s principal distribution customers were (ordered by energy contracted): Enel Distribución Perú (our subsidiary), Luz del Sur, Seal, Electrosureste and Hidrandina. Enel Generación Perú’s principal unregulated customers were (ordered by energy contracted) Votorantim Metais - Cajamarquilla S. A., Chinalco, Hudbay, Siderperú, Productos Tissue del Perú.

In 2016, Enel Generación Piura had contracts with 11 regulated customers and five unregulated customers. Sales to regulated customers represented 92.2% of Enel Generación Piura’s total contracted sales.

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

ENEL GENERACIÓN PIURA’s ELECTRICITY SALES PER CUSTOMER SEGMENT (GWh)

	Year ended December 31,
	2016				2015				2014(1)
	Sales		% ofSales Volume		Sales		% of Sales Volume		Sales		% of Sales Volume
Contracted sales(1)		648		91.4		597		91.8		498		83.6
Non-contracted sales		61		8.6		54		8.2		98		16.4
Total electricity sales		709		100		650		100		596		100

(1) Includes sales to distribution companies without contracts.

For the year ended December 31, 2016, Enel Generación Piura’s principal distribution customers were Enel Distribución Perú and Luz del Sur.

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Our most significant competitors in Peru are: Engie, Ex-GDF Suez, (installed capacity of 2,568 MW), Electroperú a state-owned competitor (914 MW), Kallpa, belonging to Inkia (1,060 MW), Egenor, belonging to Duke, (375 MW) and Fenix (570 MW).

Electricity Transmission Business

CIEN

Our electricity transmission operations are conducted through CIEN, a wholly-owned subsidiary of Enel Brasil, in which we hold a 99.3% economic interest. CIEN consolidates CTM and TESA, which operate the Argentine side of the interconnection line between Argentina and Brazil. In 2016, CIEN represented 1.0 % of our operating revenues and 2.8% of our operating income. CIEN is recognized by the local authority as a “regulatory asset” and as part of the Brazilian grid, and therefore, it is entitled to receive fixed payments called Permitted Annual Compensation (RAP).

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

Electricity Distribution Business

Our electricity distribution business is conducted in Argentina through Edesur, in Brazil through Ampla and Coelce, in Colombia through Codensa, and in Peru through Enel Distribución Perú. For the year ended December 31, 2016, electricity sales increased by 0.5% compared to 2015, totaling 62,716 GWh. For more information on energy sales by our distribution subsidiaries for the last five fiscal years, see “Item 3. Key Information — A. Selected Financial Data.”

Edesur (Argentina)

Edesur is one of the largest electricity distribution companies in Argentina in terms of energy purchases. Edesur operates in a concession area of 3,309 square kilometers in the south-central part of the Buenos Aires metropolitan area, serving approximately 2.5 million customers, under a 95-year concession granted by the Argentine government that will be in force until 2087.  As of December 31, 2016, residential, commercial, industrial and other customers, primarily public and municipal, represented 45%, 30%, 16% and 9%, respectively, of Edesur’s total energy sales. In 2016, its energy losses were 12.0%, compared to 11.6% in 2015.

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

	Year ended December 31,
	2016		2015		2014
Electricity sales (GWh)		18,493		18,492		17,972
Residential		8,408		8,284		7,907
Commercial		4,512		4,489		4,485
Industrial		1,412		1,393		1,363
Other customers(1)		4,161		4,326		4,217
Number of customers (thousands)		2,504		2,479		2,464
Residential		2,200		2,174		2,160
Commercial		273		273		270
Industrial		22		21		23
Other customers		9		11		11
Energy purchased (GWh)(2)		21,039		21,084		20,174
Total energy losses (%)(3)		12.0		11.6		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 excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines as well as technical losses. The figure reported in 2015 differs from the one previously reported due to the recovery of illegally tapped lines.

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For the year ended December 31, 2016, 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 2016, the collection rate from customers was 103% compared to 100.0%, in 2015. The 2016 collection rate was more than 100% due to the collection of unpaid bills from previous years.

During 2016, Edesur maintained the distribution of energy in Buenos Aires and complied with the year’s investment plan.

On January 29, 2016, the Ministry of Energy and Mining instructed ENRE to adjust the tariff of Edesur through a transitory tariff until the application of the Integral Tariff Revision (“RTI” in its Spanish acronym), which was initially expected to apply by December 31, 2016, but took effect February 1, 2017.

Under the RTI, the estimated total increase is 72% for the whole tariff, including the VAD increase, which will be applied in two stages: the first on November 1, 2017 and the second on February 1, 2018 that will be gradually included as part of the tariff rate, in 48 installments starting February 1, 2018.

The new tariff will be in effect for five years until January 2022 and will be adjusted semiannually, mainly based on inflation and service quality efficiency factors and investments as defined under ENRE Resolution 64/2017.  

As of the application of the new RTI in February 2017, the tariff transition period has concluded and Edesur is governed by its concession contract.

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 almost three million customers in a concession area of 32,615 square kilometers, with an estimated population of eight million. Ampla operates under a 30-year concession granted by the Brazilian government which will remain in force until December 2026. As of December 31, 2016, residential, commercial, industrial and other customers represented 40%, 18%, 6% and 36%, respectively, of Ampla’s total sales of 11,181GWh. In 2016, its energy losses were 19.4%, compared to 20.9% in 2015.

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

	Year ended December 31,
	2016		2015		2014
Electricity sales (GWh)		11,181		11,096		11,678
Residential		4,688		4,715		4,754
Commercial		2,088		2,187		2,232
Industrial		638		872		970
Other customers(1)		3,767		3,322		3,721
Number of customers (thousands)		3,054		2,997		2,876
Residential		2,775		2,697		2,607
Commercial		177		175		172
Industrial		5		5		5
Other customers		97		120		92
Energy purchased (GWh)(2)		14,348		14,591		14,647
Total energy losses (%)(3)		19.4		20.9		20.3

(1) The data for other customers includes tolls.

(2) Energy losses are calculated as the percent difference between energy purchased and energy sold excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines as well as technical losses. The figure reported in 2015 differs from the one previously reported due to the recovery of illegally tapped lines.

In 2016, the collection rate from customers was 97.1%, compared to 94.2% in 2015.

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For the year ended December 31, 2016, 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 the Concession Contract 05/1996, which regulates the electricity distribution in Ampla’s concession area, Ampla is subject to a comprehensive tariff review by ANEEL every five years. However, Ampla has negotiated an anticipated tariff review for 2018 instead of 2019.

As of March 15, 2016, the annual tariff review raised average consumer tariffs by 7.4%.

Coelce (Brazil)

Coelce is mainly engaged in the distribution of electricity to municipalities located in the State of Ceará, and serves almost 3.8 million customers in a concession area of 148,920 square kilometers, with an estimated population of 8.8 million. Coelce operates under a 30-year concession granted by the Brazilian government that will remain in force until December 2027. As of December 31, 2016, residential, commercial, industrial and other customers represented 36%, 18%, 9% and 37%, respectively, of Coelce’s total sales of 11,628 GWh. In 2016 and 2015, energy losses were 12.5%.The following table sets forth Coelce’s principal operating data for each of the periods indicated:

	Year ended December 31,
	2016		2015		2014
Electricity sales (GWh)		11,628		11,229		11,165
Residential		4,129		3,959		3,940
Commercial		2,136		2,148		2,076
Industrial		1,055		1,196		1,206
Other customers(1)		4,308		3,925		3,942
Number of customers (thousands)		3,890		3,758		3,625
Residential		2,861		2,865		2,802
Commercial		236		232		230
Industrial		8		7		7
Other customers		786		654		587
Energy purchased (GWh)		13,298		13,016		12,806
Total energy losses (%)(2)		12.5		12.5		12.8

(1) The data for other customers includes tolls.

(2) Energy losses are calculated as the percent difference between energy purchased and energy sold excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines as well as technical losses. The figure reported in 2015 differs from the one previously reported due to the recovery of illegally tapped lines.

In 2016, the collection rate from customers was 97.8% compared to 96.1% in 2015.

For the year ended December 31, 2016, Coelce’s main unregulated customers were (ordered alphabetically): Durametal, Esmaltec, Gerdau, Grandene, Mecesa, Norsa Refrigerante, North Shopping, Petrobras, Vicunha Textil and Votorantim.

Under the concession contract which regulates the electricity distribution in Coelce’s concession area, Coelce is subject to a comprehensive tariff review by ANEEL every four years, with the next one expected in 2019.

As of April 19, 2016, the annual tariff review applied an average increase of 13.0% to consumers.

Codensa (Colombia)

Codensa is a Colombian electricity distribution company that serves a concession area of 35,194 square kilometers in Bogotá and other 135 municipalities of the provinces of Cundinamarca, Tolima and Boyacá, with approximately 3.2 million customers.

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

Since 2001, Codensa only provides services to regulated customers. The unregulated market is serviced directly by our generation company, Emgesa, with the exception of public lighting in Bogotá. In 2016 and 2015, energy losses were 7.1%.

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

	Year ended December 31,
	2016		2015		2014
Electricity sales (GWh)		13,632		13,946		13,660
Residential		4,656		4,665		4,575
Commercial		2,294		2,280		2,213
Industrial		1,047		1,011		931
Other customers(1)		5,635		5,990		5,941
Number of customers (thousands)		3,248		2,865		2,772
Residential		2,890		2,543		2,459
Commercial		302		273		265
Industrial		48		45		44
Other customers		8		4		4
Energy purchased (GWh)(2)		14,680		15,039		14,726
Total energy losses (%)(3)		7.1		7.1		7.2

(1) The data for other customers includes tolls.

(2) The increase in the number of customers is mainly explained by the merger of DECSA and EEC with and into Codensa. Codensa is the continuing company as of October 1, 2016.

(3) In 2016, 42% of the electricity purchased was acquired from Emgesa, 20 % in 2015 and 28% in 2014.

(4) Energy losses are calculated as the percent difference between energy purchased and energy sold excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines as well as technical losses The figure reported in 2015 differs from the one previously reported due to the recovery of illegally tapped lines.

In 2016, the collection rate from customers was 99.8% compared to 100.5% in 2015. The 2015 collection rate was more than 100% due to the collection of unpaid bills from previous years.

For the year ended December 31, 2016, Codensa’s only unregulated customer was Alumbrado Público Distrito Capital Bogotá.

Codensa’s ordinary tariff review is currently in progress and is expected to conclude in 2017.

Enel Distribución Perú (Perú)

Enel Distribución Perú is a Peruvian electricity distribution company that operates in a concession area of 1,517 square kilometers under an indefinite concession granted by the Peruvian government. It has an exclusive concession to distribute electricity in the northern part of the Lima metropolitan area, as well as some provinces in the Lima region, including Huaral, Huaura, Barranca and Oyón, and the adjacent province of Callao. As of December 31, 2016, Enel Distribución Perú distributed electricity to approximately 1.4 million customers, an increase of 2.2% compared to 2015.

As of December 31, 2016, Enel Distribución Perú had total energy sales of 7,782 GWh, an increase of 2.1% compared to 2015. Energy losses decreased to 7.8% in 2016 from 8.1% in 2015.

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

	Year ended December 31,
	2016		2015		2014
Electricity sales (GWh)		7,782		7,624		7,339
Residential		2,818		2,839		2,719
Commercial		1,353		1,688		1,641
Industrial		1,421		1,213		1,220
Other customers(1)		2,190		1,884		1,759
Number of customers (thousands)		1,367		1,336		1,293
Residential		1,296		1,266		1,223
Commercial		42		42		42
Industrial		1		1		1
Other customers		28		27		27
Energy purchased (GWh)(2)		8,444		8,311		7,995
Total energy losses (%)(3)		7.8		8.1		8.2

(1) The data for other customers includes tolls and does not consider own consumption.

(2) In 2016, 35% of the electricity purchased was acquired from Edegel, Chinango and Enel Generación Piura. In 2015, 26% of the electricity purchased was acquired from Edegel and Enel Generación Piura, and 27% from Edegel and Enel Generación Piura in 2014.

(3) Energy losses are calculated as the percent difference between energy purchased and energy sold excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise mainly from illegally tapped lines as well as technical losses. The figure reported in 2015 differs from the one previously reported due to the recovery of illegally tapped lines.

In 2016, Enel Distribución Perú’s primary unregulated customers were (ordered alphabetically): Alicorp,  APM Terminals, Centro Comercial Plaza Norte, Corporación Celima, Corporación JR Lindley, DP World, Fabrica Peruana de Eternit, Goodyear Peru, G&M Ferrovias S.A., Indeco, Lima Airport Partners, Makro Refineria La Pampilla, Sodima and YOBEL.

In 2016, the collection rate from customers was 99.8% compared to 98.6% in 2015.

The review of Enel Distribución Perú’s distribution tariff rates was expected to occur in October 2017, but on December 21, 2016, the Peruvian Ministry of Energy and Mines extended the application of the current tariffs until October 2018.

For further details regarding regulation of the distribution business, see “Item 4. Information on the Company— B. Business Overview — Electricity Industry Regulatory Framework.” For further details regarding the financial impact, see “Item 5. Operating and Financial Review and Prospects— A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2016 and 2015.”

Seasonality

The distribution business is directly influenced by seasonal changes in energy demand. Although the price at which a distribution company purchases electricity can change seasonally and has an impact on the price at which it is sold to end users, it does not have an impact on our profitability since the cost of electricity purchased is passed to end users through tariffs that are set for multi-year periods.

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ELECTRICITY INDUSTRY REGULATORY FRAMEWORK

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

		Argentina	Brazil	Colombia	Peru
Gx	Unregulated Market	Regulated remuneration scheme (Resolution 482/2015)	Spot markets with prices defined by the regulator	Spot market with auctioned cost (Price-offered)	Spot markets with costs audited by the regulator
	Regulated	Seasonal Price	Auction Thermal - 20 years / Hydro - 30 years	Auction 3/5 years	Auction up to 20 years and node price
	Capacity	Contribution peak demand	--	Firm energy contribution (energy auctions for at least 20 years)	Income based on contributions during peak demand
Tx	Features	Public - Open Access - Regulated Tariff Monopoly Regime for Transmission System Operators
Dx	Law	Concession contract		Authorization Operation Zone	Administrative Concession (indefinite)
	Expansion	95 years	30 years	-	Undefined
	Tariff review	5 years	4/5 years	5 years	4 years
Td	Unregulated customers	> 0.03 MW	> 0.5 MW to 3MW/ NCRE > 3MW/conventional	> 0.1 MW	> 0.2 to 2.5 MW optional > 2.5 MW mandatory
	Unregulated market (%)	≈ 20%	≈ 25%	≈ 30%	≈ 45%

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

Argentine Electricity Regulatory Framework

Industry Overview and Structure

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

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

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 95/2013 that set out a regulated remuneration scheme for power generation activity beginning retroactively from February 2013. On February 2, 2017, the Secretary of Electric Energy published Resolution 19/2017 that set a new remuneration scheme for existing power generators.

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 Electric 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. These 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 95, large customers buy electricity directly from CAMMESA, following the expiration of their bilateral contracts directly with generators.

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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 activities include: 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 Edesur’s management. ENRE Resolution 243/2013 increased the term from 45 to 90 business days and it was extended by successive 90 day-terms. The overseer’s appointment terminated in 2016.

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.

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Regulatory Developments: The Industry After the Public Emergency Law

Law 25,561/2002, the Public Emergency Law, was enacted 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 former 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 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. The resolution also set a cap on the spot price at Ar$ 120 per MWh, which was valid until the adoption of Resolution 95 (March 2013). The generators that adopted Resolution 95 were remunerated according to such resolution and later by Resolution 529, Resolution 482 and Resolution 22.

Until last year, the Argentine government had avoided increasing electricity tariffs for end customers and seasonal prices had been maintained substantially fixed in Argentine pesos.

The former Argentine Secretary of Energy published Resolution95, Resolution 529 and Resolution 482, in 2013, 2014 and 2015, respectively, and under the new government, the Secretary of Electric Energy published Resolution 22, 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).

On December 16, 2015, the Argentine president enacted Decree134, which declared a state of emergency for the National Electricity sector through December 31, 2017 and instructed the newly-created Ministry of Energy and Mining 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.

On March 22, 2016, the Argentine Secretary of Energy issued Resolution21, which called for additional thermal generation capacity for the 2016 and 2017 summer seasons and during the 2017 and 2018 winter seasons. As a result of this, tenders of 2,871 MW were awarded, of which 1,915 MW was tendered during the first stage and the other 956 MW was awarded during a second stage.

On February 2, 2017, Resolution19 of the Secretary of Electric Energy (“SEE”) established guidelines for the remuneration of existing power plants. The resolution defines a minimum remuneration for power by technology and scale. Additionally, thermal units have the option of offering commitments of availability with an equal differential remuneration for all the technologies. Thermal generators can declare during each summer period the value of firm power to be committed for each unit during a three-year period with the ability to differentiate between the summer and winter period (adjustments can be made in the same period).

As an exception applicable to 2017, the declaration of “Guaranteed Availability Commitments” together with information required for Seasonal Winter Programming is authorized, from May 1 to October 31, 2017. Generators will sign a Guaranteed Availability Commitment contract with CAMMESA who in turn may assign the contract to demand as defined by the SEE. The remuneration received by a unit with power committed will be proportional to its fulfillment or the minimum value calculated based on the minimum price for power. Thermal generators may also offer additional power availability for bimonthly periods, which will be auctioned at a maximum price.

For hydroelectric power plants, a new scheme is defined for evaluating power based on actual power available (implying a higher power value for remuneration compared to the previous regulation). Hydroelectric power plants also have a base power price, and an

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additional price differentiated from May to October 2017, and another from November 2017. The remuneration values of Resolution 19 are denominated in U.S. dollars and will be converted at the exchange rate published by the Central Bank of Argentina, corresponding to the last business day, with maturity dates established by CAMMESA.

FONINVEMEM

Resolution 712 created FONINVEMEM, a fund whose purpose is to increase electricity capacity/generation within the Argentine MEM. Pursuant to Resolution406, 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 406 from January 1, 2004 to December 31, 2006. CAMMESA was appointed to manage FONINVEMEM.

Pursuant to Resolution 1,193, 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, Resolution564 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 406 for an additional period ending December 31, 2007. These plants were completed in 2010 and are powered by natural gas or alternative fuels.

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 the Vuelta 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 the Río 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 2017.

Limits and Restrictions

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

Vertical Integration Restrictions

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

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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

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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 Law15,336 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 95 suppressed the market for energy transactions among generators, large customers and traders.

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.

Pursuant to Resolution 1,301, 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 134, which declared a state of emergency for the Argentine Electricity sector, the Ministry of Energy and Mining enacted Resolution 6 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 and through January 2016, the former Argentine Secretary of Energy has been approving seasonal prices lower than those recommended by CAMMESA.

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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 Resolution 2,016, 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 467. This presentation only included the income requirements and did not include rate proposals, which were later presented to ENRE in May 2010.

On January 28, 2016, under the new government and following the seasonal price changes, emergency Resolution7 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.

On January 29, 2016, ENRE issued Resolution 1, which set a new temporary tariff effective February 1, 2016. Its application is according to the MEM Resolution7, which changed supply procedures and defines monthly billing.

On April 5, 2016, ENRE enacted Resolutions 54 and 55, which commenced the application of the RTI for Edesur and Edelnor, and were supplemented by successive Resolutions 463, 492 and 494, which defined procedures, rate of return, quality of service and technical parameters, among other things.

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On September 1, 2016, Edesur submitted to ENRE its proposal and all required reports related to its investment plans and the RTI process.

On September 28, 2016, ENRE held a public hearing to discuss the proposals of distributors. On December 30, 2016, ENRE enacted Resolution 626, approving the document titled "Final Public Hearing Resolution" that informed and responded to the opinions expressed in the tariff proposals presented by the companies and authorized ENRE to carry out changes to tariffs.

On February 1, 2017, ENRE published Resolution 64 (subsequently corrected by Resolution 92), which closed the RTI process and defined Edesur’s annual remuneration as Ar$ 14,539,836,941.

As a result of the RTI process to be applied as of February 1, 2017, the Ministry of Energy and Mining instructed ENRE to increase the VAD by a maximum of 42% compared to the current VAD. The VAD will increase in two stages: the first on November 1, 2017 and the second on February 1, 2018, and will include the VAD differences accounting for the gradual increase in the tariff of Edesur.

As of February 1, 2017, the tariff transition period concluded and Edesur is now governed by a concession contract signed in 1992 and the related modifications implemented by ENRE Resolution 64.

Penalties

The distributors are subject to three types of penalties:

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

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

3) Supply penalties related to the system as a whole including generation, transmission, and distribution intended to compensate 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 Decree2,743. Due to technological reasons, the transmission sector is heavily affected by economies of scale that limit competition. As a result, the transmission sector operates under monopoly conditions and is subject to considerable regulation. Resolution196 of the Ministry of Energy and Mining instructs ENRE to complete the RTI before January 31, 2017.

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. Resolution949 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, 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 1,410 issued in October 2010, reinforced such restrictions on gas

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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 712 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 108/11 which allowed CAMMESA to sign contracts directly with generators of renewable energy on conditions similar to Resolution 712.

In October 2015, Law 27,191 “National Development Scheme for the Use of Renewable Energy Sources for the production of Electric Power”, defined renewable energy sources as: 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.

Resolution 71 and 72, dated May 17, 2016, of the Argentine Ministry of Energy and Mining, extended Law 27,191 and Regulatory Decree 531, which commenced MEM’s 1,000 MW tender process for renewable energy as part of the "RenovAr-Round 1 Program" comprised of the following: wind power of 600 MW, photovoltaic power of 300 MW, biomass fuel of 65 MW, mini hydro power of 20 MW and biogas power of 15 MW.

There were 123 offers for a total of 6,366 MW, of which 105 (42 for wind energy for 2,870 MW, 50 for solar energy for 2,305 MW, eight for biomass and biogas for 23 MW, and five for small hydroelectric power for 11 MW). On September 30, 2016, offers were made with most falling below the maximum award price stipulated by the Ministry; for wind energy the minimum price was US$ 49 per MWh and for solar energy US$ 59 per MWh. Under Round 1 of the RenovAr Program, 29 projects were awarded for a total of 1,142 MW. Subsequently, a new round of the Program (Round 1.5) was carried out, which awarded 30 projects for a total of 1,281.5 MW and an average price of US$ 54 per MWh (765.4 MW for wind energy and 516.2 MW for solar energy) .

The RenovAr Program (Round 1+ Round 1.5) awarded a total of 59 projects for a total of 2,423.5 MW and a weighted price of US$ 57.44 per MWh.

Brazilian Electricity Regulatory Framework

Industry Overview and 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.

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

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.e. companies in the distribution business segment): (i) perform activities related to the generation or transmission of electricity; (ii) sell electricity to unregulated customers; (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 5,163/2004 and 5,177/2004 of the Electricity Trading Chamber or Clearing House (“CCEE” in its Portuguese acronym), and ANEEL Resolution 109/2004, which introduced the Electricity Trading Convention. This convention defines the terms, rules and procedures for the trading in the CCEE. Two possible scenarios 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 are 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, 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

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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 sources 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 February 2017, submitted by the Energy Research Company, (“EPE” in its Portuguese acronym), 99.4% of the energy required by Brazil is supplied by the Brazilian NIS and the remaining 0.6% is supplied by isolated systems.

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.

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The Electricity Law

General

In 1993, the Brazilian electricity sector was reformed through Law 8,631, 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 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, 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 Law 10,847 and 10,848 of March 15, 2004, and Decree 5,163 of July 30, 2004. The principal objectives of these laws and decrees were to (i) guarantee the security of the electricity supply, 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 299 repeals certain sections of ANEEL Resolution 278, which established the limits and conditions for the participation of electricity distributors and traders. Specifically, the section of Resolution 278 on limits to generation was repealed. Subsequently, Resolution 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.

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

On January 23, 2013, the Brazilian Congress approved Law 12,783, which renewed electricity concessions according to Provisional Resolution 579. This law requires companies to reduce the average electricity tariff by 20.2% from February 2013, and to extend generation, transmission and distribution concessions for 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, and for 2017, between R$ 33.68 per MWh to R$ 533.82 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

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contracts, to purchase cheaper energy at a price that covers the incremental costs of operation, the maintenance of hydroelectric plants and the financial compensation for use of water. The tariff used for trading energy in the MRE, the Optimum Energy Tariff, was set as R$ 11.58 per MWh for 2017.

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.

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 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.

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. 

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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.

On April 29, 2016, an A-5 tender resulted in the allocation of 528,877 MW to hydroelectric plants (61.4%), biomass thermal plants (37.5%) and gas thermal plants (1.1%) at an average price of R$ 198.59 per MWh. In addition, an A-1 tender was held on December 23, 2016, resulting in the allocation of 21 MW at an average price of R$ 118.15 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 (15-25 years for thermal and 30 years for hydroelectric) and certain price levels for each technology in order to promote investment for the required expansion. On the other hand, “formerly existing power plants,” which include depreciated power plants, can sell their energy at lower prices under contracts with shorter terms.

Law 10,438 created certain incentive programs 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 BNDES 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 5 163 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 109 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.

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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 “Item 4. Information on the Company— B. Business Overview — Electricity Industry Regulatory Framework —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;

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• 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 11.4% to 10.9% real rate pre-tax), the regulatory asset base, the X factor and operating costs. After evaluating the contributions from distributors at Public Hearing 023, ANEEL decided to review the proposed 12.3% WACC. As a result, the WACC increased from 11.4% to 12.3% (real pre-tax rate). The new rate was published in the Normative Resolution 648 on March 2, 2015, effective retroactively as of February 5, 2015. The methodology for the fourth tariff cycle is being applied to all distributors in their ordinary tariff reviews. A new revision of WACC will occur at the end of 2017 and will be effective 2018.

Revenue from 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 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 color coded green, yellow and red. Since its creation, the cost ranges and the additional tariffs have been changing according to new expectations of the marginal cost of generation. On January 26, 2016, ANEEL published its latest modification through Note 16, 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	Expensive generation conditions	422.56 ≤ MC< 610.00	+0.0030
Red level 2	Most expensive generation conditions	610.00 ≤ MC	+0.0045

In addition, on September 12, 2016, ANEEL approved Resolution 733, which established the application of an hourly tariff to low tension customers and defined where they may monitor the value of energy during consumption. This new tariff is called a white tariff and will be effective January 2018.

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

Created by Law 10,438, 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 Abrace Association partners’ CDE charges, ANEEL allocated the lost contribution among other customers. The deficits generated by this loss of charges has been included in the next annual distribution tariff adjustment.

ANEEL 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.

On June 22, 2016, Provisional Resolution 735 was enacted, which established that CCEE will replace Electrobras as the debt collector of CDE’s charges as well as the manager of the funds. Between January 1, 2017 and December 31, 2029, CDE’s annual charges will decrease gradually until they are fully satisfied. As of January 1, 2030, the annual cost per MWh will be prorated according to the level of a consumer’s tension.

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Governmental Tariff Reduction Plan (Provisional Resolution 579/2012)

On September 12, 2012, the Brazilian government’s Provisional Resolution 579 reduced tariffs for end customers and defined new concession renewal policies for generation and transmission companies.

In order to reduce tariffs, 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 579 was approved by the Brazilian House of Representatives and was sent to the President of Brazil for signature under Law 12,783. 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 7,945 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 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.

ANEEL has been simplifying the procedures to facilitate the connection of micro and mini generators within the distribution network. As of January 2017, a connection request may be submitted online.

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

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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. Unregulated customers also have this right, provided that they comply with certain technical and legal requirements. This is called “open 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 revenues (a fixed amount paid by consumers and generators); and (iii) extraordinary tariff review).

Law 13,203, published on December 8, 2015, changed the discounts applicable to tariffs for the utilization of Transmission and Distribution Systems, including the generation amount and the energy’s final destination when self-produced. For the regulation of this law, ANEEL established public hearing 38 that was replaced by Resolution 77.

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.

Colombian Electricity Regulatory Framework

Industry Overview and Structure

The Wholesale Electricity Market in Colombia (“Colombian MEM” in its Spanish acronym) is based on a competitive market model and operates under open access principles. The Colombian 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. 

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

Generation activity consists of the production of electricity through hydroelectric, thermoelectric and 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:

1. Energy spot market: short-term daily market

2. Bilateral contracts: long-term market; and

3. “Firm Energy.”

“Firm Energy” refers to the maximum electric energy that a generation plant is able to deliver on a continual basis during a year, in 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.

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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, 97% of the Colombian population in 2015 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

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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, 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.

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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 Law143 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 036 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 026 which enacted the Statute, which defines the rules of operation under critical supply conditions.

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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 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 in May 2014 and by Decree 142 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.

In the tender mentioned above, 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),

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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 the Porvenir II hydroelectric power plant which will have a capacity of 352 MW by 2018. The other two involved increases in OEF for plants already under construction and had available firm energy following the 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 48 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 as Ambeima and Porvenir II have lost their OEF.

During 2013, Resolution 062 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 022, 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.

Also in 2014, CREG published the Circular 088, indicating that no auction was 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 177 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 2016, CREG declared through Resolution 115 that there is no need for a reliability charge auction to supply demand during 2019-2020. However, it did not define the mechanism by which the OEF will be distributed among plants. It is expected that CREG will publish a new methodology during the first half of 2017.

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 so called Andean Nations Community; namely, 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

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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 002, which attempts to resolve the discrepancies between firm capacity in Panama and the OEF in Colombia; (ii) CREG 004, which outlines the exchanges in conditions of rationing; and CREG 057, 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-owned Empresa 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.

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During 2015, CREG presented the final scheme for supply contract indexation which considers two methodologies: bilateral negotiation and regulated formula application. Also, the Colombian Ministry of Energy issued regulations related to the reliability and security of natural gas supply; by modifying the definition of essential demand, the priority of attention and the main topics for the development of the “Natural Gas Supply Plan.”

During 2016, the Energy Mining Planning Unit (“UPME” in its Spanish acronym) published the final version of the Natural Gas Supply Plan, which included the main projects needed in the gas market to avoid shortages and procure a long term supply for the country. Among the most anticipated projects are a second LNG plant in the pacific coast and the construction of a new pipeline, connecting the new plant with existing facilities.

Finally, as a mechanism to supply thermal demand and improve the reliability of the national electricity supply, the first LNG plant located in the Caribbean started commercial operation in December 2016. This plant provides gas for at least 25% of the national gas demand.

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:

• Level 1: less than 1 kV;

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

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

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

In 2013, CREG began to review distribution charges using Resolution 043, which contained a remuneration methodology proposal and was later supplemented by CREG Resolution 079 containing the Purposes and Guidelines for the Distribution Remuneration for the 2015-2019 period. In 2015 and 2016, CREG published Resolutions 179, 024 and 176, which disclose remunerative parameters. These draft methodologies incorporate replacement incentives (annual compensation for investments in the improvements of quality efficiency; new technology and control of energy losses) by including depreciation as part of a tariff formula in investment plans. The new distribution remuneration methodology will be published in 2017. In March 2017, the final comments on Resolution 19/2017 were published, with relevant concepts in low tension remuneration and incentives for service quality.

Additionally, CREG issued Resolutions 083, 112, and 095, which defined the methodology for calculating 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

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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.

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.

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.

The review of regulated transmission charges began in 2013 with the publication of the bases for the remuneration methodology proposed by CREG Resolution 042. Such bases were supplemented by the development of the Purposes and Guidelines for the Transmission Remuneration for the 2015-2019 period and by resolutions that have been submitted for review under CREG Resolution 178, 023 and 177. CREG Resolution 042 was defined by MME and seeks to ensure timely expansions and adequate assets. The new transmission remuneration methodology is expected to be published during the first half of 2017.

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 180. 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

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2016. In the case of Codensa, in 2015 CREG published Resolution 120/2015 approving Codensa’s selling costs. The new tariff applies as of 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 117, and the deadline for consultations has passed. It is expected that the final resolution on MOR will be issued during 2017.

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 240B/2015 establishes the basis of the studies to determine the unit cost formula of providing service to regulated customers. It is expected that the commission will issue the formula during 2017.

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 011 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 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 (“NCRE”), 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 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 2,143 which defines the process agents must undertake in order to receive the tax and tariff benefits established by Law 1,715. According to the decree, to receive tax benefits, agents must procure certificates from the Energy and Mining Planning Unit (UPME) and ANLA following procedures and requirements defined by UPME Resolution 45 of 2016 and MADS Resolution 1,283 of 2016.

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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 1,450 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.

In 2008, Resolution 909 was enacted to increase air quality, and to allow energy recovery from waste and/or hazardous waste in thermal generation plants by establishing admissible limits for emissions produced by stationary sources. In 2011, Institutional Decree 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 1,517 established the procedures relating to the Environmental Compensation for Biodiversity Loss while Decree 1,640 of 2012 set forth regulations for the planning and management of hydrographic basins. In addition, Resolution 1,526 established the procedural requirements for the subtraction of the forest areas protected by Law 2 of 1959.

Due to national discussions about environmental licensing, MADS enacted Decree 2,041 which aimed to reduce the timing needed to receive the necessary licenses. In 2016, Resolution 376 established seven additional activities that do not require license modifications.

During 2015, MADS issued the Single Regulatory Decree 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.

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. During 2016, MADS defined the actions necessary to accomplish these goals in different sectors, and also established the organizational responsibilities of the National Climate Change System (SISCLIMA) through Decree 298.

In 2016, Decree 630, established measures to renew the fleet of taxis in 2017 and obtain benefits for using vehicles with zero emission, electric or hydrogen technologies.

During 2016, MADS delimited the Paramo ecosystem. So far, the Ministry has published the delimitation of 18 of these ecosystems throughout the country. These ecosystems provide water supply to hydropower plants and to the population, as well as other environmental services.

In 2016, MADS issued Resolution 1312, which established the Terms of Reference for the Environmental Impact Assessment for onshore wind power plants.

Peruvian Electricity Regulatory Framework

Industry Overview and Structure

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

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

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 Osinergmin.

In 2008, due to gas transport and electricity transmission problems, Osinergmin defined a new rule to calculate spot prices. Decree 049 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 October 1, 2017. 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.

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There is only one interconnected system, the SEIN, and several isolated regional and smaller systems that provide electricity to specific areas. According to Osinergmin, as of December 31, 2015, 93.3% 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 030 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, hydrocarbon and mining activities, controls and enforces compliance with the obligations stated in the concession contracts, and is responsible for the preservation of the environment in connection with the development of these activities. Osinergmin’s Tariff Regulatory Bureau has the authority to publish the regulated tariffs. It also controls and supervises the bidding processes required by distribution companies to purchase energy from generators.

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

General

The general legal framework applicable to the Peruvian electricity industry includes: the Law of Electricity Concessions (Decree Law 25,844/1992) and its ancillary regulations, the Law to Secure the Efficient Development of Electricity Generation (Law  28,832), the Technical Regulation on the Quality of the Electricity Supply (Supreme Decree 020), the Electricity Import and Export Regulation (Supreme Decree 049), the Antitrust Law for the Electricity Sector (Law 26,876), the law that regulates the activity of Osinergmin (Law 26,734, together with Law 27,699), and Decree Law 1,221 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 and Regulation 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.

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Law 29,969 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 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, enacted on September 24, 2015, has been applied since 2016, and establishes the following main modifications:

• 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.

• 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.

• 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.

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

• 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%.

• 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.

• 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.

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Dispatch and Pricing

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

Sales by Generation Companies to Unregulated Customers

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

Sales to Distribution Companies and Certain Regulated Customers

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

Sales of Capacity to Other Generation Companies

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

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

Regulatory Charges

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

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

Tenders Promoted by the State

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 in Reserva Fría de Talara, Trujillo and Ilo that would add another 800 MW to the system. The bid resulted in two of the projects being awarded: Reserva Fría de Talara (200 MW, for EEPSA, our subsidiary) and Ilo (400 MW, for Enersur, an unrelated company). These plants receive regular payments for being permanently available to operate and provide energy to the SEIN whenever the COES calls on them and will also be reimbursed for the fuel costs incurred for generating electricity. The Trujillo generation facility was later replaced by the Eten generation facility and awarded to Planta de Reserva Fría de Generación de Eten S.A. (200 MW).

On March 21, 2013, Peruvian Investment Promotion Agency held an international public tender to promote private investments in the Hydroelectric Plant project (Molloco Hydroelectric Plant—280 MW), which is located in the hills of the Arequipa 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

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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 2016 and 2015, the net electricity exports amounted to 15.5 GWh and 54.3 GWh, respectively. 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 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.

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, and for the next tariff revision in 2018, the VAD would be set for every company with 50,000 or more customers.

Actual return on investment for a distribution company depends on its performance relative to the standards chosen by the Osinergmin for a theoretical model company. The tariff system allows for a greater return for distribution companies that are more efficient than the model company. Tariff studies are performed by the distribution companies. Preliminary tariffs are tested to ensure that they provide an average 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 2018 (extended from October 2017 because of the new regulation).

Regulatory Charges

In addition to the taxes that are applicable to all industries (mainly income tax and value added tax), operators in the electricity industry 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 is up to 1% of the annual billing of each company and the funds levied are distributed proportionally to MINEM and Osinergmin (regulatory authorities).

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Incentives and Penalties

Law 28,832 and Supreme Decree 052-2007-EM (“General Regulations of the Supply Auctions”) state that if auctions are called for 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 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) and in the Regulation for Environmental Protection regarding Electricity Activities (Supreme Decree 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 sources, referred to in Peruvian regulations as Renewable Energy Resources (“RER” in its Spanish Acronym), for electricity generation are considered to originate from the following power sources: biomass, wind, solar, geothermal and tidal sources, as well as hydroelectric plants with an installed capacity lower than 20 MW.

In 2008, 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.

In December 2015, the last NCRE was tendered with the objective to provide 1,300 GWh to the interconnected system under the understanding that 450 GWh per year are required from mini hydroelectric projects with a maximum capacity of 20 MW each.  As a result, 1,741 GWh were awarded to 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).

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 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 a Supreme Decree with the consenting vote of the Council of Ministers.

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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.”

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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 51.0% of our shares as of December 31, 2016. Enel is an energy company with multinational operations in the power and gas markets, with a focus on Eurpore and Latin America. Enel operates in over 30 countries across four continents, produces energy through a net installed capacity of 84 GW and distributes electricity and gas through a network covering 1.9 million kilometers. With over 61 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enel publicly trades on the Milan Stock Exchange.

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The companies listed in the following table were consolidated by us as of December 31, 2016. In the case of subsidiaries, our economic interest is calculated by multiplying our percentage economic interest in a directly held subsidiary by the percentage economic interest of any entity in the chain of ownership of such ultimate subsidiary.

Principal Subsidiaries and Country of Operations	% Economic Ownership of Enel Américas		Consolidated Assetsof Each Main Subsidiary		Revenues and Other Operating Income of Each Main Subsidiary
	(in %)		(inbillionsofCh$)
Electricity Generation and Transmission
Electricity Generation
Dock Sud (Argentina)(1)		40.3		138,131		86,363
El Chocón (Argentina)		65.3		267,633		28,241
Costanera (Argentina)		75.6		187,640		92,633
Fortaleza (Brazil)		99.3		181,633		159,477
Cachoeira Dourada (Brazil)		99.1		180,149		192,912
Emgesa (Colombia)		48.5		2,009,933		778,880
Enel Generación Perú (Peru)		83.6		824,626		360,187
Enel Generación Piura (Peru)		96.5		169,879		65,145
Electricity Transmission
CIEN (Brazil)		99.3		235,735		52,179
Electricity Distribution
Edesur (Argentina)		72.1		699,219		664,100
Ampla (Brazil)		99.3		1,663,067		879,499
Coelce (Brazil)		73.7		1,025,347		804,640
Codensa (Colombia)		48.4		1,275,422		928,621
Enel Distribución Perú (Peru)		75.7		827,190		585,196

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

Generation and Transmission Segment

The following companies include generation and transmission companies consolidated by us as of December 31, 2016.

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 2016, Dock Sud generated 5,025 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 40.3%.

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. We own a 75.6% economic interest in Costanera.

El Chocón (Argentina)

El Chocón is an Argentine electricity generation company. It has two hydroelectric power stations with an aggregate installed capacity of 1,364 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. We own a 65.3% economic interest in El Chocón.

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, 2016, had a concession that expires in 2027. Enel Brasil has a 99.8% ownership interest in Cachoeira Dourada and our economic interest is 99.1%.

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CIEN (Brazil)

CIEN is a Brazilian transmission and trading company wholly-owned by Enel Brasil. It transmits electricity through two owned transmission lines that connect Argentina and Brazil, covering a distance of 500 kilometers, with a total interconnection capacity of 2,100 MW. As of December 31, 2016, 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 99.3%.

Enel Brasil (Brazil)

In 2005, Enel Brasil was formed in order to manage all Brazilian generation, transmission and distribution assets that Enel owned in conjunction with Enersis, 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). We beneficially own a 99.3% economic interest in Enel Brasil.

Fortaleza (Brazil)

Fortaleza owns and operates a 327 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, 2016, Fortaleza had a concession that expires in 2031. Fortaleza is wholly-owned by Enel Brasil, and we hold a 99.3% economic interest.

Emgesa (Colombia)

Emgesa has a total installed generating capacity of 3,510 MW, of which 87% is from hydroelectric power plants and 13% is from thermoelectric power plants. Empresa de Energía de Bogotá S.A. directly holds a 51.5% equity interest in Emgesa. We beneficially own 48.5% of Emgesa’s shares and have 56.4% of the voting rights. As a result of our ownership in Emgesa and pursuant to a shareholders’ agreement, we are allowed to appoint the majority of the Board members and, therefore, control Emgesa. For more information, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results. — 1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

Enel Generación Perú (Peru)

Enel Generación Perú, an electricity generation company, owns and operates seven hydroelectric plants and two thermal plants, with a consolidated installed capacity of 1,684 MW. In October 2009 and in September 2014, we acquired additional shares of the company. As of December 31, 2016, we hold an economic interest of 83.6%. For more information about the purchases, see “Item 4. Information on the Company – A. History and Development of the Company - History.”

Enel Generación Perú 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.

Enel Generación Piura (Peru)

Enel Generación Piura has 293 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 Enel Generación Piura.

Distribution Segment

The following companies include distribution companies consolidated by us as of December 31, 2016.

Edesur (Argentina)

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

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 over 3 million customers in a concession area of 32,615 square kilometers. As of December 31, 2016, Ampla had a concession that expires in 2026. We have a 99.3% 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 3.8 million customers within a concession area of 148,920 square kilometers. As of December 31, 2016, Coelce had a concession that expires in

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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%. Our economic interest in Coelce is 73.7%.

Codensa (Colombia)

Codensa is a Colombian electricity distribution company that serves a concession area of 35,194 square kilometers in Bogotá and 135 other municipalities of the provinces of Cundinamarca, Tolima and Boyacá, serving approximately 3.2 million customers. Our economic interest in Codensa 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.”

Enel Distribución Perú (Peru)

Enel Distribución Perú, 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, 2016, Enel Distribución Perú distributed electricity to approximately 1.4 million customers. We hold a 75.7% economic interest in Enel Distribución Perú.

Selected Related and Jointly-Controlled Companies

Yacylec (Argentina)

Yacylec is an Argentine electricity transmission company. As of December 31, 2016, Yacylec had a concession that expires in 2088. Our economic interest in Yacylec is 22.2%. 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.

D. Property, Plants and Equipment.

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

Property, Plant and Equipment of Generating Companies

We conduct our generation and transmission businesses directly in Argentina, Colombia and Peru, consolidating revenues from 28 generation power plants and through our subsidiary Enel Brasil, which consolidates revenues from two generation power plants. 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, severe and extended droughts or any other such natural disasters, could have a material adverse effect on our operations.

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

			Installed Capacity(1) As of December 31,
Country/Company	Power Plant Name	Power Plant Type(2)	2016		2015		2014
			(in MW)
Argentina
Costanera
	Costanera Steam Turbine	Steam Turbine/Natural Gas+Fuel Oil		1,131		1,131		1,131
	Costanera Combined Cycle II	Combined Cycle/Natural Gas+Diesel Oil		851		851		851
	Buenos Aires Combined Cycle I	Combined Cycle/Natural Gas		322		322		322
	Total			2,304		2,304		2,304
El Chocón
	Chocón	Reservoir		1,200		1,200		1,200
	Arroyito	Pass-through		128		128		128
	Costanera DE(3)	Diesel Engines (Diesel Oil + Fuel Oil)		36	—		—
	Total			1,364		1,328		1,328
Dock Sud
	Dock Sud CC	Combined Cycle/Natural Gas+Diesel Oil		798		798		798
	Dock Sud TG	Gas Turbine/Natural Gas+Diesel Oil		72		72		72
	Total			870		870		870
Totalcapacity in Argentina				4,537		4,502		4,502
Brazil
Cachoeira Dourada	Cachoeira Dourada	Pass-through		665		665		665
Fortaleza	Fortaleza(4)	Combined Cycle/Gas		327		322		322
Total capacity in Brazil				992		987		987

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			Installed Capacity(1) As of December 31,
Country/Company	Power Plant Name	Power Plant Type(2)	2016		2015		2014
			(in MW)
Colombia
Emgesa
	Guavio(5)	Reservoir		1,250		1,213		1,213
	Menor Guavio(5)	Reservoir		13	—		—
	Paraíso	Reservoir		277		277		277
	La Guaca	Pass-through		325		325		325
	Termozipa	Steam Turbine/Coal		236		236		236
	Cartagena	Steam Turbine/ Natural Gas		208		208		208
	Minor plants(6)	Pass-through		75		75		75
	Betania	Reservoir		541		541		541
	Dario Valencia	Pass-through		150		150		150
	Salto II	Pass-through		35		35		35
	Quimbo	Reservoir		400		400	—
Totalcapacity in Colombia				3,509		3,460		3,060
Peru
Enel Generación Perú
	Huinco	Pass-through		268		268		247
	Matucana	Pass-through		137		137		137
	Callahuanca	Pass-through		84		84		80
	Moyopampa	Pass-through		69		69		66
	Huampani (7)	Pass-through		31		30		30
	Santa Rosa(7)	Gas Turbine/Diesel Oil		418		419		413
	Ventanilla(7)	Combined Cycle/Natural Gas		479		484		485
	Total			1,486		1,491		1,458
Chinango
	Yanango	Pass-through		43		43		43
	Chimay(7)	Pass-through		155		152		151
	Total			198		195		194
Enel Generación Piura	Malacas(7)(8)	Gas Turbine/Natural Gas+Diesel Oil		293		298		297
	Total			293		298		297
Total capacity in Peru				1,977		1,984		1,949
Consolidated capacity				11,014		10,933		10,498

(1) The installed capacity corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its own operation.

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

(3) The four diesel engines were installed during 2015 and began commercial operations in July 2016. These engines are located in our Costanera thermal plant. Please see “Item 4. Information on the Company — B. Business Overview — Operations in Argentina.”

(4) We are updating the capacity of the power plant according to ANEEL’s approval.

(5) In April 2016, the two auxiliary units started commercial operations as a separate power plant (Menor Guavio of 13 MW in total). This plant also feeds Guavio’s auxiliary services. In December 2016, El Guavio increased its capacity by 50 MW after some capacity tests (10 MW by unit).

(6) Minor plants have an aggregate capacity of 75 MW. As of December 31, 2016, Emgesa owned and operated four minor plants: Charquito (19.5 MW), El Limonar (18 MW), Laguneta (18 MW) and Tequendama (19.5 MW). Laguneta was previously reported as a separate power plant.

(7) The variation in the installed capacity of this power plant in 2016 was the result of tests performed by COES.

(8) Includes the installed capacity (189 MW) of the Reserva Fría de Talara power plant.

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.

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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

				Transmission Lines(1)
	Location	ConcessionArea		2016		2015		2014
		(in km2)		(in kilometers)
Edesur	Argentina		3,309		1,123		1,120		1,115
Ampla(2)	Brazil		32,615		2,403		2,398		2,395
Coelce(3)	Brazil		148,920		5,127		5,101		5,069
Codensa(4)(5)	Colombia		35,194		928		857		857
Enel Distribución Perú	Peru		1,517		648		573		534
Total			221,556		10,229		10,050		9,970

(1) The transmission lines consist of circuits with voltages in the 34.5-500 kV range.

(2) Transmission lines previously reported differ since we updated commissioning dates.

(3) Transmission lines for 2015 previously included some lines under construction, but not yet under operation.

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

(5) 2015 and 2014 figures differ from those previously reported since we are now reporting the layout of the line regardless of the number of circuits.

Power and Interconnection Substations and Transformers⁽¹⁾

	Year ended December 31,
	2016						2015						2014
	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(2)		71		184		12,504		71		183		12,424		70		175		11,949
Ampla(3)		117		291		5,127		115		294		4,726		115		306		4,658
Coelce(4)		113		183		3,026		111		179		2,955		109		175		2,780
Codensa(5)(6)		169		414		10,433		122		339		9,840		122		331		9,337
Enel Distribución    Perú(7)		37		138		4,119		36		132		3,837		34		129		3,652
Total		507		1,210		35,209		455		1,127		33,782		450		1,116		32,375

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

(2) Figures related to the number of transformers and their related capacity could differ from those previously reported, since we are now including mobile transformers used as backups.

(3) Figures related to the number of substations and their capacity could differ from those previously reported, since we are now not including substations owned by third parties. Number of transformers could also differ from those previously reported, since we now consider single-phase and three-phase transformers as one unit.

(4) 2014 capacity previously reported included the capacity of a backup transformer which was not installed in any substation.

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

(6) 2015 and 2014 figures differ from those previously reported, since we are now including medium voltage substations.

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(7) Figures related to the number of substations and their capacity could differ from those previously reported, since we are now including medium voltage substations. The number of transformers could also differ from those previously reported, since we now consider single-phase and three-phase transformers as one unit.

Distribution Network - Medium and Low Voltage Lines⁽¹⁾

	Year ended December 31,
	2016				2015				2014
	MediumVoltage		Low Voltage		Medium Voltage		Low Voltage		Medium Voltage		Low Voltage
					(in Kilometers)
Edesur		8,002		17,152		7,872		17,018		7,577		16,541
Ampla(2)		35,530		18,668		35,211		18,394		34,649		18,124
Coelce		86,024		51,423		84,290		50,223		83,318		49,718
Codensa(3)		28,507		41,307		20,266		28,270		20,016		28,136
Enel Distribución    Perú		4,597		22,826		4,484		22,268		4,308		21,819
Total		162,660		151,376		152,123		136,173		149,868		134,338

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

(2) The figure for low voltage lines for 2014 were wrong due to a change in the information system.

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

Transformers for Distribution⁽¹⁾

	Year ended December 31,
	2016				2015				2014
	Number of Transformers		Capacity (MVA)		Number of Transformers		Capacity (MVA)		Number of Transformers		Capacity (MVA)
Edesur		19,814		6,280		20,487		6,159		22,155		6,062
Ampla		122,384		5,043		120,387		4,858		118,358		4,666
Coelce(2)		138,060		3,357		134,135		3,208		132,050		3,112
Codensa(2)(3)		65,607		6,361		53,512		5,854		53,200		5,818
Enel Distribución    Perú		10,900		1,865		10,758		1,774		10,532		1,699
Total		356,765		22,907		339,279		21,853		336,295		21,357

(1) The voltage for these transformers is in the range of 34.5 kV (medium voltage) and 110 V (low voltage).

(2) Figures related to the number and capacity of transformers could differ from those previously reported since we are now not including transformers owned by customers.

(3) In October 2016, Codensa merged with its subsidiaries DECSA and Cundinamarca, with Codensa continuing as the surviving company. Figures for 2016 includes DECSA and Cundinamarca.

Insurance

Both our electricity generation and distribution facilities are insured against damage due to natural disasters such as earthquakes, fires, floods, other acts of god (but not for droughts, which are not considered force 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 that the risk of the previously described events resulting in a material adverse effect on our facilities is remote. Claims under our 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 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.

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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$ 669.47 per U.S. dollar, the U.S. dollar Observed Exchange Rate as of December 31, 2016. Budgeted amounts include connecting lines that could eventually be owned by third parties and paid as tolls, unless otherwise indicated.

Projects under Construction

Peru. Huampani Hydroelectric Project Expansion

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

The environmental permit for the project was granted in August 2016 and the Pre-operativity Study (“EPO” in its Spanish acronym) was approved by COES in September 2016.

In September 2016, we assigned the water to wire contract, which is a package simplifying the planning and development of a site given that one vendor oversees most of the equipment supply to a consortium. The contract was between the consortium and our subsidiary Enel Generación Perú and became effective in November 2016. Currently, the consortium is developing a detailed engineering plan of the civil project and the design for electromechanical equipment, which are expected to be finalized within the first half of 2017.

Construction is expected to start in June 2017 and reach full production by the end of 2017. This project is being financed primarily by internally generated funds. The estimated total investment is Ch$ 2,257.7 million, of which Ch$ 303.3 million was accrued as of December 31, 2016.

Projects Under Development

We continuously analyze different growth opportunities in the countries in which we participate. We study and assess our project portfolio, focusing recently on constructing smaller, less environmentally 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. An additional focus will be placed on the development of renewable energy technologies. In the thermal generation business, we seek new opportunities, either by building new greenfield projects or by modernizing existing brownfield assets and improving (e.g. operational and / or environmental) the performance of such assets. The expected start-up for each project is assessed and is defined based on the commercial opportunities and our financing capacity to fund these projects. The most relevant projects in the pipeline are as follows:

Generation Business

Colombia. Termozipa Thermoelectric Power Plant Improvements

Termozipa is a coal-fired power plant of our subsidiary Emgesa, located about 40 km from Bogotá, Colombia. It consists of four units with a total installed capacity of 336 MW that are supplied with coal from local mines. The power plant started commercial operations in 1964 with one unit and added the rest by 1984.

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

The environmental upgrade aims to achieve the best environmental standards for gas emissions among coal-fired power plants in Latin America by reducing the following targets: Nitrogen oxide (NO_x) emissions to less than 330 mg/Nm³ (milligrams per cubic meter); Sulfur dioxide (SO₂) emissions to less than 400 mg/Nm³ and particulate emissions to less than 35 mg/Nm³.

The improvements as a part of the life extension project started at the end of 2016 and the main improvements are expected to be completed in 2017 with the goal of achieving new emissions regime standards for all units by 2020. This project is being financed by internally generated funds with an estimated total investment of Ch$ 79.7 billion, of which Ch$ 6.3 billion was accrued as of December 31, 2016.

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Argentina. Costanera New Combine Cycle Unit

In the context of the regulatory changes implemented by the Argentine government and the series of tenders that have been made and are expected to continue to carry out new energy investments, we are analyzing the possible installation of a new combined cycle in Costanera. The intent is to compete for electric power contracts through tenders offered by the Ministry of Energy and Mining. The process started in the fourth quarter of 2016 when the government asked for preliminary indications of interest in the submission of projects to such process. The tenders for new combined-cycle units are expected for 2017.

The project would consist of the installation of a combined-cycle unit with an installed capacity of up to 450 MW connected to the 220 kV and 132 kV bars of the existing Costanera substation. The combined-cycle unit could operate either with natural gas, as the preferable fuel, or if unavailable, with diesel.

We are currently analyzing various technical configurations, using different powertrains. In November 2016, we started the bidding process for the main project. The studies necessary to obtain the environmental permits and the connection to the electricity grid were finished last year, and in December 2016, we sent the results of the studies to the respective authorities.

The construction period is estimated to extend 32 months, depending on the technical configuration chosen. The commissioning date of the new unit is estimated to be in 2020.

This project would be financed by internally generated funds and with external debt in an initial structure of approximately 30%-70%, respectively. The estimated total investment is in the range of Ch$ 168,526 million and Ch$ 252,789 million, depending on the type and size of the project that is finally chosen. As of December 31, 2016, Ch$ 30.9 million has been accrued.

Distribution Business

Argentina

In 2016, Edesur invested Ch$ 84 billion to satisfy the growth in demand and improve its quality of service. These investments included extension works for the Sarandí, Gerli, Quilmes and Santa Rita substations, completion of the extension of Caballito substation, renewal of the trims 648-649 and change of power in Alberdi substation, 190 km of expansion in medium and low voltage networks, renovation of 54 km of medium and low voltage electrical networks, 21 new medium / low voltage transformation centers, 150 new processing centers, 36 new well chambers in Buenos Aires (distributed in the following districts: Villa del Parque, Villa Santa Rita, Villa Gral. Miter, Villa Crespo, Villa Devoto, Flores, Forest, Mataderos, Liniers, Balvanera, Almagro, Boedo, Centenario Park and Villa Soldati), improvement in processing centers to avoid water intake, and mechanical reinforcement in aerial medium voltage lines to withstand storms.

In 2016, Edesur implemented the “2015-2016 Summer Plan” (from December 2015 to March 2016) comprised of a contingency plan for coping with the extreme climate conditions caused by “El Niño” under a strong intensity level. This plan 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. Between January to March of 2016, we kept a facility of 60 electric mobile generation units (“UGEMs” in its Spanish acronym), which are transportable motor-generators located at critical points, to be able to generate energy at a moment’s notice in areas where the medium voltage network was overloaded, reducing the demand on the network at its most exposed points and thus saving those cables from destruction due to an overload. There were 84 units used in the previous period.

For the 2016 winter period, adjustments were made and actions were reinforced, intensifying the monitoring of the climatic variables to guarantee the stability of the electrical system and the continuity of supply.

Brazil

In 2016, Ampla invested a total of Ch$ 178.7 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$ 104.1 billion targeted at satisfying network and connection needs of clients and to support the recent sustained growth in demand in the State of Ceará, including projects to increase the capacity for transporting energy through transmission lines called “load increase projects.”

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Colombia

In 2016, Codensa invested Ch$ 143 billion, of which Ch$ 93 billion was used for the expansion mainly focused on connections to new clients and networks to improve service quality. In addition, Ch$ 50 billion was invested in projects to ensure the sustainability of the distribution business, meet load increases, comply with legal requirements, provide corrective maintenance, improve public lighting infrastructure, and invest in systems and communications.

Peru

In 2016, Enel Distribución Perú invested Ch$ 83 billion, representing a decrease of 15% in comparison to 2015. The most important investments were the extension and strengthening of medium and low voltage networks (Ch$ 44 billion), the extension of capacity of transformation substations and transmission lines including works for the new Malvinas, Philadelphia and Comas substations (Ch$ 20 billion), the improvement in public lighting infrastructure (Ch$ 1 billion) and other investments focused on reducing commercial losses (Ch$ 2 billion).

Major Encumbrances

Costanera’s supplier debt with Mitsubishi Corporation (“MC”) relates 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$ 7.2 billion as of December 31, 2016.

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 requirements of the international markets.

NCRE plants 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.

Enel, our ultimate controlling shareholder, announced in October 2015 that it will no longer build coal power plants because it considers the technology to be counterproductive to its goal of being carbon neutral by 2050. Closures of existing coal power plants are scheduled at the end of their life cycles. The lost capacity will be substituted with more environmentally friendly types of generation, focusing on NCRE.

Our Callahuanca hydroelectric power station (80.2 MW in operation since 1938) is an NCRE facility that has contributed clean and renewable energy to the Peruvian national grid. 

In addition, we are expanding the Huampani hydroelectric power plant in Peru (see above), which indirectly will avoid CO₂ emissions by displacing the operation of thermal units and implementing improvements to the thermal power plant Termozipa in Colombia (see above), which aims to achieve the best environmental standards for gas emissions among coal-fired power plants in Latin America by reducing NO_x, SO₂ and particulate emissions. In Argentina, during the first quarter of 2016, Costanera carried out some works on the gas turbine of its combined cycle in the Buenos Aires power plant. The work mainly injected water to the combustion chamber through the burners for the purpose of reducing NO_x emissions during the burning of liquid fuel (oil gas). As a result, we have reduced NO_x emissions by around 75% in comparison to the initial value.

Item 4A.Unresolved Staff Comments

None

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, 2016 and 2015 and for the three years ended December 31, 2016, have been prepared in accordance with IFRS, as issued by the IASB.

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

We are an electricity company headquartered in Chile that owns and operates generation, transmission and distribution companies in Argentina, Brazil, Colombia and Peru. 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 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, and with the risk profiles of our businesses within the generation and transmission business and distribution business, in order to mitigate adverse impacts that may affect our consolidated operating results. The impact of these factors on us, for the years covered by this Report, is discussed below.

We directly hold 48.5% and 48.4% of the equity interests and 56.4% and 57.1% of the voting shares of Emgesa and Codensa respectively. We exercise control over Emgesa and Codensa through shareholder agreements with Empresa de Energía de Bogotá S.A., which owns the remaining equity interests of both entities. We have the right to appoint a majority of Emgesa’s and Codensa’s Board members and, therefore, we consolidate Emgesa and Codensa in our consolidated financial statements.

On October 1, 2016, DECSA and EEC merged with and into Codensa our Colombian subsidiary.  Before the merger, DECSA and EEC were treated as joint ventures. The effects of this transaction on our consolidated financial statements as of December 31, 2016 are described in Note 6 to our consolidated financial statements.

a. Generation and Transmission Business

Our electricity generation and transmission business is conducted in Argentina through Costanera, El Chocón and Dock Sud, in Brazil through Cachoeira Dourada and Fortaleza, in Colombia through Emgesa, and in Peru through Enel Generación Perú and Enel Generación Piura. 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, 2016, 2015 and 2014 was 11,014 MW, 10,933 MW and 10,498 MW, respectively. In those years, our hydroelectric installed capacity represented 53.1%, 52.9% and 51.1% of our total installed capacity, respectively. See “Item 4. Information on the Company – D. Property, Plants and Equipment.”

Our hydroelectric generation was 22,250 GWh, 22,171 GWh and 22,439 GWh in 2016, 2015 and 2014, respectively. Our hydroelectric generation in 2016 was 0.4% higher than in 2015 mainly due to better hydrological conditions in Brazil and Colombia, partially offset by less favorable 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 the summer months, from November through May, and it is lightest during the winter. These hydrological conditions prevail in southern Brazil at the Paranaiba River at the Parana basin, where the 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 pattern is characterized by two rainy periods separated by a drier season, in the Andean region and in the center of the country, the most populated area and the center of economic activity, where all our hydroelectric plants, except the Guavio plant, are located. The second pattern is characterized by a rainy season followed by a drier season, in the Orinoquia region (eastern part of the country), where our largest hydroelectric plant, Guavio (1,263 MW), is located, and where hydrological conditions are influenced by the Amazon River.

Hydrological conditions in Peru also vary significantly depending on the location. The coast, which concentrates most of the population and economic activity, typically has less rainfall than the rest of the country. In the Andean mountains, rainfall is most abundant from 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.

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For purposes of discussing the impact of hydrological conditions on our business, we generally categorize our hydrological conditions into either 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.

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 reservoir water, 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 tariff or remuneration scheme and no energy and commodity trading. The remuneration scheme defines the regulated remuneration of generation companies, which provides a remuneration for fixed and variable costs plus additional remuneration.  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 2016, El Chocón’s generation decreased compared to 2015 due to lower hydrological levels of the Limay River, where our plants are located, because of less accumulated precipitation during the winter months. 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 Limay River. 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 of their contracted sales. In 2016, hydrological conditions were better in most of the country compared to previous years, which was reflected through lower prices in the spot market, and most of the hydroelectric generators were able to cover the assured energy, or maximum firm energy, which is the electricity that a hydroelectric generation plant is able to deliver on a continual basis during a year, with poor hydrological conditions for the long-term and at lower prices.  In 2015 and 2014, droughts affected all hydroelectric generators that participated in the MRE, and the overall hydroelectric generation system was not able to cover the assured energy. Fortaleza is a thermal plant, and its results depend mainly on its thermal generation, its generation costs, energy purchase costs and its commercial policy.

In Colombia, hydrological conditions in 2016 were more favorable than in 2015, although both years were below the historical averages. The first half of 2016 and all of 2015 were influenced by El Niño phenomenon that resulted in drought conditions for the whole system and very high spot prices.  However, hydrological conditions affecting our Guavio hydroelectric plant were better than the historical average, and the commissioning of El Quimbo hydroelectric power plant in November 2015 allowed Emgesa to compensate for lower hydroelectric generation in its other hydroelectric plants affected by the drought.

In Peru, hydrological conditions in 2016 were worse than the historical average. In addition, a slowing economic growth rate and delays in mining projects resulted in an electricity oversupply resulting in lower sale prices while operating costs increased due to the drought that was more severe in 2016 than in 2015 and 2014. Enel Generación Piura is a thermal plant, and its results depend mainly on its generation, generation costs, energy purchase costs and its commercial policy.

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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 Enel Distribución Perú. For the year ended December 31, 2016, electricity sales increased slightly by 0.6% compared to 2015, totaling 62,716 GWh. Currently, our distributors serve important South American cities, providing electricity to over 14 million customers. These companies face growing electricity demand, partly because of demographic growth and partly because of higher consumption, which requires 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, 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, improving our collectability indices and our efficiency. 

c. Selective Regulatory Developments

The regulatory framework governing our businesses in the countries in which we operate has a material effect on our operating results. In particular, regulators set (i) energy prices in the generation business, taking into consideration factors such as fuel costs, reservoir levels, exchange rates, future investments in installed capacity and demand growth, and (ii) distribution tariffs taking into account the costs of energy purchases paid by distribution companies (which distribution companies pass on to their customers) and the Value Added from Distribution, all of which are intended to reflect investment and operating costs incurred by distribution and generation companies and to allow our companies to earn a regulated level of return on their investments and guarantee service quality and reliability. The earnings of our electricity subsidiaries are determined to a large degree by regulators, mainly through the tariff setting process. In Argentina, the Argentine Secretary of Energy published Resolution. 22/2016, which temporarily updated the tariff or the remuneration scheme for generation companies beginning in February 2017.  The fixed cost remuneration increased by 70% and 120% for thermal and hydroelectric generators respectively, the variable cost remuneration increased by 40% for both thermal and hydroelectric generators and the non-recurrent maintenance remuneration increased by 60% and 25% for thermal and hydroelectric generators respectively.

In general, our distribution companies are subject to annual tariff adjustments and integral tariff setting processes, or tariff reviews, carried out according to calendars defined by the regulators in each country. For example, in Brazil, the next integral tariff setting process for Coelce is expected in 2019, but Ampla negotiated the timing of its tariff review that will be in place in 2018. In Colombia, Codensa’s integral tariff setting process is currently in progress and expected to conclude in 2017. Enel Distribution Perú’s tariff is expected to be reviewed in 2018.  Each of these reviews is unique and presents challenges, since tariff reviews seek to capture distribution efficiencies and economies of scale based on economic growth.

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

d. Economic Conditions

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

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.

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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, 2016, our consolidated debt totaled Ch$ 2,884 billion, of which 22.1% was denominated in U.S. dollars, 46.8% in Colombian pesos, 19.5% in Brazilian reais, 10.8% in Peruvian soles, 0.8% in Chilean pesos (including the Chilean UF, which is inflation-indexed), and none in Argentine pesos.

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

	Local Currency U.S. Dollar Exchange Rates
	2016				2015				2014
	Average		Year End		Average		Year End		Average		Year End
Argentina (Argentine pesos per U.S. dollar)		14.76		15.89		9.25		13.04		8.11		8.55
Brazil (Brazilian reais per U.S. dollar)		3.48		3.26		3.34		3.90		2.35		2.66
Colombia (Colombian pesos per U.S. dollar)		3,050.79		3,001		2,748		3,149		1,997		2,392
Peru (Peruvian soles per U.S. dollar)		3.37		3.36		3.18		3.41		2.84		2.99
Chile (Chilean pesos per U.S. dollar)		676.19		669.47		654.66		710.16		570.40		606.75

Sources: Central banks of each country.

For the year ended December 31, 2016, our revenues were Ch$ 5,197 billion or US$ 7.7 billion, of which 36.2% was generated in Brazil, 29.5% in Colombia, 17.4% in Peru and 16.7% 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)
	2016 ThCh$			2015 ThCh$			2014 ThCh$
Argentina		(60,390,257	)		(77,204,771	)		(3,627,084	)
Colombia		4,500,774			(160,522,082	)		(120,301,154	)
Brazil		246,759,422			(428,619,742	)		38,871,966
Peru		(45,987,411	)		23,681,916			67,649,223
Chile		421,576			(1,872,994	)		21,777,698
Total		145,304,104			(644,537,673	)		4,370,648

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, (iii) equity remains at the historical exchange rate from the date of acquisition or contribution, and (iv) for retained earnings,  the average exchange rate at the date of origination is used.

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$) Exchange Rates
	2016				2015				2014
	Average		Year End		Average		Year End		Average		Year End
Argentina (Argentine pesos per Ch$)		0.02183		0.02374		0.01412		0.01824		0.01423		0.01394
Brazil (Brazilian reais per Ch$)		0.00515		0.00487		0.00509		0.00558		0.00412		0.00437
Colombia (Colombian pesos per Ch$)		4.51174		4.48222		4.19703		4.47257		3.50421		3.92279
Peru (Peruvian soles per Ch$)		0.00499		0.00502		0.00486		0.00480		0.00498		0.00493

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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 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 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 2016 versus 2015 and 2015 versus 2014 for the closing and average local currencies per Chilean peso:

	Appreciation/(Devaluation) per Chilean Peso (in %)
	2016/2015						2015/2014
	Average			Year End			Average			Year End
Argentine pesos		(35.3	)		(23.2	)		0.8			(23.6	)
Brazilian reais		(1.1	)		14.7			(19.1	)		(21.7	)
Colombian pesos		(7.0	)		(0.5	)		(16.5	)		(12.3	)
Peruvian soles		(2.6	)		(4.4	)		2.4			2.7

In the analysis of results of operations included below, when the impacts of the appreciation or devaluation are significant, they are disclosed and explained below.

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 in Argentina, or in 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 and Capital Resources.”

Our Argentine operations do not affect our consolidated liquidity. Our Argentine cash and cash equivalents were Ch$ 145.3 billion as of December 31, 2016, which represents 8.1% of our total cash and cash equivalents. Of the total Argentine cash and cash equivalents, 98.4% is denominated in local currency, and the remaining 1.6% is denominated in U.S. dollars. Our Argentine debt was Ch$ 35.3 billion as of December 31, 2016, representing 1.2% of our total debt. Of the total Argentine debt, 2.4% is denominated in local currency, and the remaining 97.6% 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 35.3% increase in the amount in Chilean pesos in 2016 compared to 2015.

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 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.

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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 based on the application of reasonable growth rates, between 3.2% and 11.1%, and a unique growth rate for the entire forecasted period that is in line with the average long-term growth rates for the electricity sector.

These cash flows are discounted at a given pre-tax rate in order to calculate their present value. This rate reflects the cost of capital of the business and the geographical area in which the business is conducted. The discount rate is calculated taking into account the current time value of money and the risk premiums generally used by market participants for the specific business activity and the country involved.

The pre-tax nominal discount rates applied in 2016, 2015 and 2014 are as follows:

		Year ended December 31,
		2016				2015				2014
Country	Currency	Minimum		Maximum		Minimum		Maximum		Minimum		Maximum
		(in %)
Argentina	Argentine peso		29.8		40.6		32.7		39.4		23.3		38.9
Brazil	Brazilian reais		11.0		21.8		11.1		21.1		9.7		22.7
Colombia	Colombian peso		10.0		10.7		8.5		15.1		8.0		13.3
Peru	Peruvian sol		7.2		11.5		7.3		13.5		7.3		14.3

If the recoverable amount is less than the net carrying amount of the cash generating unit, the corresponding impairment loss provision is recognized for the difference, and charged to “Reversal of impairment loss (impairment loss) recognized in profit or loss” in the consolidated statement of comprehensive income.

Impairment losses recognized for an asset in prior periods are reversed when their estimated recoverable amount changes, increasing the asset’s value with a credit to earnings, limited to the asset’s carrying amount if no adjustment had occurred. In the case of goodwill, any adjustments made are not reversible.

Litigation and Contingencies

We are currently involved in certain legal and tax proceedings. As discussed in Note 22 of the Notes to our consolidated financial statements as of December 31, 2016, we have estimated the probable outflows of resources for resolving these claims to be Ch$ 266 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.

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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$ 46.9 billion, Ch$ 32.6 billion and Ch$ 46.8 billion as of December 31, 2016, 2015 and 2014, 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$ 55.1 billion, Ch$ 38.0 billion and Ch$ 56.7 billion as of December 31, 2016, 2015 and 2014, respectively.

Change in Functional and Reporting Currency for Financial Reporting

We reviewed our functional currency in accordance with IFRS. We concluded that as a result of the 2016 Reorganization, the economic environment in which Enel Américas operates changed and the cash inflows and outflows are now primarily denominated in U.S. dollars. Therefore, we changed our functional and reporting currency from Chilean Pesos to U.S. dollars as of January 1, 2017.  This conclusion was discussed and approved by the Board of Directors at its meeting held on October 28, 2016 and approved by the ESM on April 27, 2017.  

See Note 38 to the Consolidated Financial Statements.

Recent Accounting Pronouncements

Please see Note 2.2 of the Notes to our consolidated financial statements for additional information regarding recent accounting pronouncements.

2. Analysis of Results of Operations for the Years Ended December 31, 2016 and 2015.

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, 2016 and 2015:

	Electricity sales during the year ended December 31,
	2016		2015		Change			Change
	(in GWh)							(in %)
Costanera (Argentina)		5,713		8,168		(2,455	)		(30.1	)
El Chocón (Argentina)		2,574		3,801		(1,226	)		(32.3	)
Dock Sud (Argentina)		5,025		3,802		1,223			32.2
Cachoeira Dourada (Brazil)		6,399		3,215		3,185			99.1
Fortaleza (Brazil)		3,049		3,326		(277	)		(8.3	)
Emgesa (Colombia)		18,015		16,886		1,129			6.7
Enel Generación Perú (Peru)		9,091		8,633		458			5.3
Enel Generación Piura (Peru)		709		650		58			9.0
Total		50,575		48,480		2,094			4.3

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Distribution Business

The following table sets forth the electricity sales of our subsidiaries, by country, and their corresponding variations for the years ended December 31, 2016 and 2015:

	Electricity sales during the year ended December 31,
	2016		2015		Change			Change
	(in GWh)							'(in %)
Edesur (Argentina)		18,493		18,492		1			0.0
Ampla (Brazil)		11,181		11,096		85			0.8
Coelce (Brazil)		11,628		11,229		400			3.6
Codensa (Colombia)		13,632		13,946		(314	)		(2.3	)
Enel Distribución Perú (Peru)		7,782		7,624		158			2.1
Total		62,716		62,387		329			0.5

The following table sets forth the revenues from continuing operations, by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2016 and 2015:

	Year ended December 31,
	2016			2015			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business in Argentina		207,605			212,136			(4,531	)		(2.1	)
Costanera		92,633			100,857			(8,224	)		(8.2	)
El Chocón		28,241			40,005			(11,763	)		(29.4	)
Dock Sud		86,363			69,963			16,400			23.4
Other		368			1,312			(944	)		(72.0	)
Generation and Transmission Business in Brazil		387,094			305,830			81,264			26.6
Cachoeira Dourada		192,912			91,563			101,349		n.a.
Fortaleza		159,477			159,052			425			0.3
CIEN		52,179			55,534			(3,355	)		(6.0	)
Other		(17,473	)		(319	)		(17,154	)	n.a.
Generation and Transmission Business in Colombia		778,880			778,768			112			0.0
Emgesa		778,880			778,768			112			0.0
Generation and Transmission Business in Peru		458,974			437,887			21,087			4.8
Enel Generación Perú		396,807			382,877			13,930			3.6
Enel Generación Piura		65,145			58,093			7,053			12.1
Other		(2,978	)		(3,082	)		104			(3.4	)
Other Generation and Transmission Business reportable segment		—			141			(141	)		(100.0	)
Total Generation and Transmission Business reportable segment		1,832,554			1,734,762			97,792			5.6
Distribution Business in Argentina
Edesur		664,100			607,345			56,755			9.3
Distribution Business in Brazil		1,684,139			1,836,864			(152,725	)		(8.3	)
Ampla		879,499			1,026,680			(147,181	)		(14.3	)
Coelce		804,640			810,184			(5,544	)		(0.7	)
Distribution Business in Colombia		923,912			884,468			39,444			4.5
Codensa		923,912			884,467			39,445			4.5
Distribution Business in Peru		585,196			562,046			23,150			4.1
Enel Distribución Perú		585,196			562,046			23,150			4.1
Total Distribution Business reportable segment		3,857,347			3,890,723			(33,376	)		(0.9	)
Less: consolidation adjustments and non-core activities		(492,615	)		(324,045	)		(168,570	)		52.0
Total Revenues		5,197,286			5,301,440			(104,154	)		(2.0	)

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Generation and Transmission Business: Revenues from Continuing Operations

In Argentina, revenues from Costanera decreased by Ch$ 8.2 billion, or 8.2% in 2016, mainly due to the devaluation of the Argentine peso against the Chilean peso that resulted in lower revenues of Ch$ 35.5 billion. This decrease was partially offset by a Ch$ 25.7 billion increase related to combined-cycle availability contracts with the Argentine Secretary of Energy and a Ch$ 1.9 billion increase due to higher energy sales. The higher energy sales are attributable to a Ch$ 3.5 billion increase due to higher tariffs as a result of Resolution 22/2016, partially offset by a Ch$ 1.6 billion decrease due to lower energy sales of 2,455 GWh or 30.1%, as result of plant stoppages for maintenance.

Revenues from El Chocón decreased by Ch$ 11.8 billion, or 29.4%, in 2016, mainly due to the devaluation of the Argentine peso against the Chilean peso that resulted in lower revenues of Ch$ 14.1 billion. This decrease was partially offset by a Ch$ 1.4 billion increase due to higher energy sales attributable to a Ch$ 9.4 billion increase due to higher tariffs as a result of Resolution 22/2016, partially offset by a Ch$ 8.0 billion decrease attributable to lower energy sales of 1,227 GWh, or 32.3%, due to lower hydroelectric generation because of the drought.

Revenues from Dock Sud increased by Ch$ 16.4 billion, or 23.4%, in 2016, principally due to a Ch$ 32.2 billion increase attributable to higher energy sales of 1,223 GWh, or 32.3%, and a Ch$ 8.9 billion increase attributable to higher tariffs due to increases to tariffs as a result of Resolution 22/2016. These increases were partially offset by lower revenues of Ch$ 24.7 billion due to the devaluation of the Argentine peso against the Chilean peso.

In Brazil, revenues from Cachoeira Dourada increased by Ch$ 101.3 billion, or 110.7%, in 2016, mainly due to a Ch$ 109.2 billion increase attributable to higher energy sales of 3,185 GWh, or 99.1%, to predominantly unregulated customers, which was partially offset by a Ch$ 6.9 billion decrease due to lower prices as a result of improved hydrological conditions, and lower revenues of Ch$ 1.0 billion due to the devaluation of the Brazilian reais against the Chilean peso.

Revenues from Fortaleza remained relatively stable compared to 2015, increasing by Ch $0.5 billion, or 0.3%, in 2016, despite lower electricity generation. The increase in revenue was attributable to a Ch$ 11.4 billion increase in state industrial incentives and improved commodity hedge results of Ch$ 3.6 billion, partially offset by a Ch $7.2 billion decrease in revenues due to lower energy sales of 3,184 MW, or 8.3%, a Ch $5.7 billion decrease due to lower average sale prices as a result of improved hydrological conditions and a Ch$ 1.8 billion loss due to the devaluation of the Brazilian reais against the Chilean peso.

Revenues from CIEN decreased by Ch$ 3.4 billion, or 6.0%, in 2016, mainly due to lower regulatory revenues of Ch$ 2.7 billion (Allowed Annual Revenue or “RAP” in its Portuguese acronym) and lower revenues of Ch$ 0.7 billion due to the devaluation of the Brazilian reais against the Chilean peso.

In Colombia, revenues from Emgesa remained relatively stable compared to 2015, increasing by Ch$ 0.1 billion, or 0.01%, in 2016, despite higher generation, mainly due to the commencing of operations of El Quimbo hydroelectric plant in November 2015. Energy sale revenues increased by Ch$ 53.5 billion mainly due to a Ch$ 47.7 billion increase attributable to energy sales of 1,129 MW, or 6.7%, partially offset by a Ch$ 54.4 billion loss due to the devaluation of the Colombian peso against the Chilean peso.

In Peru, revenues from Enel Generación Perú increased by Ch$ 13.9 billion, or 3.6%, in 2016. This increase in revenues is mainly due to a Ch$ 16.0 billion increase in tolls attributable to new unregulated customers and a Ch$ 9.5 billion from higher energy sales of 458 MW, or 5.3%, partially offset by lower revenues of  Ch$ 9.6 billion due to the devaluation of the Peruvian sol against the Chilean peso, a Ch$ 1.2  billion decrease in revenues from lower average sale prices and lower revenues of Ch$ 1.0 billion due to non-recurrent revenue as a result of an insurance reimbursement recorded in 2015.

Revenues from Enel Generación Piura increased by Ch$ 7.1 billion, or 12.1%, in 2016, mainly due to a Ch$ 3.8 billion increase attributable to higher energy sales of 58 MW, or 9.0%, a Ch$ 3.6 billion increase of LNG sales due to the drought and a Ch$ 1.2 billion increase due to higher average sale prices, partially offset by lower revenues of Ch$ 1.5 billion due to the devaluation of the Peruvian sol against the Chilean peso.

Distribution Business: Revenues from Continuing Operations

In Argentina, revenues from Edesur increased by Ch$ 56.8 billion, or 9.3%, in 2016, mainly due to a Ch$ 419.7 billion increase attributable to higher energy revenues related to Edesur’s new tariffs in effect since February 1, 2016, a Ch$30.4 billion increase due to toll services and a Ch$5.6 billion increase due to surcharges for energy sales. These increases were partially offset by a Ch$ 184.0 billion decrease due to the repeal of certain resolutions that until 2015 permitted additional income to be recorded as

102

finance operating costs and investment costs, and a Ch$ 214.5 billion decrease due to the devaluation of the Argentine peso against the Chilean peso.

In Brazil, revenues from Ampla decreased by Ch$ 147.2 billion, or 14.3%, in 2016, principally due to a Ch$193.2 billion decrease in regulatory revenues from tariff adjustments in connection with pass-through cost corrections and lower revenues of Ch$11.5 billion due to the devaluation of the Brazilian reais against the Chilean peso, which were partially offset by a Ch$ 23.8 billion increase in service concession arrangements, a Ch$ 14.4 billion increase due to an average tariff adjustment and a Ch$7.5 billion increase due to electrical equipment rentals.

Revenues from Coelce decreased by Ch$ 5.5 billion, or 0.7%, in 2016, mainly due to a Ch$ 77.7 billion decrease in regulatory revenues due to tariff adjustments from pass-through cost corrections and a Ch$24.1 billion decrease in revenues from subsidies for low income consumers, partially offset by a Ch$ 71.0 billion increase due to an average tariff adjustment, a Ch$ 18.2 billion increase due to service concession arrangements and a Ch$ 6.5 billion increase in revenues due to electrical equipment rentals. 

In Colombia, revenues from Codensa increased by Ch$ 39.5 billion, or 4.5%, in 2016, mainly due to a Ch$ 670.3 billion increase from higher tariffs, which was partially offset by a Ch$ 580.3 billion decrease from 2.3% in lower physical energy sales predominantly related to lower market demand because of governmental programs designed to encourage efficient electricity consumption and a Ch$ 61.7 billion decrease due to the devaluation of the Colombian peso against the Chilean peso.

In Peru, revenues from Enel Distribución Perú increased by Ch$ 23.2 billion, or 4.1%, in 2016, mainly due to a Ch$ 18.9 billion increase from 2.1% higher physical energy sales and a Ch$ 13.9 billion increase from higher sale prices due to regulated tariff adjustments. This increase was partially offset by a Ch$ 14.4 billion decrease due the devaluation of the Peruvian sol against 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.

The following table sets forth consolidated operating costs in Chilean pesos for the years ended December 31, 2016 and 2015:

	Year ended December 31,
	2016		2015		Change			Change
	(in millions of Ch$)							(in %)
Energy purchases		1,651,607		1,885,916		(234,310	)		(12.4	)
Fuel consumption		244,886		258,114		(13,228	)		(5.1	)
Transportation costs		266,484		245,813		20,671			8.4
Other raw materials and combustibles		482,121		387,358		94,764			24.5
Other expenses(1)		552,701		488,529		64,172			13.1
Employee benefit expense and other(1)		356,117		420,597		(64,480	)		(15.3	)
Depreciation, amortization and impairment losses(1)		426,214		360,354		65,860			18.3
Total Operating Cost from Continuing Operations		3,980,130		4,046,681		(66,551	)		(1.6	)

(1) Corresponds to selling and administration expenses

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The following table sets forth our total operating costs (excluding selling and administrative expenses) from continuing operations by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2016 and 2015:

	Year ended December 31,
	2016			2015			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business in Argentina		59,539			50,332			9,207			18.3
Costanera		5,156			4,598			558			12.1
El Chocón		3,210			4,574			(1,364	)		(29.8	)
Dock Sud		52,965			43,266			9,699			22.4
Other		(1,793	)		(2,106	)		313			(14.9	)
Generation and Transmission Business in Brazil		181,654			131,431			50,223			38.2
Cachoeira Dourada		100,796			17,396			83,400		n.a
Fortaleza		96,350			111,229			(14,879	)		(13.4	)
CIEN		1,981			3,126			(1,145	)		(36.6	)
Other		(17,474	)		(319	)		(17,154	)	n.a
Generation and Transmission Business in Colombia		293,212			321,665			(28,453	)		(8.8	)
Emgesa		293,212			321,665			(28,453	)		(8.8	)
Generation and Transmission Business in Peru		234,674			174,513			60,161			34.5
Enel Generación Perú		209,323			151,046			58,277			38.6
Enel Generación Piura		28,326			26,124			2,202			8.4
Other		(2,976	)		(2,657	)		(319	)		12.0
Total Generation and Transmission Business reportable segment		769,078			677,941			91,137			13.4
Distribution Business in Argentina		303,352			157,387			145,965			92.7
Edesur		303,352			157,387			145,965			92.7
Distribution Business in Brazil		1,142,264			1,386,391			(244,127	)		(17.6	)
Ampla		605,121			804,701			(199,581	)		(24.8	)
Coelce		537,143			581,689			(44,546	)		(7.7	)
Distribution Business in Colombia		532,282			500,571			31,711			6.3
Codensa		532,282			500,571			31,711			6.3
Distribution Business in Peru		395,536			379,015			16,521			4.4
Enel Distribución Perú		395,536			379,015			16,521			4.4
Total Distribution Business reportable segment		2,373,434			2,423,364			(49,930	)		(2.1	)
Less: consolidation adjustments and non-core activities		(497,413	)		(324,103	)		(173,310	)		53.5
Total operating costs (excluding selling and administrative expenses)		2,645,099			2,777,202			(132,103	)		(4.8	)

Generation and Transmission Business: Operating Costs from Continuing Operations

In Argentina, operating costs of Costanera increased by Ch$ 0.6 billion, or 12.1%, in 2016, mainly attributable to a Ch$ 2.3 billion increase in fuel consumption in connection with scheduled maintenances, partially offset by a Ch$ 1.6 billion decrease in costs due to the devaluation of the Argentine peso against the Chilean peso.

Operating costs of El Chocón decreased by Ch$ 1.4 billion, or 29.8%, in 2016, mainly attributable to a Ch$ 1.6 billion decrease in costs due to the devaluation of the Argentine peso against the Chilean peso.

Operating costs of Dock Sud increased by Ch$ 9.7 billion, or 22.4%, in 2016, mainly due to a Ch$13.7 billion increase from higher gas consumption as a result of a 32.3% increase in physical energy generation and a Ch$ 8.7 billion increase in gas purchase prices related to Resolution 22/2016. These increases were partially offset by a Ch$ 13.3 billion decrease in costs due to the devaluation of the Argentine peso against the Chilean peso.

In Brazil, operating costs of Cachoeira Dourada increased by Ch$ 83.4 billion, or 479 %, in 2016, mainly due to a Ch$ 90.5 billion increase attributable to 272% higher physical energy purchases as a result of higher sales to unregulated customers, which was partially offset by a Ch$ 8.3 billion decrease due to lower purchase prices as a result of improved hydrological conditions in Brazil.

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Operating costs of Fortaleza decreased by Ch$ 14.9 billion, or 13.4%, in 2016, mainly due to a Ch$ 24.9 billion decrease in energy purchases as a result of lower prices due to improved hydrological conditions and a Ch$ 11.1 billion decrease in fuel consumption due to plant stoppages for maintenance. These decreases were partially offset by a Ch$ 16.7 billion increase attributable to 50% higher physical energy purchases related to the maintenance of the power plant and a Ch$ 5.6 billion increase in other miscellaneous and variable services costs related to the hedging of gas purchases.

Operating costs of CIEN decreased by Ch$ 1.2 billion, or 36.6 % in 2016, mainly due to a Ch$ 1.1 billion decrease in energy purchases.

In Colombia, operating costs of Emgesa decreased by Ch$ 28.5 billion, or 8.8%, in 2016, mainly due to a Ch$ 22.5 billion decrease in costs as a result of the devaluation of the Colombian peso against the Chilean peso and a Ch$ 12.2 billion decrease in energy purchases due to lower prices as a result of improved hydrological conditions. These decreases were partially offset by a Ch$ 11.9 billion increase in transportation costs due to higher toll prices as a result of inflation.  

In Peru, operating costs of Enel Generación Perú increased by Ch$ 57.9 billion, or 38.2%, in 2016, mainly due to a Ch$ 28.1 billion increase attributable to the recognition of a provision for legal claims and a Ch$ 19.9 billion increase in physical energy purchases in the spot market to supplement its own lower hydroelectric generation and higher physical sales to contracted customers.

Operating costs of Enel Generación Piura increased by Ch$ 2.2 billion, or 8.4%, in 2016, mainly due to a Ch$ 1.3 billion increase in fuel consumption costs attributable to the use of oil instead of gas due to the lack of availability of oil, and a Ch$ 1.1 billion increase in transportation costs due to tolls from an increase in customers.

Distribution Business: Operating Costs from Continuing Operations

In Argentina, operating costs of Edesur increased by Ch$ 145.9 billion, or 92.7%, in 2016, predominantly due to a Ch$ 163.2 billion increase due to higher purchase prices related to inflation adjustments and a Ch$ 34.6 billion increase in other miscellaneous variable and service costs because of service quality fines imposed by ENRE, partially offset by a Ch$ 55.6 billion decrease due to the devaluation of the Argentine peso against the Chilean peso.

In Brazil, operating costs of Ampla decreased by Ch$ 199.6 billion, or 24.8%, in 2016, mainly due to a Ch$ 158.0  billion  decrease as a result of a 1.7% decrease in physical energy purchases due to negative economic conditions and a Ch$ 58.0 billion decrease due to lower purchase prices attributable to improved hydrological conditions. These decreases were partially offset by a Ch$ 23.8 billion increase in other miscellaneous variable and services costs related to an increase in construction costs in connection with concession arrangements.

Operating costs of Coelce decreased by Ch$ 44.5 billion, or 7.6%, in 2016, mainly due to a Ch$ 72.8 billion decrease in average purchase prices attributable to improved hydrological conditions, partially offset by a Ch$ 15. 7 billion increase due to 2.2% higher physical energy purchases and a Ch$ 18.2 billion increase in other miscellaneous variable and services costs related to an increase in construction costs in connection with concession arrangements.

In Colombia, operating costs of Codensa increased by Ch$ 31.8 billion, or 6.3% in 2016, predominantly due to a Ch$ 21.3 billion increase due to higher energy purchases in the spot market and through contracts, a Ch$ 26.3 billion increase due to higher average purchase prices, and a Ch$ 18.1 billion increase due to higher toll prices, partially offset by a Ch$ 35.0 billion decrease in costs due to the devaluation of the Colombian peso against the Chilean peso.

In Peru, operating costs of Enel Distribución Perú increased by Ch$ 16.5 billion, or 4.3% in 2016, mainly attributable to a Ch$ 29.7 billion increase in energy purchases due to higher purchase contract prices, partially offset by a Ch$ 9.7 billion decrease in costs due to the devaluation of the Peruvian sol against the Chilean peso and a Ch$ 3.4 billion decrease in other miscellaneous variable and service costs due to reduced costs in other non-core businesses.

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.

105

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, 2016 and 2015:

	Year ended December 31,
	2016		2015
	(in %)
Selling and Administrative Expenses as a Percentage of Total Selling and  Administrative Expenses
Other expenses		41.4		38.5
Employee benefit expense and other		26.7		33.1
Depreciation, amortization and impairment losses		31.9		28.4
Total		100.0		100.0

The following table sets forth the selling and administrative expenses by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2016 and 2015:

	Year ended December 31,
	2016		2015			Change			Change
	(in millions of Ch$)								(in %)
Generation and Transmission Business in Argentina		86,583		110,595			(24,012	)		(21.7	)
Costanera		55,027		75,886			(20,859	)		(27.5	)
El Chocón		9,643		8,421			1,222			14.5
Dock Sud		20,466		23,388			(2,921	)		(12.5	)
Other		1,446		2,900			(1,454	)		(50.1	)
Generation and Transmission Business in Brazil		43,395		42,843			552			1.3
Cachoeira Dourada		12,962		12,195			768			6.3
Fortaleza		14,150		12,956			1,194			9.2
CIEN		16,198		18,089			(1,891	)		(10.5	)
Other		85		(397	)		481		n.a.
Generation and Transmission Business in Colombia		113,587		84,275			29,312			34.8
Emgesa		113,587		84,275			29,312			34.8
Generation and Transmission Business in Peru		108,973		106,048			2,925			2.8
Enel Generación Perú		96,370		91,718			4,652			5.1
Enel Generación Piura		12,602		14,305			(1,704	)		(11.9	)
Other		—		25			(25	)		(100.0	)
Other Generation and Transmission Business reportable segment		—		(1,637	)		1,637			(100.0	)
Total Generation and Transmission Business reportable segment		352,538		342,124			10,414			3.0
							-
Distribution Business in Argentina		265,119		346,182			(81,064	)		(23.4	)
Edesur		265,119		346,182			(81,064	)		(23.4	)
Distribution Business in Brazil		407,742		323,139			84,602			26.2
Ampla		247,208		195,556			51,652			26.4
Coelce		160,534		127,583			32,951			25.8
Distribution Business in Colombia		145,324		148,309			(2,985	)		(2.0	)
Codensa		145,324		148,309			(2,985	)		(2.0	)
Distribution Business in Peru		78,490		75,327			3,163			4.2
Enel Distribución Perú		78,490		75,327			3,163			4.2
Other Distribution Business reportable segment		—		1,383			(1,383	)		(100.0	)
Total Distribution Business reportable segment		896,675		894,341			2,334			0.3
Less: consolidation adjustments and non-core activities		85,818		33,015			52,803		n.a.
Total selling and administrative expenses		1,335,031		1,269,480			65,551			5.2

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Selling and administrative expenses from continuing operations increased by Ch$ 65.6 billion, or 5.2% in 2016 as compared to 2015. The main changes are explained below.

Generation and Transmission Business:

In Argentina, selling and administrative expenses of Costanera and Dock Sud decreased by Ch$ 24.0 billion in 2016, mainly due to the devaluation of the Argentine peso against the Chilean peso that led to lower costs of Ch$ 14.3 billion and Ch$ 2.2 billion respectively. El Chocón selling and administrative expenses increased by Ch$ 1.2 billion due to an increase of Ch$ 1.9 billion in other expenses, which was partially offset by a decrease of Ch$ 1.0 billion due to the devaluation of the Argentine peso against the Chilean peso.  

In Colombia, selling and administrative expenses of Emgesa increased by Ch$ 29.3 billion mostly due to a Ch$ 22.7 billion loss as a result of the allowance for uncollectible accounts recorded in 2016.

In Peru, selling and administrative expenses of Enel Generación Perú increased by Ch$ 4.7 billion in 2016, mainly due to an increase of Ch$ 13.7 billion related to the Curimbamba project write-off in June 2016, partially offset by a Ch$ 4.8 billion decrease in depreciation expenses due to the sale of transmission lines in 2016 and a Ch$ 4.7 billion decrease due to the reversal of the allowance for uncollectible accounts recognized in 2015 for the receivables from Cajamarquilla. Selling and administrative expenses of Enel Generación Piura decreased by Ch$ 1.7 billion principally due to a decrease of Ch$1.4 billion related to the VAT tax contingency recognized in 2015.

Distribution Business:

In Argentina, selling and administrative expenses of Edesur decreased by Ch$ 81.1 billion, mainly due to a Ch$ 117.5 billion decrease related to the devaluation of the Argentine peso against the Chilean peso, partially offset by an increase of Ch$ 30.9 billion in payroll expenses related to salary increases and severance payments, and an increase of Ch$ 6.9 billion in the allowance for uncollectible accounts.

In Brazil, selling and administrative expenses of Ampla increased by Ch$ 51.7 billion primarily due to a Ch$17.8 billion increase as a result of higher third-party maintenance service costs for lines and networks, a Ch$ 16.4 billion increase in the allowance for uncollectible accounts and a Ch$ 13.8 billion increase related to a write-off of assets.

Selling and administrative expenses of Coelce increased by Ch$ 33.0 billion mainly due to a Ch$ 19.3 billion increase in the allowance for uncollectible accounts, a Ch$ 9.5 billion increase related to a write-off of assets and a Ch$ 8.1 billion increase due to higher third-party maintenance service costs for lines and networks.

In Colombia, selling and administrative expenses of Codensa decreased by Ch$ 3.0 billion as compared to 2015, primarily due to the devaluation of the Colombian peso against the Chilean peso.

In Peru, selling and administrative expenses of Enel Distribución Perú increased by Ch$ 3.2 billion mainly due to a Ch$ 2.2 billion increase in other expenses related to contractor services.

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Operating Income from Continuing Operations

The following table sets forth our operating income from continuing operations by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2016 and 2015:

	Year ended December 31,
	2016			2015			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business in Argentina		61,484			51,209			10,275			20.1
Costanera		32,449			20,372			12,077			59.3
El Chocón		15,388			27,009			(11,621	)		(43.0	)
Dock Sud		12,932			3,309			9,622		n.a.
Other		715			518			197			38.1
Generation and Transmission Business in Brazil		162,044			131,556			30,488			23.2
Cachoeira Dourada		79,153			61,973			17,181			27.7
Fortaleza		48,976			34,867			14,109			40.5
CIEN		34,000			34,320			(319	)		(0.9	)
Other		(86	)		397			(482	)	n.a.
Generation and Transmission Business in Colombia		372,080			372,828			(748	)		(0.2	)
Emgesa		372,080			372,828			(748	)		(0.2	)
Generation and Transmission Business In Peru		115,328			157,326			(41,998	)		(26.7	)
Enel Generación Perú		91,111			139,689			(48,578	)		(34.8	)
Enel Generación Piura		24,217			17,663			6,554			37.1
Other		—			(26	)		26			(100.0	)
Other Generation and Transmission Business reportable segment		—			1,777			(1,777	)		(100.0	)
Total Generation and Transmission Business reportable segment		710,936			714,696			(3,760	)		(0.5	)
Distribution Business in Argentina		95,629			103,775			(8,146	)		(7.8	)
Edesur		95,629			103,775			(8,146	)		(7.8	)
Distribution Business in Brazil		134,132			127,334			6,798			5.3
Ampla		27,170			26,423			748			2.8
Coelce		106,962			100,911			6,051			6.0
Distribution Business in Colombia		246,306			235,587			10,719			4.5
Codensa		246,306			235,587			10,719			4.5
Distribution Business in Peru		111,170			107,705			3,465			3.2
Enel Distribución Perú		111,170			107,705			3,465			3.2
Other Distribution Business reportable segment		—			(1,383	)		1,383			(100.0	)
Total Distribution Business reportable segment		587,238			573,019			14,219			2.5
Less: consolidation adjustments and non-core activities		(81,019	)		(32,957	)		(48,062	)	n.a.
Total operating income		1,217,155			1,254,758			(37,604	)		(3.0	)

108

Generation and Transmission Business

Operating income in 2016 was slightly lower than in 2015 mainly due to Enel Generación Perú offsetting higher results recorded by our subsidiaries in Brazil and Argentina, while in Colombia, operating income was very similar during both periods.

In Argentina, a new remuneration scheme was applied as of February 2016 that led to higher operating income for our thermal plants Costanera and Dock Sud. The increase in operating income for Costanera was mainly due to its combined-cycle availability contracts and for Dock Sud its higher energy generation. El Chocón, a hydroelectric plant, experienced a decrease in operating income due to worsened hydrological conditions and the devaluation of the Argentine peso against the Chilean peso, which were not compensated by the new remuneration scheme.

In Brazil, Cachoeira Dourada sold more energy to non-regulated customers that bought from other generators at a lower price due to better hydrological conditions, increasing its operating income. Fortaleza improved operating income despite its lower physical sales mainly due to lower fuel consumption because of the stoppage of its thermal plants and lower energy costs.

In Colombia, Emgesa’s operating income increased due to slightly better hydrological conditions, especially in the second half of the year, coupled with the commissioning of El Quimbo, allowing a reduction in thermal generation and accompanying fuel purchases.  However, due to the devaluation of the Colombian peso against the Chilean peso, operating income in Chilean pesos in 2016 was very similar to 2015.

Enel Generación Perú decreased its operating income mainly due to both lower average sale prices, due to oversupply, as well as higher operating costs due to unfavorable hydrology and non-recurrent costs due to legal claims and project write-offs.  Enel Generation Piura improved its operating income due to higher thermal generation and sales.  

Distribution Business

Operating income increased by 2.5% in 2016 with respect to 2015, mainly due to annual tariff adjustments in most of the countries where our subsidiaries operate.

In Argentina, Edesur’s operating income was negatively affected by the devaluation of the Argentine peso against the Chilean peso, offsetting the positive results due to the temporal tariff applied since February 2016.

In Brazil, Coelce and Ampla improved their operating income mainly due to annual tariff adjustments and lower energy purchases mainly due to lower purchase prices attributable to improved hydrological conditions.

In Colombia, Codensa improved its operating income mainly due to annual tariff adjustments, despite a decrease in sales due to governmental programs to reduce consumption.

Enel Distribución Perú improved its operating income due to higher physical sales as a result of new customers that chose to be unregulated customers and annual tariff adjustments.

Other Results from Continuing Operations

The following table sets forth the other results from continuing operations for the years ended December 31, 2016 and 2015:

	Year ended December 31,
	2016			2015			Change			Change
	(in millions of Ch$)									(in %)
Financial results
Financial income		186,938			294,770			(107,833	)		(36.6	)
Financial costs		(522,801	)		(385,455	)		(137,346	)		35.6
Results from indexed assets and liabilities		(698	)		(9,266	)		8,568			(92.5	)
Net foreign currency exchange gains (losses)		39,851			128,238			(88,387	)		(68.9	)
Total		(296,711	)		28,287			(324,998	)	n.a.
Other
Other gains (losses)		8,209			(6,566	)		14,775		n.a.
Share of the profit of associates and joint ventures accounted for    using the equity method		1,830			3,333			(1,503	)		(45.1	)
Total		10,039			(3,233	)		13,272		n.a.
Total other results		(286,672	)		25,054			(311,726	)	n.a.

109

Financial Results from Continuing Operations

Our net total financial results in 2016 were a net loss of Ch$ 296.7 billion, while in 2015, we recorded a net gain of Ch$ 28.3 billion, mainly explained by:

▪ a decrease in financial income of Ch$ 107.8 billion in 2016 mainly due to a Ch$ 57.1 billion decrease in  non-recurring interest income, as compared to 2015, due to accounts receivables that accrued interest from the Vuelta de Obligado thermal plant according to the agreement with our subsidiaries El Chocón, Costanera and Dock Sud and a Ch$ 32.2 billion decrease in non-recurring financial income recorded, as compared to 2015, because of  the waiver of interest payments related to the debt of Edesur and Costanera with  CAMMESA;

▪ an increase in financial costs of Ch$ 137.3 billion in 2016 mainly due to Ch$ 66.3 billion from Emgesa related to El Quimbo power plant, a Ch$ 47.1 billion from Edesur due to interest accrued on unpaid service quality fines and a Ch$ 18.4 billion from Edesur, Dock Sud and Costanera, mainly due to higher outstanding debt balances with CAMMESA; and

▪ a decrease in foreign currency exchange gains (losses) of Ch$ 88.4 billion in 2016 mainly due to a Ch$ 49.2 billion decrease related to the non-recurring gain in foreign currency exchange differences in 2015 in connection with accounts receivable denominated in U.S. dollars from the Vuelta de Obligado thermal plant and a Ch$ 21.8 billion decrease in positive foreign exchange differences in the foreign currency denominated debt of our Brazilian subsidiaries.

Other Non-Operating Results from Continuing Operations

Other non‑operating results amounted to Ch$ 10.0 billion in 2016, an increase of Ch$ 13.3 billion compared to 2015, predominantly due to other gains in Enel Generación Perú from the sale of high-tension transmission lines for Ch$ 19.2 billion, partially offset by a recorded loss of Ch$ 9.9 billion due to the merger of Cundinamarca with and into Codensa.

Income Taxes

Total income tax expense decreased by Ch$ 164.3 billion, or 31.4%, in 2016, as compared to 2015, mainly due to a lower tax expense as a result of lower taxable income compared to 2015.

The effective or statutory tax rate was 38.6% in 2016 and 40.9% in 2015, mainly as result of lower taxes due to the appreciation of the Chilean peso in terms of the U.S. dollar, which impacted the U.S dollar denominated balance of our foreign investments for tax purposes (i.e. tax base of the foreign investments), taking into account that the tax currency of Enel Américas was the Chilean peso. In 2016, the Chilean peso appreciated against the U.S. dollar, thereby decreasing the tax bases of our foreign investments and decreasing the current income tax expense in 2016 as compared to 2015.

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 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 17 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 result in a difference between domestic or nominal tax rates in Chile and tax rates (12.0% for 2016 and 12.9% for 2015) enacted in each foreign jurisdiction:

	Nominal Tax Rates (%)				Tax effect of rates applied in other countries
	2016		2015		2016 ThCh$			2015 ThCh$
Argentina		35.0		35.0		(5,956,233	)		(35,876,093	)
Brazil		34.0		34.0		(20,797,438	)		(26,523,564	)
Colombia		40.0		39.0		(76,551,807	)		(89,366,919	)
Peru		29.5		28.0		(8,754,332	)		(13,049,116	)
						(112,059,810	)		(164,815,692	)

110

The reconciling tax effect, or the differences between the nominal tax rate and the statutory tax rate for each country are detailed below.

In Argentina, the reconciling tax effect decreased during 2016 compared to 2015 due to lower taxable income in El Chocón as a result of the non-recurring gain related to the Vuelta de Obligado thermal plant in 2015. The effective tax rate was 55.8% in 2016 and 27.7% in 2015, mainly due to the recognition in 2015 of non-recurrent revenues in Edesur, which resulted in net income for financial purposes and a reduction in the tax loss carryforward, and the recognition in 2015 of the non-recurring gain in Costanera, El Chocón, and Dock Sud related to the Vuelta de Obligado thermal plant.

In Brazil, the reconciling tax effect decreased in 2016 compared to 2015 due to lower taxable income from our Brazilian subsidiaries as a consequence of decreased revenues due to lower local electricity demand. The effective tax rate was 22.6% in 2016 and 32.0% in 2015, mainly due to a higher tax loss carryforward for Ampla and Enel Brasil.

In Colombia, the reconciling tax effect decreased in 2016 compared to 2015 due to an increase in the local corporate tax rate to 40% in 2016, compared to 39% in 2015, partially offset by lower taxable income from Emgesa as a result of the cessation capitalization of borrowing costs attributable to El Quimbo power plant which started operations in 2015. The effective tax rates for Colombia were 41.4% in 2016 and 38.0% in 2015, due to lower tax benefits from capital expenditures incurred during 2016, which was attributable to the completion of El Quimbo power plant in 2015. This tax benefit was granted to encourage investments in revenue-producing assets, and applies 30% of the invested amount as a deduction to taxable income. This tax benefit is considered a permanent difference that results in an effective tax rate lower than the statutory tax rate since the depreciable tax basis of the asset is equivalent to its gross amount.

In Peru, the reconciling tax effect decreased in 2016 compared to 2015 due to a decrease in taxable income due to a decrease in results from operations of Enel Generación Perú. The effective tax rate was 44.0% in 2016 and 29.9% in 2015. The higher effective tax rate in 2016 is due to the tax reform implemented in Peru in 2014 which led to a progressive reduction in tax rates. The tax rate as of 2017 will be 29.5%.

Net Income

The following table sets forth our consolidated net income from continuing operations before income taxes, income taxes and net income from continuing operations for the years ended December 31, 2016 and 2015.

	Year ended December 31,
	2016			2015			Change			Change
	(in millions of Ch$)									(in %)
Operating income		1,217,155			1,254,758			(37,603	)		(3.0	)
Other results		(286,671	)		25,054			(311,725	)	n.a
Income from Continuing Operations before income taxes		930,484			1,279,812			(349,329	)		(27.3	)
Income taxes		(359,369	)		(523,663	)		164,295			(31.4	)
Net Income from continuing operations		571,115			756,149			(185,034	)		(24.5	)
Income from discontinued operations		115,130			388,321			(273,190	)		(70.4	)
Net income attributable to:		686,245			1,144,469			(458,224	)		(40.0	)
Net income attributable to the parent company		383,060			661,587			(278,527	)		(42.1	)
Net income attributable to non-controlling interests		303,186			482,883			(179,697	)		(37.2	)

111

II. Results from Discontinued Operations

On March 1, 2016, the separation of the Chilean and non-Chilean generation and distribution businesses became effective. The Chilean shareholdings and related assets, liabilities, income, expenses and cash flows were allocated to the newly incorporated entity Enel Chile. Therefore, the statement of comprehensive income of Enel Américas for the year ended December 31, 2016 only includes income and expenses for two months from the Chilean businesses as compared to the inclusion of twelve months of income and expenses from the Chilean businesses for the year ended December 31, 2015 (see Note 5 Non-Current Assets or Disposal Groups Held for Sale or Held for Distribution to Owners and Discontinued Operations in our consolidated financial statements as of December 31, 2016).

The following table sets forth the breakdown by nature of the line item “Income after tax from discontinued operations” for the two month period ended February 29, 2016 and the year ended December 31, 2015:  

	For the two months ended February 29, 2016			For the year ended December 31, 2015
	(In millions of Ch$)
Revenues		402,810			2,382,671
Other operating income		2,561			14,736
Total Revenue and Other Operating Income		405,371			2,397,407
Raw materials and consumables used		(236,672	)		(1,481,986	)
Contribution Margin		168,699			915,421
Other work performed by the entity and capitalized		3,367			21,004
Employee benefits expense		(16,099	)		(136,555	)
Depreciation and amortization expense		—			(153,202	)
Reversal of impairment loss (impairment losses) recognized in profit or loss		(968	)		3,055
Other expenses		(16,591	)		(125,850	)
Operating income		138,408			523,873
Other gains		—			20,056
Financial income		2,563			15,270
Financial costs		(8,616	)		(61,616	)
Share of profit (loss) of associates and joint ventures accounted for using the equity method		1,293			8,905
Foreign currency exchange differences		(21	)		(13,395	)
Profit from indexed assets and liabilities		267			4,839
Income before taxes		133,894			497,932
Income tax expense, discontinued operations		(18,763	)		(109,613	)
NET INCOME FROM DISCONTINUED OPERATIONS		115,131			388,319
Net income from discontinued operations attributable to:
Shareholders of Enel Américas		77,879			293,191
Non-controlling interests		37,251			95,129
NET INCOME FROM DISCONTINUED OPERATIONS		115,130			388,320

112

Due to the classification of generation and distribution of energy activities in Chile as discontinued operations, those lines of business are not included in Note 32, Information by segment, in our consolidated financial statements.

3.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	)		(21.4	)
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
Enel Generación Perú (Peru)		8,633		9,320		(687	)		(7.4	)
Enel Generación Piura (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)		11,096		11,678		(582	)		(5.0	)
Coelce (Brazil)		11,215		11,165		50			0.4
Codensa (Colombia)		13,946		13,660		286			2.1
Enel Distribución Perú (Peru)		7,624		7,338		286			3.9
Total		62,373		61,813		560			0.9

113

The following table sets forth the revenues from continuing operations, by reportable segments and by operating segments within such reportable segments 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 in Argentina		212,136			167,630			44,506			26.6
Costanera		100,857			75,194			25,663			34.1
El Chocón		40,005			30,174			9,831			32.6
Dock Sud		69,963			61,606			8,357			13.6
Other		1,312			656			656			100.0
Generation and Transmission Business in Brazil		305,830			437,033			(131,203	)		(30.0	)
Cachoeira Dourada		91,563			158,965			(67,402	)		(42.4	)
Fortaleza		159,052			210,793			(51,741	)		(24.5	)
CIEN		55,534			70,800			(15,266	)		(21.6	)
Other		(319	)		(3,525	)		3,206			(91.0	)
Generation and Transmission Business in Colombia		778,768			753,385			25,383			3.4
Emgesa		778,768			753,373			25,395			3.4
Other		12			12			—			—
Generation and Transmission Business in Peru		437,887			401,695			36,192			9.0
Enel Generación Perú		382,877			353,795			29,082			8.2
Enel Generación Piura		58,093			50,849			7,244			14.2
Other		(3,082	)		(2,949	)		(133	)		4.5
Other Generation and Transmission Business reportable segment		141			3,126			(2,985	)		(95.5	)
Total Generation and Transmission Business reportable segment		1,734,762			1,762,869			(28,107	)		(1.6	)
Distribution Business in Argentina		607,345			371,412			235,933			63.5
Edesur		607,345			371,412			235,933			63.5
Distribution Business in Brazil		1,836,864			1,969,226			(132,362	)		(6.7	)
Ampla		1,026,680			1,092,282			(65,602	)		(6.0	)
Coelce		810,184			876,944			(66,760	)		(7.6	)
Distribution Business in Colombia		884,468			982,771			(98,303	)		(10.0	)
Codensa		884,468			982,771			(98,303	)		(10.0	)
Distribution Business in Peru		562,046			478,700			83,346			17.4
Enel Distribución Perú		562,046			478,700			83,346			17.4
Total Distribution Business reportable segment		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 Revenues		5,301,440			5,206,370			95,070			1.8

114

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 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 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 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 reais 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 reais and a Ch$ 11.6 billion decline of the price on the spot market. Revenues from CIEN decreased by 18.0% or Ch$ 12.1 billion mainly due to devaluation of Brazilian reais that resulted in Ch $ 12.9 billion 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 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 Enel Generación Perú in Peru grew by 8.1%, or Ch$ 28.8 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 Enel Generación Piura, 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$351.5 billion increase related to the application of Resolution 32/2015, which was comprised of: (i) Ch$ 305.9 billion of a non-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 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 reais 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 reais 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 Enel Distribución Perú increased by Ch$ 83.4 billion 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.

115

Total Operating Costs from Continuing Operations

Total operating costs from continuing operations consist primarily of energy purchases from third parties, fuel consumption, depreciation, amortization and impairment losses, maintenance costs, tolls paid to transmission companies, employee salaries and administrative and selling expenses.

The following table sets forth the consolidated operating costs in Chilean pesos for the years ended December 31, 2015 and 2014:

	Year ended December 31,
	2015				2014
	(inmillions 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 expense		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		12.1		463,729		12.1
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		3,818,369		100.0

(1) Corresponds to selling and administration expenses

116

The following table sets forth our total operating costs (excluding selling and administrative expenses) from continuing operations by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2015 and 2014:

	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business in Argentina		50,332			47,296			3,036			6.4
Costanera		4,598			6,777			(2,179	)		(32.2	)
El Chocón		4,574			8,427			(3,853	)		(45.7	)
Dock Sud		43,266			34,976			8,290			23.7
Other		(2,106	)		(2,884	)		778			(27.0	)
Generation and Transmission Business in Brazil		131,431			234,225			(102,794	)		(43.9	)
Cachoeira Dourada		17,396			72,988			(55,592	)		(76.2	)
Fortaleza		111,229			158,318			(47,089	)		(29.7	)
CIEN		3,126			3,343			(217	)		(6.5	)
Other		(319	)		(424	)		105		n.a.
Generation and Transmission Business in Colombia		321,665			220,460			101,205			45.9
Emgesa		321,665			220,303			101,362			46.0
Other		—			157			(157	)		(100.0	)
Generation and Transmission Business in Peru		174,513			151,707			22,806			15.0
Enel Generación Perú		151,046			133,735			17,311			12.9
Enel Generación Piura		26,124			20,916			5,208			24.9
Other		(2,657	)		(2,944	)		287			(9.7	)
Total Generation and Transmission Business reportable segment		677,941			653,688			24,253			3.7
Distribution Business in Argentina		157,387			161,995			(4,608	)		(2.8	)
Edesur		157,387			161,995			(4,608	)		(2.8	)
Distribution Business in Brazil		1,386,391			1,313,723			72,668			5.5
Ampla		804,701			707,301			97,400			13.8
Coelce		581,689			606,422			(24,733	)		(4.1	)
Distribution Business in Colombia		500,571			547,594			(47,023	)		(8.6	)
Codensa		500,571			547,594			(47,023	)		(8.6	)
Distribution Business in Peru		379,015			315,116			63,899			20.3
Enel Distribución Perú		379,015			315,116			63,899			20.3
Total Distribution Business reportable segment		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 operating costs (excluding selling and administrative expenses)		2,777,202			2,631,669			145,534			5.5

117

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 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 reais 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 reais 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 Enel Generación Perú rose by Ch$ 17.5 billion, or 13.1%, 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 reais 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 reais, 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 Enel Distribución Perú 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.

118

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 Selling and   Administrative Expenses
Other expenses		38.5		39.1
Staff benefit costs		33.1		28.1
Depreciation, amortization and impairment losses		28.4		32.8
Total		100.0		100.0

The following table sets forth the selling and administrative expenses by reportable segments and by operating segments within such reportable segments for the years ended December 31, 2015 and 2014:

119

	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business in Argentina		110,595			81,625			28,970			35.5
Costanera		75,886			54,715			21,171			38.7
El Chocón		8,421			7,408			1,013			13.7
Dock Sud		23,388			17,165			6,223			36.3
Other		2,900			2,337			563			24.1
Generation and Transmission Business in Brazil		42,843			53,974			(11,131	)		(20.6	)
Cachoeira Dourada		12,195			14,124			(1,929	)		(13.7	)
Fortaleza		12,956			15,481			(2,525	)		(16.3	)
CIEN		18,089			25,336			(7,247	)		(28.6	)
Other		(397	)		(967	)		570			(59.0	)
Generation and Transmission Business in Colombia		84,275			83,435			840			1.0
Emgesa		84,275			83,435			840			1.0
Generation and Transmission Business in Perú		106,048			91,131			14,917			16.4
Enel Generación Perú		91,718			78,902			12,816			16.2
Enel Generación Piura		14,305			12,345			1,960			15.9
Other		25			(116	)		141			(121.3	)
Other Generation and Transmission Business reportable segment		(1,637	)		(1,286	)		(351	)		27.3
Total Generation and Transmission Business reportable segment		342,124			308,879			33,245			10.8
Distribution Business in Argentina		346,182			260,646			85,536			32.8
Edesur		346,182			260,646			85,536			32.8
Distribution Business in Brazil		323,139			354,277			(31,138	)		(8.8	)
Ampla		195,556			201,135			(5,579	)		(2.8	)
Coelce		127,583			153,142			(25,559	)		(16.7	)
Distribution Business in Colombia		148,309			173,202			(24,893	)		(14.4	)
Codensa		148,309			173,202			(24,893	)		(14.4	)
Distribution Business in Perú		75,327			72,598			2,729			3.8
Enel Distribución Perú		75,327			72,598			2,729			3.8
Other	—				1,250
Total Distribution Business reportable segment		894,341			861,973			32,368			3.8
Less: consolidation adjustments and non-core activities		33,015			15,849			17,166			108.3
Total selling and administrative expenses		1,269,480			1,186,701			82,779			7.0

120

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 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 reais and Colombian peso to the Chilean peso, respectively.

In Peru, selling and administrative expenses of Enel Generación Perú 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 reportable segments and by operating segments within such reportable segments for the years ended December 31, 2015 and 2014:

121

	Year ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Generation and Transmission Business in Argentina		51,209			38,708			12,501			32.3
Costanera		20,372			13,702			6,670			48.7
El Chocón		27,009			14,339			12,670			88.4
Dock Sud		3,309			9,465			(6,156	)		(65.0	)
Other		518			1,202			(684	)		(56.9	)
Generation and Transmission Business in Brazil		131,556			148,834			(17,278	)		(11.6	)
Cachoeira Dourada		61,973			71,853			(9,880	)		(13.8	)
Fortaleza		34,867			36,994			(2,127	)		(5.7	)
CIEN		34,320			42,121			(7,801	)		(18.5	)
Other		397			(2,134	)		2,531			(118.6	)
Generation and Transmission Business in Colombia		372,828			449,490			(76,662	)		(17.1	)
Emgesa		372,828			449,635			(76,807	)		(17.1	)
Generation and Transmission Business in Peru		157,326			158,857			(1,531	)		(1.0	)
Enel Generación Perú		139,689			141,158			(1,469	)		(1.0	)
Enel Generación Piura		17,663			17,588			75			0.4
Other		(26	)		111			(137	)		(123.8	)
Other Generation and Transmission Business reportable segment		1,777			4,413			(2,636	)		(59.7	)
Total Generation and Transmission Business reportable segment		714,696			800,302			(85,606	)		(10.7	)
Distribution Business in Argentina		103,775			(51,229	)		155,004			(302.6	)
Edesur		103,775			(51,229	)		155,004			(302.6	)
Distribution Business in Brazil		127,334			301,226			(173,892	)		(57.7	)
Ampla		26,423			183,846			(157,423	)		(85.6	)
Coelce		100,911			117,380			(16,469	)		(14.0	)
Distribution Business in Colombia		235,587			261,975			(26,388	)		(10.1	)
Codensa		235,587			261,975			(26,388	)		(10.1	)
Distribution Business in Peru		107,705			90,986			16,719			18.4
Enel Distribución Perú		107,705			90,986			16,719			18.4
Other Distribution Business reportable segment		(1,383	)		(1,250	)		(133	)		10.6
Total Distribution Business reportable segment		573,019			601,708			(28,689	)		(4.8	)
Less: consolidation adjustments and non-core activities		(32,957	)		(14,010	)		(18,947	)		135.2
Total operating income		1,254,758			1,388,000			(133,242	)		(9.6	)

122

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 result
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			(793.4	)
Total		28,287			(213,316	)		241,603			(113.3	)
Other
Other gain (losses)		(6,566	)		877			(7,443	)		(848.7	)
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	)		(194.1	)
Total other results		25,054			(209,879	)		234,933			(111.9	)

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 1,208/2015, (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.

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 Dock Sud, Ch$ 8.0 billion in Enel Distribución Perú and Ch$ 4.3 billion in Edesur.

123

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 17 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		2015ThCh$			2014ThCh$
Argentina		35.0		35.0		(35,876,093	)		7,239,770
Brazil		34.0		34.0		(26,523,564	)		(41,357,762	)
Colombia		39.0		34.0		(89,366,919	)		(84,883,915	)
Peru		28.0		30.0		(13,049,116	)		(21,030,440	)
						(164,815,692	)		(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 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 Dock Sud 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 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.

124

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		n.a.
Income before tax		1,279,812			1,178,121			101,691			8.6
Income tax		(523,663	)		(425,958	)		(97,705	)		22.9
Net Income from continuing 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:		1,144,469			967,495			176,974			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 Enel Generación Chile and its subsidiaries and the corresponding changes for the years ended December 31, 2015 and 2014:

	Years ended December 31,
	2015		2014		Change		Change
	(in GWh)						(in %)
Enel Generación Chile and subsidiaries		23,558		21,156		2,402		11.4

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		Change
	(in GWh)						(in %)
Enel Distribución 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
Enel Generación Chile and subsidiaries		1,543,812			1,220,566			323,246			26.5
Distribution Business
Enel Distribución 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		2,397,407			2,047,507			349,900			17.1

125

Generation and Transmission Business: Revenues

Revenues from Enel Generación 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 Chile, which has been consolidated by Enel Generación Chile since May 2014.

Distribution Business: Revenues

Revenues from Enel Distribución 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.

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
	(inmillions of Ch$)		(in %)		(in millions of Ch$)		(in %)
Energy purchases		860,203		45.9		788,421		47.3
Fuel purchases		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 costs		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
Enel Generación Chile and subsidiaries		880,891			750,213			130,678			17.4
Distribution Business
Enel Distribución Chile and subsidiaries		983,733			855,758			127,975			15.0
Non-electricity business and combination adjustments		(382,639	)		(296,569	)		(86,070	)		29.0
Total		1,481,985			1,309,402			172,583			13.2

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Generation and Transmission Business: Operating Costs

Operating costs increased by Ch$ 130.7 billion, or 17.4%, in 2015, mainly due to (i) Ch$ 39.5 billion of higher other variable procurement and services costs mostly attributable to (a) Ch$ 23.7 billion related to the cost of the agreement with Gener’s Nueva Renca combined-cycle power plant that allows Enel Generación Chile to use its available LNG and (b) Ch$ 9.4 billion of higher water transportation costs for the operation of the San Isidro power plant, (ii) Ch$36.9 billion of higher gas transportation costs related to additional energy purchases, (iii) Ch$ 22.0 billion higher fuel consumption costs mainly due to Enel Generación Chile’s higher coal consumption costs of Ch$ 16.0 billion, and (iv) increased purchases of energy on the spot market of Ch$ 32.2 billion due to higher sales.

Distribution Business: Operating Costs

Operating costs of Enel Distribución Chile increased by Ch$ 128.0 billion, or 15.0%, in 2015, compared to 2014, mainly due to Ch$ 115.3 billion greater energy purchases, primarily due to a higher average purchase price of Ch$6.5 /GWh (13.2%) as a result of regular indexed costs adjustment that accounted for Ch$ 105.3 billion. In addition, operating costs increased because of variable procurement and service costs of Ch$ 8.2 billion, and higher transportation costs of Ch$ 4.5 billion.

Selling and Administrative Expenses from Discontinued Operations

Selling and administrative expenses relate to salaries, compensation, administrative expenses, depreciation, amortization and impairment losses, and office materials and supplies.

The following table sets forth our selling and administrative expenses as a percentage of our consolidated total selling and administrative expenses from discontinued operations for the years ended December 31, 2015 and 2014:

	Years ended December 31,
	2015		2014
	(in %)
Selling and Administrative Expenses as a Percentage of Selling and Administrative Expenses
Other fixed costs		32.1		30.9
Employee benefit expense and others		29.5		29.4
Depreciation, amortization and impairment losses		38.4		39.7
Total		100.0		100.0

The following table sets forth our 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
Enel Generación Chile and subsidiaries		261,088		224,627		36,461			16.2
Distribution Business
Enel Distribución Chile and subsidiaries		124,706		118,028		6,678			5.7
Non-electricity business and combination adjustments		5,753		14,125		(8,372	)		(59.3	)
Total selling and administrative expenses from discontinued    operations		391,547		356,780		34,767			9.7

Selling and administrative expenses from discontinued operations increased by Ch$ 34.8 billion, or 9.7%, in 2015, compared to 2014, mainly due to (i) higher other fixed costs of Ch$ 24.9 billion mostly attributable to increased costs related to the corporate reorganization and higher fines for sanctions and litigations, and (ii) higher charges in Enel Generación Chile for depreciation of Ch$ 2.8 billion from the full consolidation of GasAtacama.

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Operating Income from Discontinued Operations

The following table sets forth our operating income 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
Enel Generación Chile and subsidiaries		401,833			245,726			156,107			63.5
Distribution Business
Enel Distribución Chile and subsidiaries		149,294			154,107			(4,813	)		(3.1	)
Non-electricity business and combination adjustments		(27,637	)		(18,508	)		(9,129	)		49.3
Total		523,490			381,325			142,165			37.3

Other Results from Discontinued Operations

The following table sets forth our other results from discontinued operations for the years ended December 31, 2015 and 2014:

	Years ended December 31,
	2015			2014			Change			Change
	(in millions of Ch$)									(in %)
Financial results
Financial income		15,270			14,763			507			3.4
Financial costs		(61,617	)		(59,544	)		(2,073	)		3.5
Profit for indexed assets and liabilities		4,839			15,264			(10,425	)		(68.3	)
Foreign currency exchange differences		(13,395	)		(20,328	)		6,933			(34.1	)
Total		(54,903	)		(49,845	)		(5,058	)		10.1
Others
Gain from sales of assets		20,056			70,893			(50,837	)		(71.7	)
Share of the profit (loss) of associates and joint ventures    accounted for using the equity method		8,905			(54,353	)		63,258			(116.4	)
Total		28,961			16,540			12,421			75.1
Total other results from discontinued operations		(25,942	)		(33,305	)		7,363			(22.1	)

Financial Results from Discontinued Operations

The net financial results for the year ended December 31, 2015 was an expense of Ch$ 54.9 billion, an increase of Ch$ 5.1 billion, or 10.1%, compared to 2014, which was mainly explained by a lower gain for indexed assets and liabilities of Ch$ 10.4 billion due to a lower inflation rate in 2015.

Others from Discontinued Operations

The gain from sales of assets for the year ended December 31, 2015 was Ch$ 20.1 billion, a decrease of Ch$ 50.8 billion or 71.7%, compared to 2014. This decrease was primary due non-recurring gains in 2014 of (i) Ch$ 42.6 billion recorded in 2014 arising from the revaluation of the 50% pre-existing investment in GasAtacama and a recognition of its accumulated currency exchange differences and (ii) Ch$ 21.1 billion recorded in 2014 from the sale of the equity interest in Los Maitenes and Aguas Santiago Poniente (ENEA Project). The decrease was partially offset by a net gain of Ch$ 14.6 billion from the sale of land (Alonso de Córdova substation) during the fourth quarter of 2015. Our share of the profit (loss) of associates and joint ventures investments accounted for using the equity method in 2015 was Ch$ 8.9 billion, an increase of Ch$ 63.3 billion as compared to 2014, primarily due to the non-recurring impairment loss of Ch$ 69.1 billion recorded in December 2014 in connection with HidroAysén project, due to Enel Generación Chile’s decision not to proceed with this project. This decision was based on the uncertainty of recovering the investment made in the project, mainly as a consequence of the long judicial process in order to obtain environmental approvals.

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Income Tax Expenses from Discontinued Operations

Income tax expenses totaled Ch$ 109.7 billion in 2015, a decrease of Ch$ 23.0 billion, or 17.4%, compared to 2014. The decrease in corporate income tax expense was mainly due to the absence in 2015 of a one-time effect recorded as a net deferred tax liability of Ch$ 66.7 billion in 2014, following the tax reform enacted in Chile on September 29, 2014. The 2014 tax reform established a gradual increase in the taxation rate until 2018 and is expected to slightly affect our results in the future, considering that the main impacts on deferred taxes have already been recognized.

The effective tax rate was 24.0% in 2015 and 39.9% in 2014.

Net Income from Discontinued Operations

The following table sets forth our net income before taxes, income tax expenses and net income for the years ended December 31, 2015 and 2014:

	Years ended December 31,
	2015			2014			Change		Change
	(in millions of Ch$)								(in %)
Operating income		523,875			381,325			142,550		37.4
Other results		(25,942	)		(33,305	)		7,363		(22.1	)
Net income before taxes		497,933			348,020			149,913		43.1
Income tax expenses		(109,613	)		(132,688	)		23,075		(17.4	)
Net income		388,320			215,332			172,988		80.3
Net income attributable to the Parent Company		293,191			178,231			114,960		64.5
Net income attributable to non-controlling interests		95,130			37,101			58,029		156.4

The increase in net income attributable to non-controlling interests of Ch$ 58.0 billion in 2015 compared to 2014, is primarily due to the Ch$ 69.3 billion increase of net income attributable to the non-controlling interests of Enel Generación Chile for 2015, which in turn is mainly due to the increase in net income in Enel Generación Chile by Ch$ 154.7 billion. The controlling and economic interest in Enel Generación Chile is the same in both years (59.98%).

B. Liquidity and Capital Resources.

Our main assets are the stocks of our subsidiaries. The following discussion of cash sources and uses reflects the key drivers of our cash flow.

We, on a stand-alone basis, receive cash inflows from our subsidiaries, as well as from related companies. Our subsidiaries and associates’ cash flows may not be available to satisfy our own liquidity needs, mainly because they are not wholly-owned, and because there is a time lag before we have effective access to those funds through dividends or capital reductions. However, we believe that cash flow generated from our business operations, as well as cash balances, borrowings from commercial banks, and ample access to both Chilean and foreign capital markets will be sufficient to satisfy all our needs for working capital, debt service, dividends and routine capital expenditures in the foreseeable future.

Our 2016 statement of cash flows includes cash flows for only two months from the Chilean businesses as compared to the 2015 and 2014 statements of cash flow that include 12 months of cash flows from the Chilean businesses (see Note 5 of the Notes to our consolidated financial statements).

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Set forth below is a summary of our consolidated cash flow information (including both continued and discontinued operations) for the years ended December 31, 2016, 2015 and 2014.

	Year ended December 31,
	2016			2015			2014
	(in billions of Ch$)
Net cash flows provided by operating activities		1,712			1,923			1,698
Net cash flows used in investing activities		(497	)		(1,215	)		(300	)
Net cash flows used in financing activities		(740	)		(1,060	)		(1,283	)
Net increase (decrease) in cash and cash equivalents before    effect of exchange rates changes		476			(352	)		115
Effects of exchange rate changes on cash and cash equivalents		(5	)		(23	)		(17	)
Cash and cash equivalents at beginning of period		1,329			1,705			1,606
Cash and cash equivalents at end of period		1,801			1,329			1,705

Set forth below is a summary of the net cash flow attributable to discontinued operations for the two months ended February 29, 2016 and for the years ended December 31, 2015 and 2014.

	Two months ended February 29,			Year ended December 31, (12 months)
	2016			2015			2014
	(in billions of Ch$)
Net cash flows provided by operating activities		152			577			265
Net cash flows used in investing activities		(46	)		(297	)		(189	)
Net cash flows used in financing activities		(88	)		(273	)		(159	)
Net increase (decrease) in cash and cash equivalents before    effect of exchange rates changes		18			6			(83	)
Effects of exchange rate changes on cash and cash equivalents		(1	)		5			1
Cash and cash equivalents at beginning of period		144			133			215
Cash and cash equivalents at end of period		161			144			133

For the year ended December 31, 2016, net cash flow provided by operating activities from continuing and discontinued operations was Ch$ 1,712 billion, a decrease of Ch$ 211 billion, or 11%, compared to Ch$ 1,923 billion for the same period of 2015. The main drivers of this change are described below.

The aggregate cash inflows from operating activities provided by continuing operations were primarily due to Ch$ 662 billion in higher collections from the sale of goods and services mainly comprised of:

(i) Ch$ 374 billion from Enel Brasil, on a consolidated basis, explained by (a) Ch$ 160 billion from Coelce due to an increase in the collection rate from 96.1% in 2015 to 97.8% in 2016, despite a decrease of Ch$ 5.5 billion, or 0.7%, in its revenues, (b) Ch$ 128 billion from Ampla mainly as a result of an increase in the collection rate from 94.2% in 2015 to 97.1% in 2016 and (c) Ch$ 97 billion from Cachoeira due to an increase in physical sales;

(ii) Ch$ 56 billion from Enel Generación Perú due to an increase in physical sales;

(iii) Ch$ 43 billion from Codensa mainly related to the annual tariff adjustment;

(iv) Ch$ 42 billion from Edesur due to higher revenues mainly as a result of the application of Resolution 1/2016;

(v) Ch$ 40 billion from Enel Distribución Perú due to increased physical sales and increased prices according to annual tariff adjustments as well as a higher collection rate of 99.8% in 2016 compared to 98.6% in 2015; and

(vi) Ch$ 39 billion from Dock Sud as a result of increased physical sales due to greater market demand.  

The aggregate cash outflows used in operating activities from continuing operations were primarily due to an increase in payments to suppliers for goods and services from continuing operations of Ch$ 225 billion mainly related to:

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(i) Ch$ 174 billion from Edesur due to greater energy purchases mostly attributable to increased prices as a result of the annual tariff adjustment mainly due to local inflation; and

(ii) Ch$ 46 billion from Enel Distribución Perú due to greater energy purchases related to higher contracted prices.

These operating cash inflows and outflows from continuing operations were offset by a net outflow of Ch$ 814 billion related to collections from the sale of goods and services and payments to suppliers from the discontinued operations of Enel Generación Chile and Enel Distribución Chile, which as a result of the separation of the Chilean and non-Chilean businesses are no longer consolidated by us as of March 1, 2016 (see explanation above). The decrease in net cash flow from operating activities from continuing and discontinued operations was partially offset by a decrease in other operating cash outflows of Ch$ 198 billion, due to greater payments of Value Added Tax and others of Ch$ 88 billion, lower collections carried out by Codensa Hogar in Colombia of Ch$ 48 billion, and other lower payments in operating activities of Ch$ 118 billion, offset by greater payments to the Energy Development Account in Brazil of Ch$ 56 billion (see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework — Brazilian Electricity Regulatory Framework — Regulation of Distribution Companies — Energy Development Account, “Cuenta de Desarrollo Energético - CDE”).

For the year ended December 31, 2015, net cash flow from operating activities from continuing and discontinued operations was Ch$ 1,923 billion, an increase of Ch$ 225 billion, or 13.3%, compared to Ch$ 1,698 billion for the same period of 2014. This increase is primarily a consequence of an increase in collections from the sale of goods and services of Ch$ 1,197 billion comprised of:

(i) Ch$ 337 billion from Enel Distribución Chile due to an increase of the tariff to regulated customers, despite the decrease in the collection rate from 99.6% in 2014 to 97.0% in 2015;

(ii) Ch$ 286 billion of Enel Generación Chile on a stand-alone basis as a consequence of an increase in physical sales;

(iii) Ch$ 265 billion from Edesur due to higher revenues as a result of the application of Resolution 32/2015;

(iv) Ch$ 116 billion from the full consolidation of GasAtacama; and

(v) Ch$ 88 billion from Enel Distribución Perú as a consequence of increased revenues of Ch$ 83.4 million in 2015.

The increase in collections from the sale of goods and services in 2015 was partially offset by:

(i) an increase in payments to suppliers for goods and services of Ch$ 479 billion comprised of:

(a) Ch$ 135 billion from Edesur due to the application of Resolution 32/2015, which allows trade and other payables to be offset against trade and other receivables;

(b) Ch$ 133 billion from Enel Distribución Chile mainly due to Ch$ 115.3 billion of higher energy purchases due to the higher indexation cost adjustments;

(c) Ch$ 86 billion from Enel Generación Chile, on a stand-alone basis, of payments to third parties, which was mostly a consequence of higher variable procurement and services of Ch$ 39.5 billion, mostly attributable to costs related to the lease of Gener’s Nueva Renca combined-cycle power plant for use of Enel Generación Chile’s available LNG and Ch$ 36.9 billion higher transportation costs related to additional energy purchases;

(d) Ch$ 80 billion from Emgesa as a consequence of Ch$ 82 billion higher energy purchases;

(e) Ch$ 80 billion from Ampla due to higher energy purchases of Ch$ 75 billion related to the drought;

(f) Ch$ 64 billion from the full inclusion of GasAtacama; and

(g) Ch$ 94 billion lower payments to suppliers for goods and services from Codensa mainly due to the currency translation effect of converting Colombian pesos to Chilean pesos;

(ii) a decrease in other collections from operating activities of Ch$ 200 billion mainly due to a decrease in Ampla of Ch$ 113 billion and in Coelce of Ch$ 72 billion, in both cases as a consequence of reduced collection of the CDE charges (see “Item 4. Information on the Company — B. Business Overview — Electricity Industry Regulatory Framework —

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Brazilian Electricity Regulatory Framework — Regulation of Distribution Companies — Energy Development Account, “Cuenta de Desarrollo Energético - CDE”);

(iii) an increase in other payments for operating activities of Ch$ 155 billion mainly attributable to lower VAT payments by Ampla of Ch$ 159 billion as a consequence of lower sales;

(iv) an increase in payments to and on behalf of employees of Ch$ 72 billion mainly attributable to Ch$ 69 billion of increases in wages and benefits in Edesur;

(v) an increase in other outflows of cash of Ch$ 34 billion mainly attributable to Ch$ 25 billion as a consequence of higher VAT related to higher sales in Enel Distribución Chile; and

(vi) an increase in income taxes paid of Ch$ 23 billion, mainly due to higher sales in Enel Generación Chile.

For further information regarding our operational results in 2016, 2015 and 2014, please see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2016 and 2015” and “— 3. Analysis of Results of Operations for the Years Ended December 31, 2015 and 2014.”

For the year ended December 31, 2016, net cash used in investing activities from continuing and discontinued operations was Ch$ 497 billion, mostly explained by the acquisition of fixed assets totaling Ch$ 832 billion, of which Ch$ 772 billion was from continuing operations.  This line item was mainly comprised of: (i) the incorporation of intangible assets (under IFRIC 12) of our Brazilian distribution companies of Ch$ 274 billion, and (ii) investments to ensure the sustainability of the distribution business: Ch$ 150 billion from Codensa, Ch$ 91 billion from Edesur, and Ch$ 80 billion from Enel Distribución Perú. This was partially offset by interest received of Ch$ 85 billion from continuing operations and proceeds from the sale of property, plant and equipment of Ch$ 70 billion of which Ch$ 54 billion was from continuing operations related to the sale of real estate property and transmission lines by Enel Generación Perú and Chinango. In addition, net cash used in investing activities from continuing and discontinued operations was also the result of Ch$ 171 billion in collections from related parties mainly due to a payment of Ch$ 167 billion by Enel Generación Chile to us related to an intercompany structured loan.

For the year ended December 31, 2015, net cash used in investing activities from continuing and discontinued operations was Ch$ 1,215 billion, mostly explained by the acquisition of fixed assets totaling Ch$ 1,363 billion. This line item was mainly comprised of (i) Enel Generación Chile, on a stand-alone basis, related to the 150 MW Los Cóndores project, (ii) Emgesa, related to the construction of El Quimbo and (iii) the incorporation of intangible assets (under IFRIC 12) of the Brazilian distribution companies. This was partially offset by (i) interest received of Ch$ 59 billion, (ii) investments in time deposits with a maturity greater than 90 days for Ch$ 43 billion, (iii) collections from derivatives contracts of Ch$ 17 billion and (iv) other inflows for Ch$ 18 billion, mainly the collection of cash collateral related to derivatives.

For further information regarding the acquisition of fixed assets in 2016 and 2015, please see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures and Divestitures.”

For the year ended December 31, 2016, net cash used in financing activities from continuing and discontinued operations decreased to Ch$ 740 billion from Ch$ 1,060 billion for 2015. The main drivers of this change are described below.

The aggregate cash outflows from financing activities from continuing operations were primarily due to:

• Ch$ 699 billion in payments of loans and bonds (including Ch$ 172 billion from us on a stand-alone basis and from our subsidiaries: Enel Distribución Perú (Ch$ 120 billion), Emgesa (Ch$ 107 billion), Ampla (Ch$ 88 billion), Enel Generación Perú and Chinango (Ch$ 87 billion), Coelce (Ch$ 78 billion), among others).

• Ch$ 417 billion in dividend payments to third parties, excluding dividends paid to us (including Ch$ 229 billion from us on a stand-alone basis, Ch$ 91 billion from Emgesa, Ch$ 50 billion from Codensa, Ch$ 29 billion from Endesa Américas, among others).

• Ch$ 235 billion in interest expense (including Ch$ 99 billion paid by Emgesa, Ch$ 36 billion paid by Ampla, Ch$ 32 billion paid by Codensa, Ch$ 24 billion paid by Coelce, Ch$ 18 billion paid by Enel Distribución Perú, Ch$ 14 billion paid by us, among others).

Other important outflow was Ch$ 318 billion in other cash outflows from continuing and discontinued operations mostly as a consequence of: (i) the division of the Company’s cash and cash equivalent related to the 2016 Reorganization of Ch$ 161 billion, (ii) the payment of financial derivatives of Ch$ 84 billion related to our 10-year Yankee Bond issued in 1996 and due in December, 2016 and (iii) payments for fees and discounts of bonds and bank loans of Ch$ 67 billion.

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The aggregate cash inflows from financing activities from continuing operations were primarily due to:

• Ch$ 396 billion in Yankee Bonds issued by us.

• Ch$ 179 billion in bonds issued by Emgesa.

• Ch$ 157 billion in loans and bonds granted to Enel Distribución Perú.

• Ch$ 154 billion in loans granted to Ampla and Coelce.

• Ch$ 98 billion in loans granted to Codensa.

For the year ended December 31, 2015, net cash used in financing activities from continuing and discontinued operations decreased to Ch$ 1,060 billion from Ch$ 1,283 billion for 2014. The main drivers of this change are described below.

The aggregate cash outflows from financing activities from continuing and discontinued operations were primarily due to:

• Ch$ 612 billion in dividend payments to third parties, excluding dividends paid to us (including Ch$ 305 billion from us on a stand-alone basis, Ch$ 135 billion from Emgesa, Ch$ 64 billion from Enel Generación Chile on a stand-alone basis, Ch$ 72 from Codensa, among others).

• Ch$ 615 billion of payments of loans and bonds (Ch$ 207 billion for Emgesa, Ch$ 141 billion for Enel Generación Chile on a stand-alone basis, Ch$ 92 billion for Enel Generación Perú and Chinango, Ch$ 63 billion for Ampla, Ch$ 49 billion of Enel Distribución Perú, among others).

• Ch$ 267 billion in interest expense (including Ch$ 80 billion in Emgesa, Ch$ 60 billion in Enel Generación Chile on a stand-alone basis, Ch$ 36 billion in Ampla, Ch$ 27 billion in Codensa, among others).

The aggregate cash inflows from financing activities from continuing and discontinued operations were primarily due to:

• Ch$ 290 billion in loans granted to Emgesa.

• Ch$ 47 billion in loans granted to Enel Generación Perú and Chinango.

• Ch$ 48 billion in loans and bonds granted to Enel Distribución Perú.

For a description of liquidity risks resulting from the inability of our subsidiaries to transfer funds, please see “Item 3. Key Information — D. Risk Factors — We depend on payments from our subsidiaries, jointly-controlled entities and associates to meet our payment obligations.”

We coordinate the overall financing strategy of our controlled subsidiaries. However, our operating subsidiaries independently develop their capital expenditure plans and finance their capital expansion programs through internally generated funds or direct financings. We have no legal obligations or other commitments to financially support our subsidiaries. In some cases, our subsidiaries may be financed by us through intercompany loans. For information regarding our commitments for capital expenditures, see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures and Divestitures” and our contractual obligations table set forth below under “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations.

Having stated our corporate policy in connection with the financial autonomy that we expect from our subsidiaries, we have in the past, and to a very limited extent, provided financial support to Argentina in the form of intercompany loans and capital contributions in which debt was capitalized, and in the more recent past to Brazil. 

In March 2016, as a consequence of the political and economic situation prevailing in Brazil, we guaranteed Ampla’s US$ 75 million three-year bank term loan. The financing was provided in Chile in U.S. dollars, and had a swap from U.S. dollars to Brazilian reais contracted in Brazil, which was also guaranteed by us. Thereafter, in July, 2016, the Chilean shareholders of Enel Brasil granted intercompany loans to Enel Brasil to provide financial stability to our subsidiaries in Brazil. Following the consummation of the merger of Endesa Américas and Chilectra Américas with and into Enel Américas, we are the only creditor of such intercompany loans for a total amount of Br$ 169 million. Enel Generación Perú, also a shareholder of Enel Brasil, granted a loan to the company for Br$ 7 million. The intercompany loans are due in December 2017.

We have accessed the international equity capital markets (including several SEC-registered ADS issuances) in 1993, 1996, 2000, 2003 and 2013. We have also issued bonds in the United States (“Yankee Bonds”). Since 1996, we have issued a total of US$ 1.75 billion in Yankee Bonds.

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The following table lists the Yankee Bonds issued by us outstanding as of December 31, 2016. The weighted average annual coupon interest rate for such bonds is 4.0%, without giving effect to each bond’s duration, or put options.

					AggregatePrincipalAmount
Issuer	Term	Maturity	Coupon		Issued		Outstanding
			(%)		(in millions of US$)
Enel Américas	10 years	October 2026		4.00		600		600
Enel Américas(1)	30 years	December2026		6.60		150		1
Total			4.004 (2)			750		601

(1) Holders of our 6.6% Yankee Bonds due 2026 exercised a put option on December 1, 2003 for an aggregate principal amount of US$ 149 million, leaving US$ 1 million outstanding.

(2) Weighted-average coupon by outstanding amount.

The following table lists Emgesa’s bond issued in the United States. The bond is denominated in Colombian pesos. The annual interest rate for such bond is 10.17%.

					Aggregate Principal Amount
Issuer	Term	Maturity	Coupon (inflation adjustedrate)		Issued		Outstanding
			(%)		(inbillionsof CP$)		(inbillionsof CP$)		(inbillions ofCh$)(1)
Emgesa	10years	January2021		10.17		737		737		164

(1) Calculated based on the Observed Exchange Rate as of December 31, 2016, which was CP$ 4.482 per Ch$ 1.00

We, as well as our subsidiaries in the countries in which we operate, have access to the domestic capital markets where we have issued debt instruments including commercial paper and medium and long-term bonds that are primarily sold to pension funds, life insurance companies and other institutional investors.

The following table lists UF-denominated Chilean bonds issued by us outstanding as of December 31, 2016. 

					Aggregate Principal Amount
Issuer	Term	Maturity	Coupon (inflation adjustedrate)		Issued		Outstanding
			( %)		(inmillions ofUF)		(inmillions ofUF)		(inbillions ofCh$)
Enel Américas Series B2	21 years	June 2022		5.75		2.5		0.9		23

For a full description of local bonds issued by us, see “Secured and unsecured liabilities by company” in Note 18 of the Notes to our consolidated financial statements.

The following table lists local bonds issued by our foreign subsidiaries, outstanding as of December 31, 2016. We present aggregate information for each company. The maturity column for each company reflects the issuance with the longest maturity, and the coupon rate corresponds to the weighted average coupon of all issuances for each company.

Issuer	Maturity	Coupon(1)		AggregatePrincipal Amount Outstanding
		(%)		(in billions of Ch$)
Ampla	July 2019		16.47		192
Codensa	November 2025		11.26		250
Coelce	October 2018		17.35		58
Enel Generación Perú	January 2028		6.43		36
Enel Distribución Perú	November 2038		6.39		252
Emgesa	May 2030		11.21		708
Total					1,496

(1) Many of the coupon rates are variable rates based on local indices, such as inflation. The table reflects the coupon rate taking into account each local index as of December 31, 2016.

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We frequently participate in the international commercial bank markets through syndicated senior unsecured loans, including both fixed term and revolving credit facilities. We also borrow from banks in Chile under fully committed facilities under which a potential “Material Adverse Effect” (“MAE”) would not be an impediment to this source of liquidity. In 2016, we entered into 3-year bilateral revolving loans for an aggregate amount of UF 2.8 million (Ch$ 75 billion as of December 31, 2016) as shown below.

Borrower	Type	Maturity	Facility Amount		Amount Drawn
			(in millions of UF$)		(in millions of UF$)
Enel Américas	Bilateral revolving loan	March 2019		2.8		—

Our subsidiaries also have access to fully committed credit lines in the local markets, as detailed below.

Borrower	Type	Last Maturity	Facility Amount		Amount Drawn
			(in billions of Ch$)		(in billions of Ch$)
Ampla	Bilateral revolving loan	June 2017		21		—
Enel Brasil	Bilateral revolving loan	April 2017		10		—
Total				31		—

As a result of the foregoing, we have access to fully committed undrawn revolving loans, both international and domestic, for up to Ch$ 106 billion in the aggregate as of December 31, 2016.

In August 2016, we entered into an 18-month Senior Unsecured Term Loan Agreement for an initial aggregate amount of US$ 1 billion denominated in Chilean pesos and an additional US$ 500 million denominated in U.S. dollars, to fund the potential financial needs arising from the 2016 Reorganization, including the payment of statutory merger dissenters’ withdrawal rights, among other needs. In December 2016, we decided before the due date to terminate the agreement, which was undrawn at the time.

We also borrow routinely from uncommitted Chilean bank facilities with approved lines of credit for Ch$ 6 billion in the aggregate, none of which are currently drawn. Unlike the committed lines described above, which are not subject to MAE conditions precedent prior to disbursements, these facilities are subject to greater risk of not being disbursed in the event of a MAE, and therefore could limit our liquidity under such circumstances. Our subsidiaries also have access to uncommitted local bank facilities, for a total amount of Ch$ 313 billion, which were completely undrawn as of December 31, 2016.

We may also access the Chilean commercial paper market under programs that have been registered with the Chilean SVS for a maximum of US$ 200 million. In addition, we have a local bond program registered with the SVS for UF 12.5 million (Ch$ 329 billion as of December 31, 2016), which has not been drawn upon yet. Finally, our foreign subsidiaries also have access to other types of financing, including governmental facilities, supplier credit and leasing, among others.

Except for our SEC-registered Yankee Bonds, which are not subject to financial covenants, our outstanding debt facilities include financial covenants. The types of financial covenants, and their respective limits, vary from one type of debt to another. As of December 31, 2016, the most restrictive financial covenant affecting us was the ratio of Unsecured Assets to Unsecured Total Liabilities, as defined contractually, corresponding to the Series B2 local bonds due June 2022. Under such covenant, the maximum additional debt that could be incurred without a breach is Ch$ 2,670 billion. As of December 31, 2016 and as of the date of this Report, we and our subsidiaries are in compliance with the financial covenants contained in our debt instruments.

In the distribution business, Ampla has been facing 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 a breach of contract. There is an additional risk of covenant noncompliance if the economic environment in Brazil continues to worsen. In this context, we guaranteed a loan from Ampla, as mentioned above.

As is customary for certain credit and capital market debt facilities, a significant portion of our financial indebtedness is subject to cross default provisions. Each of the revolving credit facilities described above, as well as all of our Yankee Bonds, have cross default provisions with different definitions, criteria, materiality thresholds, and applicability as to the subsidiaries that could give rise to a cross default.

Our local facility due March 2019 does not have cross default provisions to debt other than the borrower’s own indebtedness.

Cross default provisions of a substantial portion of our Yankee Bonds may be triggered by another debt of the borrower or by significant subsidiaries, as defined contractually. A matured default on an individual basis could result in a cross default to our Yankee Bonds if such matured default, on an individual basis, has a principal exceeding US$ 150 million, or its equivalent in other currencies.

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In the case of a matured default above the materiality threshold, Yankee bondholders would have the option to accelerate if either the trustee or bondholders representing no less than 25% of the aggregate debt of a particular series then outstanding choose to do so. Our local bonds do not have subsidiary cross default provisions.

All of our Yankee Bonds are unsecured and not subject to any guarantees by any of our subsidiaries or parent company, or contain any financial covenants.

Our subsidiaries have access to existing credit lines sufficient to satisfy all of their present working capital needs. However, during 2015 and 2016, access to the capital markets on the part of our Brazilian subsidiaries was very limited due to the financial situation prevailing in Brazil. Notwithstanding these circumstances and the slightly better result in 2016, these subsidiaries were still able to refinance debt maturing in 2015 and in 2016.

Payment of dividends and distributions by our subsidiaries and affiliates represent an important source of funds for us. The payment of dividends and distributions by certain subsidiaries and affiliates are potentially subject to legal restrictions, such as legal reserve requirements, and capital and retained earnings criteria, and other contractual restrictions. Legal counsel in the countries where our subsidiaries and affiliates operate have informed us of the current legal restrictions regarding the payment of dividends or distributions to us in the jurisdictions where such subsidiaries or affiliates are incorporated. We are currently in compliance with the legal restrictions, and therefore, they currently do not affect the payment of dividends or distributions to us. Certain credit facilities and investment agreements of our subsidiaries or affiliates restrict the payment of dividends or distributions in certain special circumstances. For instance, one of Enel Generación Chile’s UF-denominated Chilean bonds due October 2028 restricts the amount of intercompany loans that Enel Generación Chile and its consolidated subsidiaries are allowed to lend to us. The threshold for such aggregate restriction of intercompany loans is US$ 100 million equal to Ch$ 67 billion. For a description of liquidity risks resulting from our company status, please see “Item 3. Key Information — D. Risk Factors —We depend on payments from our subsidiaries, jointly-controlled entities and associates to meet our payment obligations.”

Our estimated capital expenditures for 2017 through 2019 amount to Ch$ 2,755 billion, of which Ch$ 2,687 billion are considered non-discretionary investments. Maintenance capital expenditures is considered non-discretionary because it is necessary to maintain the quality and operation standards required for our facilities, but we do have some flexibility regarding the timing for these investments. We consider the investment in expansion projects under execution as non-discretionary expenditures. We consider the remaining Ch$ 67 billion as discretionary capital expenditures. The latter includes expansion projects that are still under evaluation, in which case we would undertake them only if deemed profitable.

Other than in Brazil, we do not currently anticipate liquidity shortfalls affecting our ability to satisfy the material obligations described in this Report.  Brazil is currently affected by a severe recession that has limited its access to bank loans and the ability to issue new debt in the capital markets, not only for electrical utilities, but also for companies in most of the other industries operating in the country.  As a result, market conditions have deteriorated and interest rates have risen due to increased market risk, making the cost of funding operations more expensive in Brazil.

Notwithstanding these market conditions, our subsidiaries in Brazil benefit from being part of the Enel Group, which provides them access to most of the leading banks in the world, facilitating access to resources outside Brazil.  For example, in March 2016, Ampla entered into a US$ 75 million loan with us as guarantor.  However, if market conditions in Brazil continue to deteriorate or lenders are unwilling to accept an Enel Américas guarantee as credit support, then the cost of financing would increase both in the short and long term, and in the worst case scenario the companies would not be able to finance themselves under these adverse economic conditions.

Other than with respect to Brazil, we expect to be able to refinance our indebtedness as it becomes due, fund our purchase obligations with internally generated cash and fund capital expenditures with a mixture of internally generated cash and borrowings.

C. Research and Development, Patents and Licenses, etc.

None.

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D. Trend Information.

Our subsidiaries are engaged in the generation, transmission and distribution of electricity in Argentina, Brazil, Colombia and Peru. Our businesses are subject to a wide range of conditions that may result in significant variability in our earnings and cash flows from year to year. We seek to establish a conservative and well-balanced commercial policy on a country-by-country basis, which aims at controlling relevant variables, reducing risks and providing stability in our results of operations.

Our net income is principally the result of operating income from our generation and our distribution businesses, and non-operating income, which consists primarily of income arising from related companies accounted for under the equity method, foreign currency exchange rate effects, interest expense and tax expense.

In our generation business, our operating income is impacted by the combined effect of several factors, including our contracted electricity prices, prevailing hydrological conditions, the price of fuels used to generate thermal electricity, contracted obligations, generation mix, and electricity prices prevailing in the spot market, among others.

Among the main drivers of our results of operations are our sale prices and energy costs in each market where we operate. The quantity of electricity sold has been generally stable over time, with increases reflecting economic and demographic growth. Our profits from contracted sales are driven by the ability to generate or buy electricity at a cost lower than the contracted sale price. However, the applicable price for sales and purchases of electricity sold and purchased in the spot market is much harder to predict because the spot generation price is influenced by many factors, which can differ in each of the countries where we operate. Abundant hydrological conditions generally lower spot prices, while dry conditions increase them. However, our operating income might not be impacted adversely even when we are required to buy at high prices in the spot market if our commercial policy is appropriately managed. Our strategy to mitigate our exposure to the volatility of the spot market consists of contracting sales of a significant portion of our expected electricity generation through long-term electricity supply contracts. Hence, our optimal level of electricity supply commitments is one that allows us to protect ourselves against low marginal cost conditions, such as those existing during the rainy season, while still taking advantage of high marginal cost conditions, such as higher spot market prices during dry years. In order to determine the optimal mix of long-term contracts and sales in the spot market, we (i) project our aggregated generation taking into consideration our generation mix, the incorporation of new projects under construction and various hydrological scenarios (from “wet” to “dry” conditions), (ii) create demand estimates using standard economic theory, and (iii) forecast the system’s marginal cost using proprietary stochastic models. This commercial policy is not applicable in Argentina, where contracted sales are immaterial and our margin is strongly dependent on the current regulatory framework, which is heavily controlled and regulated by the government, as explained further below.

International prices for commodities such as fuel oil, coal and LNG also have an impact on spot electricity prices. Fuel prices affect our results since commodity prices directly affect generation costs of our thermal power plants, mainly in Peru where our capacity is approximately 60% thermal, as opposed to Colombia and Brazil, where most of our capacity corresponds to hydroelectric plants. Fuel prices have materially decreased since the second half of 2014 reaching their lowest level in February 2016 and increasing slightly during 2016, but still remaining lower than 2015 prices. It is expected that fuel prices will continue to increase during 2017 and, therefore, our costs might also increase, especially for our Peruvian power plants. Our costs also depend on factors such as spot prices, generation mix, hydrological conditions and our contractual surpluses/deficits. In order to mitigate the risk of increasing fuel costs, we have entered into supply contracts to cover part of the fuel needed to operate our thermal generation units, which operate with coal, natural gas, diesel, and fuel oil. 

Other factors that affect operating income include transmission costs that are incurred when delivering electricity from its source to end consumers. In Colombia and Peru, transmission costs are mostly passed through to the customers and mainly depend on physical sales. The transmission system charge is set by the regulator, and has tended to remain stable over time.  In Argentina, generators pay their transmission costs, which as of February 2017, have new values due to a transmission tariff review that has impacted the operational margin of power plants. In Brazil, transmission costs are passed through to the final customers. The ANEEL, the Brazilian National Electric Energy Agency, approves the annual transmission electricity required revenue, which is paid by all the transmission system’s users. 

This general framework applies to most of the countries where we operate, but there are some variations in some of these factors. In Argentina, the electricity market is highly regulated and electricity prices are determined by CAMMESA, which is the sole seller for the fuel needed for thermal generation operations. This means that market agents will not be allowed to trade fuels and, as a result, fuel and commodity prices do not have a direct impact on our Argentine operations.

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In Brazil, 65% of the country’s installed capacity and 67% of our own installed capacity is hydroelectric. Therefore, electricity prices are significantly affected by hydrological conditions. Thus, to provide financial protection against hydrological risks for hydro generators, the MRE was implemented. This mechanism requires that hydroelectric generators in the SIN network, before buying or selling energy in the spot market to cover contractual shortfalls or manage surpluses as needed, first trade energy at a cheaper price in the MRE market. The price in the MRE market covers the incremental cost of operation, plant maintenance and financial compensation for use of water.  In Brazil, there are different hydrological conditions depending on the location.  The MRE permits sharing the hydrological risk and optimizing the integrated operations of all energy subsystems, while at the same time ensuring the optimal use of water. For our Brazilian operations, fuel and commodity prices are not relevant factors because power purchase agreements are indexed to the official inflation index (IPCA) and the gas price at Fortaleza is indexed mainly to local and U.S. consumer price indices.

In Colombia, 69% of the country’s capacity and more than 87% of our own installed capacity is hydroelectric; therefore, market prices are significantly affected by hydrological conditions.  Colombia has a wholesale market with an independent systems operator, XM S.A (a subsidiary of the state run energy company ISA). Within the Colombian wholesale market, power generation companies and all traders buy and sell energy within a regulatory framework established by the Energy and Gas Regulatory Commission (CREG). There is a short-term market, “Bolsa de Energía,” and a market for long‑term contracts. In the short-term market, traders offer prices based on daily forecasting, which take into account the different and constantly changing characteristics of the market. Therefore, electricity prices are highly volatile and, for example, could be affected by the expectation of El Niño’s arrival (dry context), which could raise prices suddenly. The long-term market provides agents with coverage against the volatility of energy prices in the short-term market. Our electricity supply contracts are not standardized and the terms and conditions of these contracts are individually negotiated. Typically, when these contracts are negotiated, we try to set the price at a premium over future expected spot prices in order to mitigate the risk of future price increases. However, the premium can vary substantially depending on a variety of conditions. Fuel and commodity prices are not relevant factors because electricity prices are indexed to the local consumer price index, IPP (Indice de Precios al Productor). The current contracted obligations are committed for periods of three to four years, which enables us to weather short-term trends and better achieve our projected costs, thereby reducing market risk exposure.

In Peru, 57 % of the country’s installed capacity and 60% of our own installed capacity is thermal. Therefore, electricity prices on the spot market are highly influenced by gas costs declared by thermal power plants. Peru produces its own gas and oil, which is a key factor in the development of the sector and the growth of the Peruvian economy, especially during the last decade. Over the years, the government’s oil and gas reforms have promoted private investment and maintained energy prices low. Until October 1, 2017, spot prices will be calculated based on restrictions to gas and transmission with a maximum price of US$95/MWh. Thereafter, marginal cost will not be limited and may eventually increase in some seasons of the year, predominantly between June and December, mainly due to hydrological conditions. Contracts with regulated customers are obtained through tenders and non-regulated customers through free negotiations. We have long-term supply contracts, for periods between 10 to 20 years. The proportion of contracted sales with regulated customers (distributors) has increased in relation to the non-regulated customers. This allows us to have consistent prices for longer periods, which combined with our conservative commercial policy, lowers our risk and provides stability to revenues.

Finally, variability in our earnings and cash flows can also arise from non-operating factors, such as foreign currency exchange rates. Operating results in each of the countries where we operate are first expressed in their own functional currencies and then are converted to Chilean pesos, the reporting currency used in our financial statements. As a result of exchange rate effects, operating result in Chilean pesos may differ significantly from those expressed in their own functional currencies. There may be cases in which we have a profit in local terms but a loss in Chilean accounting terms, and vice versa. On April 27, 2017, our shareholders approved the change of our functional currency from Chilean pesos to the U.S. dollar, with retroactive effect as of January 1, 2017.  We expect that the new currency translation effects will depend on the correlation between local currencies and the U.S. dollar, which is expected to improve compared to   the current correlation between local currencies and the Chilean peso.  If that is so, we would expect lower variability in our results. Based on the next 12 months’ forward rates available on Bloomberg, we do not anticipate significant impacts on results when converting Peruvian Sol and Colombian pesos to the U.S. dollar. However, we expect a significant impact (14% reduction) on results when converting Argentine pesos to U.S. dollars and a moderate impact (7% reduction) in the case of converting Brazilian reais to U.S. dollars. For more detail on how each of these factors impacts the net income of our electricity generation business, see “—A. Operating Results—1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company.”

We expect reasonably good operating performance during the coming years given the favorable macroeconomic perspective in Argentina, Colombia and Peru, which represented 12.9%, 50.8% and 17.9%, respectively, of our operating income as of December 31, 2016. The expected gross domestic product (GDP) growth in 2017 of Argentina, Brazil, Colombia and Peru are 3.0%, 0.5%, 2.4% and 3.6%, respectively. These percentages are based on Latin American Consensus Forecasts published by Consensus Economic Inc. on March 20, 2017. However, in Peru, the Minister of Economy cut the 2017 economic growth expectation to 3.0% due to the material damages caused by the flooding that occurred in March 2017. The annual electricity demand growth in 2017 of Argentina, Brazil, Colombia and Peru are expected to be 2.4%, (0.6) %, 2.9% and 6.6%, respectively.

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With respect to the development of new projects to increase our total installed capacity, efforts toward developing conventional energy projects have increased over time as a result of higher environmental standards and the scarcity of places for the location of plants coupled with significant opposition from different stakeholders, delaying their development and increasing their costs.  In the last couple of years, the cost of NCRE has decreased as a result of technological improvements, enabling smaller projects to become profitable while addressing distinct environmental standards across countries and social opposition to larger conventional generation. In addition, these technologies have shorter construction periods and their smaller size provides more flexibility for embracing changes in demand. The upcoming increase in development of NCRE plants will allow a more flexible approach toward energy management by players with a focus on operational efficiency from combining the different technologies. 

Enel, our ultimate controlling shareholder, announced in October 2015 that it will no longer build coal power plants because it considers the technology counterproductive to its goal of being carbon neutral by 2050. Closures of these coal power plants are scheduled at the end of their life cycles. The lost capacity will be likely be substituted by NCRE generation.

We routinely participate in energy bids and have been awarded long-term contracts. These contracts incorporate expected variable costs, taking into account changes in main variables, secure the sale of at least a portion of our current and expected new capacity and stabilize our income. Currently, 14.6% of our expected annual generation is sold under contracts with terms of at least ten years and an additional 18.8% are under contracts with terms of at least five years.

In connection with the distribution business tariffs, we anticipate that our companies will maintain their profitability during the periods between periodic tariff setting processes, according to the price cap tariff model, due to growth and economies of scale. After tariffs have been set, the companies have the opportunity to increase their efficiency, and obtain extra profits associated with such efficiencies, during the period subsequent to each new tariff setting.

In Argentina, the new government, which took office in December 2015, has been gradually implementing reforms to the current regulatory framework, increasing regulated tariff rates, which is expected to have a positive effect on our Argentine results. In Brazil, we expect stability in the real regulated tariff rates over the next few years. In Colombia, the distribution tariff is under revision and a new regulated tariff is expected in 2017. In Peru, we expect regulated tariff rates to remain stable over the next few years. Although the price at which a distribution company purchases electricity has an impact on the price at which it is sold to end customers, it does not have an impact on our profitability since the cost of electricity purchased is passed to end customers through tariffs. 

We expect to emphasize growth in the distribution business based on the development of new investments, especially in new technologies to automatize our networks and reach operational and economic efficiencies.

Although having operations in the four countries allows us to somewhat offset and counterbalance variations with respect to the main factors that can affect our operating results, our portfolio of assets is not fully hedged.  Any significant change in the factors already mentioned, among other factors, could affect our operating income. More broadly, any significant change with respect to economic or population growth, as well as changes in the regulatory regimes in the countries in which we operate, among other factors, could affect our operating income.

For further information regarding our 2016 results compared with those recorded in previous periods, please see “Item 5. Operating and Financial Review and Prospects — A. Operating Results —2. Analysis of Results of Operations for the Years Ended December 31, 2016 and 2015.” Investors should not look at our past performance as indicative of future performance.

E. Off-balance Sheet Arrangements.

We are not a party to any off-balance sheet arrangements.

F. Tabular Disclosure of Contractual Obligations.

The table below sets forth our cash payment obligations as of December 31, 2016:

	Payments due by Period
Ch$ billion	Total		2017		2018-2019		2020-2021		After 2021
Purchase obligations(1)		34,436		1,635		4,137		3,139		25,525
Local bonds(2)		1,519		262		447		197		613
Interest expense(3)		1,100		242		355		208		294
Bank debt		650		149		377		97		27
Pension and post-retirement obligations(4)		575		53		86		76		360
Yankee bonds		567		—		—		164		402
Financial leases		89		29		30		29		1

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Other debt(5)	42	10	6	6	19
Total contractual obligations	38,977	2,380	5,439	3,916	27,242

(1) Includes generation and distribution business purchase obligations which are comprised mainly of energy purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of Ch$ 34,436 billion, 91.0% corresponds to energy purchased for distribution, 5.9% corresponds primarily to fuel supply, maintenance of medium and low voltage lines, supplies of cable and utility poles, and energy purchased for generation. The remaining 3.1% corresponds to miscellaneous services, such as LNG regasification, fuel transport and coal handling.

(2) Net value, hedging instruments might substantially modify the outstanding amount of debt.

(3) Interest expenses are the interest payments for all outstanding financial obligations, calculated as principal multiplied by the interest rate, presented according to when the interest payment comes due.

(4) We have funded and unfunded pension and post-retirement benefit plans. Our funded plans have contractual annual commitments for contributions, which do not change based on funding status. Cash flow estimates in the table are based on such annual contractual commitments including certain estimable variable factors such as interest. Cash flow estimates in the table relating to our unfunded plans are based on future discounted payments necessary to meet all of our pension and post-retirement obligations.

(5) Other debt includes governmental loan facilities, supplier credits and short-term commercial paper among others.

G. Safe Harbor.

The information contained in the Items 5.E and 5.F contains statements that may constitute forward-looking statements. See “Forward-Looking Statements” in the “Introduction” of this Report, for safe harbor provisions.

Item 6.Directors, Senior Management and Employees

A. Directors and Senior Management.

Directors

Our Board of Directors consists of seven members who are elected for a three-year term at an Ordinary Shareholders’ Meeting (“OSM”). If a vacancy occurs in the interim, the Board of Directors elects a temporary director to fill the vacancy until the next OSM, at which time the entire Board of Directors will be elected. Our Executive Officers are appointed and hold office at the discretion of the Board of Directors.

The business address of our directors is c/o Enel Américas S.A., Santa Rosa 76, Santiago, Chile.

Our Board of Directors is as follows:

Directors	Position	Current Position Held Since
Borja Acha B.	Chairman		2015
José Antonio Vargas L.	Vice Chairman		2016
Domingo Cruzat A.	Director		2016
Livio Gallo	Director		2016
Patricio Gómez S.	Director		2016
Hernán Somerville S.	Director		2013
Enrico Viale	Director		2016

Set forth below are brief biographical descriptions of the members of our Board of Directors, of whom three reside in Europe, three in Chile and one in Colombia, as of December 31, 2016.

Borja Acha B.

Chairman of the Board of Directors

Mr. Acha serves as Secretary General, Secretary of the Board of Directors and Director of Legal Affairs and Corporate Matters of Endesa, S.A. in Spain. From 2012 to 2015, he served as Secretary and General Counsel of Enel.  From 1998 to 2013 Mr. Acha served as General Counsel of Endesa, S.A..  Prior to joining Enel, he served as Director of the Legal Department of Sociedad Estatal de Participaciones Industriales, an organization controlled by the Spanish government with the aim of promoting privatizations of state-owned public investments from 1997 to 1998, Secretary General, Secretary of the Board of  Directors  and General Counsel of the State Industrial Agency, an organization controlled by the Spanish government with the aim of implementing government guidelines on restructuring special schemes and partial derogations from community rules on competition from 1996 to 1997, Head of the Regional Legal Service of Madrid  at the Spanish Revenue Service from 1995 to 1996, state attorney for the State Legal Service of the

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High Court of Madrid from1991 to 1995 and professor of commercial law at Universidad Carlos III in Madrid from1991 to 1995. Mr. Acha holds a degree in law from the Universidad Complutense de Madrid (Madrid, Spain) and is a state attorney.

José Antonio Vargas L.

Vice Chairman of the Board of Directors

Mr. Vargas has served as Chairman of Codensa and Emgesa, our two Colombian subsidiaries, since 2006. He has more than 20 years of experience in the energy sector, especially in the gas, coal and electricity industries, and he served as director of several companies in the Colombian energy sector and public services.  From 1999 to 2006, he served as CEO of Empresa de Energía de Bogotá, an energy transmission company and prior to this served in the roles of  Chairman and Vice Chairman of the Commission and Regional Energy Integration, Chairman of the Colombian Committee and Vice Chairman for Latin America and Caribbean Countries of the World Energy Council,  Minister of the Colombian government, Ambassador of Colombia to the European Union, the Kingdom of Belgium and the Grand Duchy of Luxembourg and Trade Representative of the Colombian government in Spain and the Mediterranean Europe. Mr. Vargas holds a degree in law from Colegio Mayor de Nuestra Señora del Rosario (Bogotá, Colombia), specializing in business law, public services, administration and corporate finance.

Domingo Cruzat A.

Director and Member of the Directors’ Committee

Mr. Cruzat serves as Director of several companies, including Conpax, a construction company, Coprefrut, a fruit cooperative, Empresa de Servicios Sanitarios de Los Lagos, a water utility company, and Corporación Esperanza, a drug rehabilitation center. He is also a professor at the ESE Business School at the Universidad de Los Andes (Santiago, Chile). Prior to these roles, Mr. Cruzat served as Director of several private companies: Tech Pack S.A., a producer of flexible packaging, Viña San Pedro Tarapacá, a Chilean winery, Compañia Sud Americana de Vapores, a shipping company, Solfrut, a fruit company, Alto Inmobiliaria Plaza Santo Domingo, a real estate company, and Principal Financial Group. He also served as Chairman of the Public Companies System and CEO of both Watt’s Aliment, a food company, and Bellsouth Comunicaciones S.A., a telecommunication company. Mr. Cruzat holds a degree in civil engineering from the Universidad de Chile and a M.B.A. from the Wharton School at the University of Pennsylvania (Pennsylvania, USA).

Livio Gallo

Director

Mr. Gallo has served as Head of Infrastructure and Global Networks of Enel since July 2014. He is the Chairman of the Board of Directors of Enel Sole S.r.L., a public lighting provider as well as a Director of Endesa, S.A. and CESI S.p.A., a technical services provider for the power industry. Currently, Mr. Gallo is Vice Chairman of European Operators of Distribution Networks for Smart Grids Association and member of the Executive Committee of the Italian Electrotechnical Committee since 2006. From 2005 to June 2014, he served as Head of Enel’s Italian Infrastructure and Networks Division and CEO of Enel Distribuzione. In addition, from 2005 to 2013, he served as Chairman of the Board of Directors of Enel Rete Gas, a gas distributor and from 2005 to 2011, he served as CEO of Deval S.p.A., an electricity distributor. From 2002 to 2004, Mr. Gallo served as Head of Enel Distribuzione’s Commercial Department. Mr. Livio joined Enel in 1999 as Head of the Sales Department for Eurogen, Elettrogen e Interpower, a power generation company. Mr. Livio further served as CEO and Director of several Italian and foreign companies. Mr. Livio holds a degree in electronic engineering from the Politecnico di Milano (Milan, Italy).

Patricio Gómez S.

Director and Member of the Directors’ Committee

Mr. Gómez has served as an ExecutiveDirectorand Partnerof Sur CapitalPartners,a privateinvestment firm since 2005.He has served as a Board Memberof BOPackaging, a packagingcompany with businessesin Chile and Peru since 2013, El TejarLtda., an agriculturalcompany with businessesin Braziland Bolivia since 2007 and Nortel,a telecommunicationscompany since 2016. Healso servedas a Board Memberof Integramédica, a Chilean medicalcenter from 2001 to 2010,and TIBA,a satelliteserviceproviderfor the cableindustryin Latin America from 2000 to 2012.From 1999 to 2004, Mr. Gómez servedas Latin America’sManagingDirectorof GeneralElectric Capital– GEEquity, an investment fund. Mr. Gómez holds a degreein business administrationfromGeorge Mason University(Virginia,USA)and a M.B.A.fromGeorge WashingtonUniversity(WashingtonDC,USA).

Hernán Somerville S.

Director, Chairman and Financial Expert of the Directors’ Committee

Mr. Somerville has been a Director of Enel since 1999 and the Directors’ Committee’s Financial Expert since April 2013. Since 1989, he has served as the Managing Director and Partner of Fintec, a Chilean investment, advisory and management company. From 1992 to 2010, Mr. Somerville served as the Chairman of the Chilean Association of Banks and Financial Institutions. From 2000 to 2010, he was both a member of the Asia-Pacific Economic Cooperation (APEC) and the Chairman of the Chilean Pacific Foundation, a Chilean foundation with connections to Pacific Ocean countries. In addition, he was Chairman of the Latin American Federation of Banks from 1994 to 1996. From 1983 to 1988, he was Director of the Chilean Central Bank, serving as Chief Debt Negotiator for

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Chilean public and private commercial bank debt. Mr. Somerville has further served in the roles of Chairman of CPC, the Chilean Confederation of Production & Commerce, and Transbank S.A., which manages credit and debit cards in Chile, and Board Member of INACAP, a Chilean vocational school. Mr. Somerville holds a law degree from the Universidad de Chile and a masters’ degrees from both Yale University (Connecticut, USA) and New York University Law School (New York, USA).

Enrico Viale

Director

Mr. Viale serves as Director of Enel Global Generation. Until April 2016, he was Chairman of the Board of Directors of Enel Generación Chile. From 2008 to 2014, he served as Chief Operating Officer of Enel, managing our interest in OGK-5 and Rusenergosbyt and supporting SeverEnergia’s upstream gas operations, before becoming Country Manager and CEO of Enel Russia. Mr. Viale joined Enel in 2003 as Country Manager for Southeastern Europe and has taken on diverse positions within Enel subsidiaries, such as CEO of Enel Maritza East 3. Before joining the Company, he served as Vice Chairman of ABB, a global technology provider for the structured finance business, which finances equipment for projects. He was also assumed the role of CFO of Ansaldo Energía, an Italian power generation plant provider, among various other finance positions. Mr. Viale holds a civil engineering degree with a specialization in hydraulic engineering from the Polytechnic University of Turin (Turin, Italy) and a M.B.A. from the University of Santa Clara Business School (California, USA).

Executive Officers

Set forth below are our Executive Officers as of December 31, 2016.

The business address of our Executive Officers is c/o Enel Américas S.A., Santa Rosa 76, Santiago, Chile.

Executive Officers	Position	Current Position Held Since
Luca D’Agnese	Chief Executive Officer		2015
Antonio Barreda T.	Procurement Officer		2015
Raffaele Cutrignelli	Internal Audit Officer		2016
Marco Fadda(1)	Planning and Control Officer		2013
Javier Galán A.	Chief Financial Officer		2014
Francesco Giorgianni	Institutional Affairs Officer		2014
José Miranda M.	Communications Officer		2014
Alain Rosolino	Human Resources Officer		2016
Domingo Valdés P.	General Counsel		1999

(1) Mr. Fadda left Enel Américas and was replaced by Emanuele Brandolini in January 2017.

Set forth below are brief biographical descriptions of our Executive Officers, all of whom reside in Chile.

Luca D’Agnese has served as our CEO since January 2015. In 2014, he became Director of the Eastern European Division as well as Chairman of the Board of Directors and CEO of Slovenské Elektrárne, an Enel subsidiary in the Slovak Republic. Mr. D’Agnese joined Enel in 2011 as Country Manager of Romania. From 2007 to 2010, he served as CEO of Ergycapital, an Italian investment company listed on the Milan Stock Exchange specializing in renewable energy. In 2006, he served as Head of Operations at Terna, an Italian electricity transmission grid operator, which absorbed Gestore della Rete di Transmissione Nazionale (GRTN), an Italian transmission company, for which Mr. D’Agnese served as CEO from 2003 to 2005. Mr. D’Agnese holds a degree in physics from the Scuola Normale Superiore di Pisa (Pisa, Italy) and a M.B.A. from INSEAD business school (Fontainebleau, France).

Antonio BarredaT. has served as our Procurement Officer since January 2015 and as the Procurement Officer of Enel Chile since February 2016. From 2008 to 2014, he served as Deputy Director of Works and Services Latam. From 2001 to 2008, he served as Deputy Director of both Business Relations Providers and of Corporate Service Purchases at Enel Américas. From 2000 to 2001, Mr. Barreda served as Contracts Manager for CAM, a former subsidiary of Enel Américas. Mr. Barreda holds a degree in electrical engineering from Universidad de Santiago and a M.B.A.from Pontificia Universidad Católica de Chile.

Raffaele Cutrignelli has served as our Internal Audit Officer since October 2016 and serves in the same position for Enel Chile. From February 2015 to October 2016, Mr. Cutrignelli served as Audit Officer for Codensa and Emgesa, Enel Américas’ subsidiaries in Colombia. From January 2013 to January 2015, Mr. Cutrignelli served as Head of Latin America Audit for Enel Green Power in Brazil, and from January 2011 to December 2012, served in a comparable position for Enel Green Power in the United States. From October 2008 to December 2010, Mr. Cutrignelli served as Internal Audit Manager of Enel OGK-5 in Moscow, Russia. Mr. Cutrignelli holds a degree in international business at Nottingham Trent University (Nottingham, United Kingdom) and a master’s degree in audit and internal controls from Universitá di Pisa (Pisa, Italia).

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Marco Fadda was our Planning and Control Officer from April 2013 to January 2016. He served as Head of Planning and Control of Energy Business from May 2009 to March 2013 and Head of Planning and Control of Power Business from July 2008 to April 2009 for Generation & Energy Management Division at Enel Produzione.He joined Enel in 1998 and has held several roles within the Planning and Control Division. Mr. Fadda holds a degree in economics from the Università degli Studi di Genova (Genoa, Italy) and a masters’ degree in business administration from Polytecnico di Milano (Milan, Italy).  

Javier Galán A. has served as our CFO since December 2014. From 2013 to 2014, Mr. Galán served as CFO of an Enel division in Italy. From 2006 to 2013, he served as Head of Finance of Endesa Spain. In 1993, Mr. Galán became CFO of Endesa Desarrollo, a subsidiary of Endesa Spain, where he initiated the international expansion of Endesa Spain’s operations, mainly in Latin America and has held various managerial positions within the group in Finance, Planning and Control, Strategy, and M&A, and served on several Boards of Directors. He joined Endesa Spain as International Operations Officer in 1992. Before joining Endesa Spain, Mr. Galán worked in the Corporate Finance Department at Chase Manhattan Bank, N.A. in London and in Madrid, and as Treasurer of Red Eléctrica de España S.A., the operator of the Spanish electricity system. Mr. Galán holds an economics degree from Universidad Complutense de Madrid (Madrid, Spain) and a M.B.A. from the Instituto de Empresas de Madrid (Madrid, Spain) and a graduate degree in Senior Management from the IESE Business School (Madrid, Spain).

Mr. Giorgianni has been our Institutional Affairs Officer since 2014 and Head of Enel’s Institutional Affairs worldwide since 2011. From 2007 to 2011, he served as Head of Enel’s European and Italian Institutional Affairs in Rome. From 2004 to 2007, he served as Head of European Institutional Affairs as a representative of Enel in Brussels. From 2000 to 2004, he held the role of Head of Regulatory and Antitrust Policies at Enel. Mr. Giorgianni holds a degree in law from the Università di Roma La Sapienza (Rome, Italy), a master’s degree in public administration from the Scuola Nazionale dell’Amministrazione (Rome, Italy), and a graduate degree from the London Business School (London, England).

José Miranda M. has been our Communications Officer since December 2014 and Enel Chile’s Communications Officer since February 2016. Before joining the Company, Mr. Miranda worked for 11 years for Televisión Nacional de Chile (TVN), a Chilean TV channel, as producer of many shows, covering both national and international events. From 2011 to November 2014, Mr. Miranda was General Producer of the Entertainment Area and Executive Producer in charge of International and National Business Content. From 2008 to 2010, he served as the General Producer of the Chilean news channel “Canal 24 Horas,” another TVN channel. Mr. Miranda is an Audiovisual Communicator and earned a degree from DUOC UC (Santiago, Chile) and a graduate degree in management from Universidad de Chile.

Alain Rosolino has been our and Enel Chile’s Human Resource Officer since his appointment in October 2016. Prior to these roles, he served as our Internal Audit Officer since February 2016 and also was the Internal Audit Officer of Enel Américas since December 2012. He joined Enel in 2003, and held several positions in the audit area at Enel, Enel Romania, Enel Green Power, Enel Latin America, and from 2011 to 2012, at Enel EGP IBAL (Iberian Peninsula and Latin America). Mr. Rosolino holds a degree in business administration from Libera Università Internazionale degli Studi Sociali Guido Carli (Rome, Italy).

Domingo Valdés P. has been our General Counsel since May 1999 and Enel Chile’s General Counsel since March 2016. Mr. Valdés further serves as Secretary of Enel Chile and Enel Américas’ Board of Directors and is a Professor of Economic and Antitrust Law at the Universidad de Chile. He joined Enel Distribución Chile in 1993 and Enel Américas in 1997. Mr. Valdés held the role of intern for the New York City law firms of Milbank, Tweed, Hadley & McCloy LLP and Chadbourne & Parke LLP. Before joining Enel Distribución Chile, Mr. Valdés was a lawyer for the Corporate Department of Chase Manhattan Bank, N.A. in Chile and an associate of Carey & Cía., a Santiago based law firm. Mr. Valdés holds a law degree from the Universidad de Chile and a masters’ degree in law from the University of Chicago (Illinois, USA).

Emanuele Brandolini has been our Planning and Control Officer since January 2017. Prior to this role, he served as Head of Planning and Control at Enel Green Power from 2015 to 2016, Head of Planning and Control at Enel Distribuzione from 2013 to 2014, Head of Investments Control and Valuation of M&A Initiatives at Enel SpAfrom 2010 to 2013 and Head of International Business Initiatives Valuation at Enel International from 2006 to 2010. Before joining Enel in 2006, he held the role of Analyst, responsible for economic and financial analyses for the Refining Business Division at ERG Petroli S.p.a., an Italian seller of oil products and as Consultant for Accenture S.p.a. Mr. Brandolini holds a degree in industrial engineering from the Università degli Studi Tor Vergata (Rome, Italy) and a M.B.A. from SDA Bocconi School of Management (Milan, Italy).

To the best of our knowledge there is not any relationship between any of the persons named above.

B. Compensation.

At the OSM held on April 28, 2016, our shareholders approved the current compensation policy for our Board of Directors. Directors are paid an annual variable fee equivalent to 0.1% of our net earnings for the current year based on the consolidated financial statements. Directors are also paid a monthly fee, in advance, depending on their attendance at Board meetings and their

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participation as Director of any of our subsidiaries. Director compensation consists of a monthly fixed compensation of UF 180 per month and an additional fee of UF 66 per meeting, depending on attendance to Board meetings. The monthly fixed fees are considered as advances on the annual variable fee and creditable against that amount. Once our net earnings are approved at the OSM of the following year, the difference between the accrued annual variable fee and the total fees paid in advance will be paid to directors, but only if the resulting amount is positive. The Chairman of the Board is entitled to double the compensation compared to other directors under this policy, while the Vice Chairman receives fixed compensation higher than the directors but lower than the Chairman. The members of our Directors’ Committee are paid a variable annual fee, equivalent to a percentage of our net earnings of the current year. If a Director serves on one or more Boards of Directors of the subsidiaries and/or related companies or serves as director of other companies or corporations in which the economic group holds an interest directly or indirectly the Director can only receive compensation in one of these Boards of Directors. Executive Officers of our Company and/or of our subsidiaries or related companies will not receive compensation in the case that they serve as Director of any subsidiary, related company or are affiliated in any way to our Company.

In 2016 the total compensation paid to each of our directors, including fees for attending Directors’ Committee meetings was as follows: 

	Year ended December 31, 2016
Director	Fixed Compensation		Variable Compensation(1)	Directors’ Committee		Total
	(in Th Ch$)
Borja Acha B(2)	—		—	—			—
José Antonio Vargas L(2)	—		—	—			—
Domingo Cruzat A.		71,676	—		23,892		95,568
Livio Gallo(2)	—		—	—			—
Patricio Gómez S.		71,676	—		23,892		95,568
Hernán Somerville S.		92,362	—		30,783		123,145
Enrico Viale(2)	—		—	—			—
Herman Chadwick P.(3)		25,349	—		8,445		33,794
Rafael Fernández M.(3)		25,349	—		8,445		33,794
Total		286,412	—		95,457		381,869

(1) Includes any positive balance against the annual variable fee paid in advance. In 2016, the balance was negative thus, there was no additional variable compensation.

(2) Messrs. Acha, Gallo and Viale waived their compensation for their positions as Director.

(3) Messrs. Chadwick and Fernández ceased to be Directors on April 28, 2016.

We do not disclose, to our shareholders or otherwise, any information about an individual Executive Officer’s compensation. For the year ended December 31, 2016, the aggregate gross compensation, paid or accrued, for all our Executive Officers, attributable to fiscal year 2016, was Ch$ 3,548 million in fixed compensation and Ch$ 57 million in variable compensation and includes only the variable remuneration directly paid by the Company since some Executive Officers are paid through our related companies.. Executive Officers are eligible for variable compensation under a bonus plan. The annual bonus plan is paid to our Executive Officers for achieving company-wide objectives and for their individual contribution to our results and objectives. The annual bonus plan provides for a range of bonus amounts according to seniority level and consists of a certain multiple of gross monthly salaries.

We entered into severance indemnity agreements with all of our Executive Officers, pursuant to which we will pay a severance indemnity in the event of voluntary resignation or termination by mutual agreement among the parties. The severance indemnity does not apply if the termination is due to willful misconduct, prohibited negotiations, unjustified absences or abandonment of duties, among other causes, as defined in Article 160 of the Chilean Labor Code. All of our employees are entitled to legal severance pay if terminated due to our needs, as defined in Article 161 of the Chilean Labor Code.

C. Board Practices.

Our Board of Directors in office as of December 31, 2016 was elected at the OSM held on April 28, 2016, for a three-year term which ends in April 2019. For information about each of the directors and the year that they began their service on the Board of Directors, see “Item 6. Directors, Senior Management and Employees — A. Directors and Senior Management— Directors” above. Members of the Board of Directors do not have service contracts with us or with any of our subsidiaries that provide them benefits upon termination of their service.

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Corporate Governance

We are managed by a Board of Directors, in accordance with our by-laws, consisting of seven directors who are elected by our shareholders at an OSM. Each director serves for a three-year term. Following the end of their term, they may be re-elected or replaced. Directors can be re-elected indefinitely. Staggered terms are not permitted under Chilean law. If a vacancy occurs on the Board of Directors during the three-year term, the Board of Directors may appoint a temporary director to fill the vacancy. Any vacancy triggers an election for every seat on the Board of Directors at the next OSM.

Chilean corporate law provides that a company’s Board of Directors is responsible for the management and representation of a company in all matters concerning its corporate purpose, subject to the provisions of the company’s by-laws and the shareholders resolutions. In addition to the by-laws, our Board of Directors has adopted regulations and policies that guide our corporate governance principles.

Our corporate governance policies are included in the following policies or procedures: the Charter Governing Executives, the Employee Code of Conduct, the Manual for the Management of Information of Interest to the Market” (the “Manual”), the Human Rights Policy (Política de Derechos Humanos), the Code of Ethics and a Zero Tolerance Anti-Corruption Plan (“ZTAC Plan”), the Penal Risk Prevention Model, the “Guidelines 231: Guidelines applicable to non-Italian subsidiaries in accordance with Legislative Decree 231 of June 8, 2001” (the “Guidelines 231”) and procedures issued in compliance with General Regulation 385 issued by the SVS.

The Charter Governing Executives, approved by our Board on May 28, 2003, and the Employee Code of Conduct, explain our principles and ethical values, establish the rules governing our contact with customers and suppliers, and establish the principles that should be followed by employees, including ethical conduct, professionalism and confidentiality. They also impose limitations on the activities that our executives and other employees may undertake outside the scope of their employment with us.

In order to ensure compliance with Securities Market Law 18,045 and SVS regulations, our Board of Directors approved the Manual at its meeting held on May 28, 2008. This document addresses applicable standards regarding the information in connection with transactions of our securities and those of our affiliates, entered into by directors, management, principal executives, employees and other related parties, the existence of blackout periods for such transactions undertaken by directors, principal executives and other related parties, the existence of mechanisms for the continuous disclosure of information that is of interest to the market and mechanisms that provide protection for confidential information. The Manual was released to the public in 2008, and is posted on our website at www.enelamericas.cl. In 2010, the Manual was modified in order to comply with the provisions of Law 20,382 (Corporate Governance Improvement Law). The provisions of this Manual apply to the members of our Board, as well as our executives and employees who have access to confidential information, and especially those who work in areas related to the securities markets.

Our Board of Directors approved a procedure for relationship between People Politically Exposed (Procedimiento Personas Políticamente Expuestas y Conexas) and our Company, which established a specific regulation for their commercial and contractual relationships.

The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into the corporate reality.

In order to supplement the aforementioned corporate governance regulations, our Board of Directors approved a Code of Ethics and the ZTAC Plan at its meeting held on June 24, 2010. The Code of Ethics is based on general principles such as impartiality, honesty, integrity and other ethical standards of similar importance, all of which are expected from our employees. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with special emphasis on avoiding corruption in the form of bribes, preferential treatment, and other similar matters. At its meeting held on January 19, 2017, our Board of Directors approved an amendment to the Code of Ethics and ZTAC Plan to eliminate the reference to Law 19,885 in connection with  political donations and to  forbid political donations altogether.

At its meeting held on March 29, 2011, our Board approved the Penal Risk Prevention Model in order to comply with Law 20,393 of December 2, 2009, which imposes criminal responsibility on legal entities for the crimes of asset laundering, financing of terrorism and bribing of public officials. The law encourages companies to adopt this model, whose implementation involves compliance with managerial and supervision duties. The adoption of the Penal Risk Prevention Model mitigates, and in some cases relieves, the effects of criminal responsibility even when a crime is committed. 

At its meeting held on October 28, 2016, our Board approved “The Global Compliance Program on Corporate Penal Liability”, which was incorporated into the Penal Risk Prevention Model to reflect current standards, and appointed Mr. Rafael Cutrignelli as our Penal Risk Prevention and Global Compliance Program for Corporate Penal Liability Officer as required by the Penal Risk Prevention Model. Mr. Cutrignelli also serves as Internal Audit Officer for both Enel Chile and Enel Américas.

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On October 27, 2010, our Board of Directors approved the Guidelines 231. The Guidelines 231 is defined by Italian Legislative Decree. 231, which was enacted on June 8, 2001. It establishes a compliance program that identifies the behaviors expected of related parties for the non-Italian subsidiaries of Enel. Given that our ultimate controlling shareholder, Enel, complies with Italian Legislative Decree 231, which establishes management responsibility for Italian companies as a consequence of certain crimes committed in Italy or abroad, in the name of or for the benefit of such entities, including those crimes described in Chilean Law 20,393, these guidelines set a group of measures, with standards of behavior expected from all employees, advisers, auditors, officials, directors as well as consultants, contractors, commercial partners, agents and suppliers. Legislative Decree 231 includes various activities of a preventive nature that are coherent with and integral to the requirements and compliance with Chilean Law 20,393, which deals with the criminal responsibility of legal entities. These guidelines are supplementary to the standards included in the Code of Ethics and the ZTAC Plan.

On November 29, 2012, the SVS issued General Regulation 341 which established regulations for the disclosure of information with respect to the standards of corporate governance compliance adopted by publicly held limited liability corporations and set the procedures, mechanisms and policies that are indicated in the Appendix to the regulation. The objective of this regulation is to provide credible information to investors with respect to good corporate governance policies and practices adopted by publicly held limited liability corporations, which include us, and permit entities like stock exchanges to produce their own analyses to help the various market participants to understand and evaluate the commitment of companies. General Regulation 341 was substituted by General Regulation 385, issued by the SVS on June 8, 2015. This regulation has similar objectives than the former General Regulation 341, but includes additional issues; by the way of separating each policy in several more detailed policies. Subjects such as non-discrimination, inclusion and sustainability are particularly important in this new regulation. The Appendix of General Regulation 385 is divided into the following four sections with respect to which companies must report the corporate practices that have been adopted: (i) the functioning and composition of the board, (ii) relations between the company, shareholders and the general public, (iii) risk management and control, and (iv) assessment by a third party. Publicly held limited liability corporations should send the information with respect to corporate governance practices to the SVS no later than March 31 of each year, using the contents of the Appendix to this regulation as criteria. If none of them is adopted, the company must explain its reasons to the SVS. The information should refer to December 31 of the calendar year prior to its dispatch. At the same time, such information should also be at the public’s disposal on the company’s website, and must be sent to the stock exchanges.

Compliance with the New York Stock Exchange Listing Standards on Corporate Governance

The following is a summary of the significant differences between our corporate governance practices and those applicable to U.S. domestic issuers under the corporate governance rules of the NYSE.

Independence and Functions of the Directors’ Committee (Audit Committee)

Chilean law requires that at least two thirds of the Directors’ Committee be independent directors. According to Chilean law, a member would not be considered independent if, at any time, within the last 18 months he (i) maintained any relationship of a relevant nature and amount with the company, with other companies of the same group, with its controlling shareholder or with the principal officers of any of them or has been a director, manager, administrator or officer of any of them; (ii) maintained a family relationship with any of the members described in (i) above; (iii) has been a director, manager, administrator or principal officer of a non-profit organization that has received contributions from (i) above; (iv) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of an entity that has provided consulting or legal services for a relevant consideration or external audit services to the persons listed in (i) above; and (v) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of the principal competitors, suppliers or customers. In case there are not sufficient independent directors on the Board to serve on the Directors’ Committee, Chilean law determines that the independent director nominates the rest of the members of the Directors’ Committee among the remaining Board members that do not meet the Chilean law independence requirements. Chilean law also requires that all publicly held limited liability stock corporations that have a market capitalization of at least UF 1,500,000 (Ch$ 39.5 billion as of December 31, 2016) and at least 12.5% of its voting shares are held by shareholders that individually control or own less than 10% of such shares, must have at least one independent director and a Directors’ Committee.

Under the NYSE corporate governance rules, all members of the Audit Committee must be independent. The Audit Committee of a U.S. company must perform the functions detailed in, and otherwise comply with the requirements of NYSE Listed Company Manual Rules 303A.06 and 303A.07. As of July 31, 2005, non-U.S. companies have been required to comply with Rule 303A.06, but not with Rule 303A.07. Since July 31, 2005, we have complied with the independence and the functional requirement of Rule 303A.06.

On June 29, 2005, our Board of Directors created an Audit Committee, composed of three directors who were also members of the Board of Directors, as required by the Sarbanes-Oxley Act (“SOX”) and the NYSE corporate governance rules. On April 22, 2010,

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at an Extraordinary Shareholders’ Meeting (“ESM”), our by-laws were amended and the Audit Committee was merged with the Directors’ Committee.

Pursuant to our by-laws, all members of the Directors’ Committee must satisfy the requirements of independence, as stipulated by the NYSE. The Directors’ Committee is composed of three members of the Board and complies with Chilean law, as well as with the criteria and requirements of independence prescribed by the SOX, the SEC and the NYSE. As of the date of this Report, the Directors’ Committee complies with the conditions of the Audit Committee as required by the SOX, the SEC and the NYSE corporate governance rules. As a result, we have a single Committee, the Directors’ Committee, which includes among its functions the duties performed by the Audit Committee.

Our Directors’ Committee performs the following functions:

• review of financial statements and the reports of the external auditors prior to their submission for shareholders’ approval;

• present proposals to the Board of Directors, which will make its own proposals to shareholders’ meetings, for the selection of external auditors and private rating agencies;

• review of information related to our transactions with related parties and reports the opinion of the Directors’ Committee to the Board of Directors;

• the examination of the compensation framework and plans for managers, executive officers and employees;

• the preparation of an Annual Management Report, including its main recommendations to shareholders;

• provide information to the Board of Directors about the convenience of recruiting external auditors to provide non-auditing services, when such services are not prohibited by law, depending on whether such services might affect the external auditors’ independence;

• oversee the work of external auditors;

• review and approval of the annual auditing plan by the external auditors;

• evaluate the qualifications, independence and quality of the auditing services;

• elaborate on policies regarding employment of former members of the external auditing firm;

• review and discuss problems or disagreements between management and external auditors regarding the auditing process;

• establish procedures for receiving and dealing with complaints regarding accounting, internal control and auditing matters;

• any other function mandated to the committee by the by-laws, our Board of Directors or our shareholders.

Corporate Governance Guidelines

The NYSE’s corporate governance rules require U.S.-listed companies to adopt and disclose corporate governance guidelines. Chilean law provides for this practice through the disclosure of the procedures related to the General Resolution 385 and the Manual. We have also adopted the codes of conduct described above, and at our ESM held in March 2006, we approved the inclusion of provisions in our by-laws that govern the creation, composition, attributions, functions and compensation of both Directors’ and Audit Committees described above.

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D. Employees.

The following table sets forth the total number of our personnel (both permanent and temporary employees) and the number of personnel (both permanent and temporary employees) of each of our consolidated subsidiaries as of December 31, 2016, 2015 and 2014, assuming that the Spin-Offs had been completed as of December 31, 2015:

Company	2016	2015	2014
Argentina
Costanera	470	485	485
El Chocón	58	47	49
Edesur	4,297	4,157	3,823
Enel Trading Argentina	17	16	13
Dock Sud	88	84	69
CTM and TESA	5	5	5
Total personnel in Argentina	4,935	4,794	4,444
Brazil
Cachoeira Dourada	82	79	76
Fortaleza	66	76	70
CIEN	37	39	62
Ampla(1)	1,103	1,217	1,202
Coelce	1,140	1,186	1,213
Enel Brasil	71	62	72
Total personnel in Brazil	2,499	2,659	2,695
Chile
Enel Américas	62	87	—
Total personnel in Chile	62	87	—
Colombia
Emgesa	558	510	589
Codensa	1,340	1,034	1,043
Total personnel in Colombia	1,898	1,544	1,632
Peru
Enel Generación Perú	256	260	268
Enel Distribución Perú	620	610	619
Enel Generación Piura	52	56	56
Generalima	2	5	8
Total personnel in Peru	930	931	951
Total personnel	10,324	10,015	9,722

(1) Includes Enel Soluções S.A.

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The following table sets forth the total number of our temporary employees and the number of temporary employees of each of our consolidated subsidiaries as of December 31, 2016, 2015 and 2014 and the average during the most recent financial year, assuming that the Spin-Offs had been completed as of December 31, 2015:

Company	Average2016			2016	2015	2014
Argentina
Costanera		9		9	1	18
El Chocón		12		11	2	3
Edesur		126		123	15	14
Enel Trading Argentina		1		1	1	1
Dock Sud	—		—		—	6
Total temporary personnel in Argentina		148		144	19	42
Brazil
CIEN		—		—	—	1
Total temporary personnel in Brazil		—		—	—	1
Colombia
Emgesa		92		101	44	92
Codensa		176		240	108	40
Total temporary personnel in Colombia		268		341	152	132
Peru
Enel Generación Perú		21		21	24	26
Enel Distribución Perú		53		53	42	62
Enel Generación Piura		2		3	3	3
Generalima		2		1	3	4
Total temporary personnel in Peru		78		78	72	95
Total temporary personnel		494		563	243	270

Chile

All Chilean employees who are dismissed for reasons other than misconduct are entitled by law to a severance payment. According to Chilean law, employees holding contracts of indefinite duration are entitled to a basic payment of one-month’s salary for each year worked, subject to a limit of a total payment of a maximum of 11 months’ pay for employees hired after August 14, 1981. Severance payments to employees hired prior to that date consist of one-month’s salary for each full year worked, not subject to any maximum limitation. Under our collective bargaining agreements, we are obligated to make severance payments to all covered employees in cases of voluntary resignation or death in specified amounts that increase according to seniority and may exceed the amounts required under Chilean law.

We have two collective bargaining agreements. The first one was signed in July 2015 and it will be in force until July 2019. The second one was signed in January 2016 and will expire in December 2019.

Argentina

Edesur has two collective bargaining agreements, both of which expired in 2007 and are still in the renegotiation process. El Chocón has two collective bargaining agreements, one of which expires in December 2016, and the other has already expired and is in process of renegotiation. Costanera has two collective bargaining agreements, both of which expired in 2014 and are in process of renegotiation.

Under Argentine law, the working conditions under the expired agreements continue until the signing of a new agreement, under the principle of ultra-activity established by Law 14,250 (Art. 12).

The result of collective bargaining agreements is subject to the result of the negotiations between companies and trade union federations, with regards to wage increases and the incorporation of contracted workers into the workforce of the companies. 

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Brazil

Ampla has five collective bargaining agreements, four of which will expire in September 2017 and the other in October 2018. Coelce has two collective bargaining agreements, one of which will expire in September 2017 and the other in October 2018.

CIEN has three collective bargaining agreements, one of which will expire in April 2017, one in September 2017 and the other in October 2018. Cachoeira Dourada has three collective bargaining agreements, one of which will expire in April 2017, one in September 2017 and the other in October 2018.

Fortaleza has two collective bargaining agreements, one of which will expire in April 2017 and the other in September 2017.

Under Brazilian law, collective bargaining agreements cannot last for more than two years.

Colombia

Codensa has two collective bargaining agreements, one of which will expire on June 30, 2018 and the other on December 31, 2019. Emgesa has two collective bargaining agreements, one of which will expire on June 30, 2018 and the other on December 31, 2019.

Under Colombian labor law, pre-existing collective bargaining agreements are automatically renewed until a new agreement is in force.

Peru

Enel Distribución Perú has two collective bargaining agreements that expired in December 2016 and are currently in the renegotiation process. Enel Generación Perú has one collective bargaining agreement, which will expire in December 2017. Enel Generación Piura has one collective bargaining agreement that expires in December 2017.

E. Share Ownership.

To the best of our knowledge, none of our directors or officers owns more than 0.1% of our shares or owns any stock options. It is not possible to confirm whether any of our directors or officers has a beneficial, rather than direct, interest in our shares. To the best of our knowledge, any share ownership by all of our directors and officers, in the aggregate, amounts to significantly less than 10% of our outstanding shares.

Item 7.Major Shareholders and Related Party Transactions

A. Major Shareholders.

We have only one class of capital stock and Enel, our ultimate controlling shareholder, has no different voting rights than our other shareholders. As of April 27, 2017, our 58,324,975,387 shares of common stock outstanding (including treasury stock) were held by 24,364 stockholders of record. There were six record holders of our ADSs as of such date.  As of April 21, 2017, Enel owned a total of 29,762,213,531 of the 58,324,975,387 shares of our common stock then outstanding.  We reacquired 872,333,871 shares as treasury stock in connection with the 2016 Reorganization, and such treasury stock will be cancelled as a result of the approval of such cancellation by shareholders at the ESM held on April 27, 2017.  

It is not practicable for us to determine the number of ADSs or common shares beneficially owned in the United States, as the depositary for our ADSs only has knowledge of the record holders, including the Depositary Trust Company and its nominees. As such, we are not able to ascertain the domicile of the final beneficial holders represented by the six ADS record holders in the United States. Likewise, we cannot readily determine the domicile of any of our foreign stockholders who hold our common stock, either directly or indirectly.

Enel has been our ultimate controlling shareholder since June 2009. On October 23, 2014, Endesa, S.A., a Spanish subsidiary of Enel, sold its interest in Enel Américas to Enel Iberoamérica, a wholly-owned Spanish subsidiary of Enel, resulting in Enel owning 60.6% of Enel Américas at that time. In December 2016, Enel Iberoamérica absorbed Enel Latinoamérica through a merger. As a result of these transactions together with the 2016 Reorganization, and the expected cancellation of treasury stock, Enel will own 51.8% of Enel Américas through Enel Iberoamérica. For further details related to the 2016 Reorganization, please refer to “Item 4. Information on the Company — A. History and Development of the Company — The 2016 Reorganization.”

As of March 31, 2017, Chilean private pension funds (AFPs), owned 14.5% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 20.3% of our

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shares. ADS holders owned 9.8% of our shares, treasury shares accounted for 1.5% and the remaining 2.9 % of our shares were held by 24,190 minority shareholders.

The following table sets forth certain information concerning ownership of the common stock as of April 27, 2017, with respect to each stockholder known by us to own more than 5% of the outstanding shares of common stock:

	Number of Shares Owned	Percentage ofShares Outstanding
Enel Iberoamérica(1)	29,762,213,531		51.0	%

(1) Enel Iberoamérica is wholly-owned by Enel.

Enel is an Italian energy company with multinational operations in the power and gas market with a focus on Europe and Latin America. Enel operates in over 30 countries across four continents, produces energy through a net installed capacity of 84 GW and distributes electricity and gas through a network covering 1.9 million kilometers. With over 61 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enel publicly trades on the Milan Stock Exchange.

B. Related Party Transactions.

Article 146 of Law 18,046 (the “Chilean Companies Act”) defines related-party transactions as all transactions involving a company and any entity belonging to the corporate group, its parent companies, controlling companies, subsidiaries or related companies, board members, managers, administrators, senior officers or company liquidators, including their spouses, some of their relatives and all entities controlled by them, in addition to individuals who may appoint at least one member of the company’s board of directors or who control 10% or more of voting capital, or companies in which a board member, manager, administrator, senior officer or company liquidator has been serving in the same position within the last 18 months. The law establishes that in the event that these persons fulfill the requirements established by Article 146, such persons must immediately inform the Board of Directors of their related-party nature or such other group as the Board may appoint for that purpose. As required by law, “related-party transactions” must comply with corporate interests, as well as prices, terms and conditions prevailing in the market at the time of their approval. They must also meet all legal requirements, including acknowledgement and approval of the transaction by the Board of Directors (excluding the affected directors), by the ESM (in some cases, with requisite majority approval) and by any applicable regulatory procedures.

The aforementioned law, which also applies to our affiliates, also provides for some exceptions, stating that in certain cases, Board approval would suffice for “related-party transactions,” pursuant to certain related-party transaction thresholds and when such transactions are conducted in compliance with the related-party policies defined by the company’s board. At its meeting held on April 23, 2010, our Board of Directors approved a related-party transaction policy (política de habitualidad). This policy is available on our website at www.enelamericas.cl.

If a transaction is not in compliance with Article 146 of the Chilean Companies Act, this would not affect the transaction’s validity, but we or our shareholders may demand compensation from the individual associated with the infringement as provided under law, and reparation for damages.

It is our policy that all cash inflows and outflows of our foreign affiliates are managed through our centralized cash management policy. It is a common practice in Chile to transfer surplus funds from one company to another affiliate that has a cash deficit. These transfers are carried out through either short-term transactions or through structured inter-company loans. Under Chilean laws and regulations, such transactions must be carried out on an arm’s-length basis. All of these transactions will be subject to the supervision of our Directors’ Committee. As of April 25, 2017, these transactions were priced at TIP (a Chilean variable interest rate) plus 0.05% per month.

In the countries in which we operate, we do not manage the cash flows of our subsidiaries even when inter-company transactions are permitted; however these may have adverse tax consequences.

During 2016, Enel Generación Chile repaid in full to us a structured loan of US$ 250 million with a fixed annual interest rate of 1.38%.

In March 2016, we guaranteed Ampla’s US$ 75 million three-year term loan with a third party. 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.

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In July 2016, in the context of the financial support provided to our Brazilian subsidiary Ampla, the Chilean shareholders of Enel Brasil (which at the time of the transaction included Endesa Américas, Chilectra Américas, Chilectra Inversud and us) granted intercompany loans to Enel Brasil in order to provide financial stability to the group in Brazil. Following the consummation of the merger of the abovementioned companies with and into Enel Américas, we are the only creditor of the intercompany loans, which as of April 25, 2017 amounted to Br$ 169 million plus accrued interests. Enel Generación Perú, also a shareholder of Enel Brasil, granted a loan to Enel Brasil, which as of April 25, 2017 amounted to Br$ 7 million plus accrued interests. The intercompany loans are due in December 2017.

During 2017, Enel Américas granted intercompany loans to Enel Brasil to support the business plan in the country, especially after the acquisition of the distribution company CELG. As of the date of this Report, Enel Américas lent US$ 225 million, denominated in U.S. dollars, for a five-year period. No other intercompany loans are expected in 2017.

Intercompany Arrangements Related to the Spin-Offs

Enel Chile does not own any of our common stock or ADSs and we do not own any of Enel Chile’s common stock or ADSs. Under Chilean law, we remain jointly and severally liable for some obligations assumed by Enel Chile pursuant to the separation of the businesses completed on March 1, 2016. Such liability, however, will not extend to any obligation to a person or entity that has given its express consent relieving us of such liability and approving the separation of the businesses.

There are various contractual relationships between Enel Chile and us to provide for intercompany services. Enel Chile entered into intercompany agreements under which it provides services directly and indirectly to us. To a much lesser extent, Enel Chile may require services from us and from SIEI. The services to be rendered by Enel Chile include certain legal, finance, treasury, insurance services, capital markets, financial compliance, accounting, human resources, communications, security, relations with contractors, IT services, tax services and other corporate support and administrative services. These services are provided and charged at market prices if there is a comparable service. If there are no comparable services in the market, they will be provided at cost plus a specified percentage. The intercompany services contracts are valid for five years.

As of the date of this Report, the abovementioned transactions have not experienced material changes. For more information regarding transactions with related parties, refer to Note 9 of the Notes to our consolidated financial statements.

C. Interests of Experts and Counsel.

Not applicable.

Item 8.Financial Information

A. Consolidated Statements and Other Financial Information.

See “Item 18. Financial Statements.”

Legal Proceedings

We and our subsidiaries are parties to legal proceedings arising in the ordinary course of business. We believe it is unlikely that any loss associated with pending lawsuits will significantly affect the normal development of our business.

For detailed information as of December 31, 2016 on the status of the material pending lawsuits that have been filed against us and our subsidiaries, please refer to Note 33.3 of the Notes to our consolidated financial statements. Please note that since March 1, 2016, Enel Chile appears as the defendant instead of us for current legal proceedings or those that may arise from our former Chilean businesses.

In relation to the legal proceedings reported in the Notes to our consolidated financial statements, we use the criteria of disclosing lawsuits above a minimum threshold of US$ 20 million of potential impact to us, and, in some cases, qualitative criteria according to the materiality of the plausible impact in the conduct of our business. The lawsuit status includes a general description, the process status and the estimate of the amount involved in each lawsuit.

Dividend Policy

Our Board of Directors generally establishes a definitive dividend payable each year, accrued in the prior year, which cannot be less than the legal minimum of 30% of annual net income. In the OSM held on April 28, 2016, our shareholders agreed to distribute a definitive dividend of Ch$ 204,874,253,630 equivalent to approximately Ch$ 4.17321 per share of common stock accrued in fiscal

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year 2015. This corresponds to a payout ratio of 50% based on annual net income. On January 29, 2016, an interim dividend of approximately Ch$ 1.23875 per share of common stock was paid as part of the definitive dividend, with the remainder of Ch$ 167,209,724,296 equivalent to approximately Ch$ 3.40599 per share of common stock paid on May 24, 2016. The payment of dividends for fiscal year 2015 was based on net income filed with the SVS, which was marginally different than the net income based on IFRS.

On November 24, 2016, the Board of Directors agreed to distribute an interim dividend of Ch$ 0.94664 per share of common stock on January 27, 2017, accrued in fiscal year 2016. The aforementioned interim dividend will be deducted from the definitive dividend to be paid in May 2017. The definitive dividend of Ch$ 191,530 million equivalent to approximately Ch$ 3.3337 per share of common stock that has been agreed to by the shareholders at the OSM held on April 27, 2017 corresponds to a payout ratio of 50% based on annual consolidated net income.

In accordance with our current dividend policy, the interim dividend corresponds to 15% of consolidated net income as of September 30 2016. Additionally, our Board of Directors will propose a definitive dividend payout equal to 50% of the annual net income for fiscal year2016. Actual dividend payments will be subject to net profits obtained in each period, as well as to expectations of future profit levels and other conditions that may exist at the time of such dividend declaration. The fulfillment of the aforementioned dividend policy will depend on actual 2017 consolidated net income. The proposed dividend policy is subject to our Board of Director’s right to change the amount and timing of the dividends under the circumstances at the time of the payment.

The payment of dividends is potentially subject to legal restrictions, such as legal reserve requirements, capital and retained earnings criteria, and other contractual restrictions such as the non-default on credit agreements. For example, Enel Generación Piura may not pay dividends unless it complies with certain financial covenants. However, these potential legal and contractual restrictions do not currently affect our ability or any of our subsidiaries’ ability to pay dividends. (See “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources” for further detail on our debt instruments).

Shareholders set dividend policies at each subsidiary and affiliate. There are currently no material currency controls which prohibit us from repatriating the dividend payments from its non-Chilean principal subsidiaries and affiliates.

We pay dividends to shareholders of record as of midnight of the fifth business day prior to the payment date. Holders of ADS on the applicable record dates will be entitled to participate in dividends.

Dividends

The table below sets forth, for each of the years indicated, the per share dividend amounts distributed by us in Chilean pesos and the amount of dividends distributed per ADS (one ADS = 50 shares of common stock) in U.S. dollars. See “Item 10. Additional Information — D. Exchange Controls.”

Year	Nominal Ch$(1)		US$ per ADS(2)
2016(3)		4.64		0.35
2015		6.21		0.44
2014		6.71		0.55
2013		4.25		0.41
2012		5.75		0.60

(1) This chart details dividends actually paid in any given year, and not the dividends accrued in that year. These dividends may have been accrued during the prior year or the same year in which they were paid. These amounts do not reflect reduction for any applicable Chilean withholding tax.

(2) The U.S. dollar per ADS amount has been calculated by applying the exchange rate as of December 31 of each year. One ADS = 50 shares of common stock.

(3) The current company is not necessarily comparable to its predecessor before the 2016 Reorganization.

For a discussion of Chilean withholding taxes and access to the formal currency market in Chile in connection with the payment of dividends and sales of ADSs and the underlying common stock, see “Item 10. Additional Information — E. Taxation” and “Item 10. Additional Information — D. Exchange Controls.”

B. Significant Changes.

As of January 1, 2017, we changed our functional currency from Chilean pesos to U.S. dollars. In the future, we will present our financial statements and pay dividends in U.S. dollars.

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Item 9.The Offer and Listing

A. Offer and Listing Details.

Market Price Information

The shares of our common stock and our ADSs currently trade on Chilean exchanges and the NYSE, respectively.

The table below shows, for the periods indicated, high and low prices in Chilean pesos on the Santiago Stock Exchange, and high and low closing prices of the ADSs in U.S. dollars as reported by the NYSE. As of April 21, 2016 and April 26, 2016, the price of common stocks and ADSs, respectively, reflect only the value of the Company and its non‑Chilean operations.  Before such period, the stock prices pertain to Enersis prior to the spin-off of Enel Chile, which included operations in five countries, including Chile.

	Santiago Stock Exchange(1)				U.S. Stock Exchanges(2)
	Ch$ per share				US$ per ADS
	High		Low		High		Low
2017
April (up to April 25, 2017)		141.16		132.22		10.74		10.28
March		141.50		125.00		10.77		9.61
February		130.50		116.09		9.91		8.97
January		117.77	107,82			9.14		8.01
2016		188.00		93.50		14.27		7.38
December		114.80		103.70		8.63		7.75
November		117.00		103.46		8.80		7.67
October		118.00		105.00		8.93		8.06
September		114.90		106.51		8.64		8.08
4th Quarter		118.00		103.46		8.93		7.67
3rd Quarter		118.50		106.51		9.16		8.08
2nd Quarter		117.10		93.50		14.27		7.38
1st Quarter		188.00		153.00		13.93		10.33
2015		226.25		161.16		18.72		11.25
4th Quarter		200.00		161.16		13.99		11.25
3rd Quarter		208.33		174.02		16.10		12.20
2nd Quarter		226.25		196.00		18.72		15.38
1st Quarter		205.00		191.98		16.58		15.15
2014		210.75		143.00		17.59		13.08
4th Quarter		204.89		176.25		15.98		14.91
3rd Quarter		210.75		184.00		17.59		15.69
2nd Quarter		187.85		169.60		17.00		15.21
1st Quarter		171.85		143.00		15.55		13.08
2013		188.00		148.00		19.97		14.39
2012		203.50		150.10		20.87		15.50

(1) Source: Santiago Stock Exchange.

(2) Source: NYSENET. Our ADS composite figures include transactions in all U.S. stock exchanges. One ADS = 50 shares of common stock.

On the last trading day in 2016, our common stock closed at Ch$ 108.87 per share on the Santiago Stock Exchange and our ADSs closed at US$ 8.21 per ADS on the NYSE.

On April 25, 2017, our common stock closed at Ch$ 136.25 per share on the Santiago Stock Exchange and our ADSs closed at US$ 10.37 per ADS on the NYSE.

B. Plan of Distribution.

Not applicable.

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C. Markets.

In Chile, our common stock is traded on three stock exchanges: the Santiago Stock Exchange, the Electronic Stock Exchange and the Valparaíso Stock Exchange. The largest exchange in the country, the Santiago Stock Exchange, was established in 1893 as a private company. As of December 31, 2016, 214 companies had shares listed on the Santiago Stock Exchange. For 2016, the Santiago Stock Exchange accounted for 92.2% of our total equity traded in Chile, which amounted to 6,694,296,428 shares. In addition, 7.8% of our equity trading was conducted on the Electronic Stock Exchange, an electronic trading market that was created by banks and non-member brokerage houses, and finally, less than 0.01% was traded on the Valparaíso Stock Exchange.

Equities, closed-end funds, fixed-income securities, short-term and money market securities, gold and U.S. dollars are traded on the Santiago Stock Exchange. The Santiago Stock Exchange also trades U.S. dollar futures and stock index futures. Securities are traded primarily through an open voice auction system; a firm offers system or the daily auction. Trading through the open voice system occurs on each business day from 9:30 a.m. to 4:00 p.m., during local standard time, and from 9:30 a.m. to 5:00 p.m. when daylight savings time is in place (usually from November to March), which may differ from New York City time by up to two hours, depending on the season. The Santiago Stock Exchange has an electronic trading system called Telepregón, which operates continuously from 9:30 a.m. to 4:00 p.m. during local standard time, and from 9:30 a.m. to 5:00 p.m. when daylight savings time in Chile is in place, on each business day. During local standard time, electronic auctions may be conducted at any of four times a day, at 10:30 a.m., 11:30 a.m., 1:30 p.m., and 3:30 p.m. During daylight savings time there is an additional electronic auction at 4:30 p.m. More than 99% of the auctions and transactions take place electronically.

There are two main share price indexes on the Santiago Stock Exchange, the General Shares Price Index, or IGPA, and the Selected Shares Price Index, or IPSA. The IGPA is calculated using the prices of shares that are traded at least 5% of the trading days of a year, with total annual transactions exceeding UF 10,000 (Ch$ 263 million as of December 31, 2016, equivalent to US$ 393,565) and a free float representing at least 5%. The IPSA is calculated using the prices of the 40 shares with highest trading volume, on a quarterly basis, and with a market capitalization above US$ 200 million. The shares included in the IPSA and IGPA are weighted according to the weighted value of the shares traded. Either we or Enersis, from whom we were spun off in 2016, have been included in the IPSA since 1988.

Shares of our common stock traded in the United States, our primary market, in the form of ADSs on the NYSE and Over the Counter from October 1993 until the completion of the spin-off under our predecessor’s ticker symbol “ENI.” Since the completion of the spin-off of Enel Chile in April 2016, our ADSs trade under the ticker symbol “ENIA.” Each ADS represents 50 shares of common stock, with the ADSs in turn evidenced by American Depositary Receipts (“ADRs”). The ADRs were issued under the Third Amended and Restated Deposit Agreement dated as of March 28, 2013 among us, Citibank, N.A. as Depositary (the “Depositary”), and the holders and beneficial owners from time to time of ADRs issued thereunder (the “Deposit Agreement”). Only persons in whose names ADRs are registered on the books of the Depositary are treated by the Depositary as owners of ADRs.

As of April 27, 2017, ADRs evidencing 114,906,684 ADSs (equivalent to 5,745,334,178 shares of common stock) were outstanding, representing 9.9% of the total number of outstanding shares. It is not practicable for us to determine the proportion of ADSs beneficially owned by U.S. final beneficial holders. Trading volume of our shares on the NYSE and other exchanges during 2016 amounted to 216 million ADSs, equivalent to US$ 2,110 million.

The NYSE is open for trading Monday through Friday from 9:30 am to 4:00 pm, with the exception of holidays declared by the NYSE in advance. On the trading floor, the NYSE trades in a continuous auction format, where traders can execute stock transactions on behalf of investors. Specialist brokers act as auctioneers in an open outcry auction market to bring buyers and sellers together and to manage the actual auction. Customers can also send orders for immediate electronic execution or route orders to the floor for trade in the auction market. The NYSE works with U.S. regulators like the SEC and the Commodity Futures Trading Commission to coordinate risk management measures in the electronic trading environment through the implementation of mechanisms like circuit breakers and liquidity replenishment points.

The following table contains information regarding the amount of total traded shares of common stock and the corresponding percentage traded per market during 2016:

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	Number of shares of common stock traded		Percentage
Market
United States (One ADS = 50 shares of common stock)(1)		10,831,429,600		59.9	%
Chile(2)		7,263,986,744		40.1	%
Total		18,095,416,344		100.0	%

(1) Includes the New York Stock Exchange and over-the-counter trading.

(2) Includes Santiago Stock Exchange, Electronic Stock Exchange and Valparaíso Stock Exchange.

For further information see “Item 9. The Offer and Listing — A. Offer and Listing Details. — Market Price Information.”

D. Selling Shareholders.

Not applicable.

E. Dilution.

Not applicable.

F. Expenses of the Issue.

Not applicable.

Item 10.Additional Information

A. Share Capital.

Not applicable.

B. Memorandum and Articles of Association.

Description of Share Capital

Set forth below is certain information concerning our share capital and a brief summary of certain significant provisions of Chilean law and our by-laws.

General

Shareholders’ rights in Chilean companies are governed by the company’s by-laws (estatutos), which have the same purpose as the articles or the certificate of incorporation and the by-laws of a company incorporated in the United States, and by the Chilean Companies Act Law 18,046. In addition, D.L. 3500, or the Pension Funds’ System Law, which permits the investment by Chilean pension funds in stock of qualified companies, indirectly affects corporate governance and prescribes certain rights of shareholders. In accordance with the Chilean Companies Act, legal actions by shareholders to enforce their rights as shareholders of the company must be brought in Chile in arbitration proceedings or, at the option of the plaintiff, before Chilean courts. Members of the Board of Directors, managers, officers and principal executives of the company, or shareholders that individually own shares with a book value or stock value higher that UF 5,000 (Ch$ 132 million as of December 31, 2016) do not have the option to bring the procedure to the courts.

The Chilean securities markets are principally regulated by the SVS under Securities Market Law (Law 18,045) and the Chilean Companies Act. These two laws state the disclosure requirements, restrictions on insider trading and price manipulation, and provide protection to minority shareholders. The Securities Market Law sets forth requirements for public offerings, stock exchanges and brokers, and outlines disclosure requirements for companies that issue publicly offered securities. The Chilean Companies Act and the Securities Market Law, both as amended, state rules regarding takeovers, tender offers, transactions with related parties, qualified majorities, share repurchases, directors’ committees, independent directors, stock options and derivative actions.

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Public Register

We are a publicly held stock corporation incorporated under the laws of Chile. We were constituted by public deed issued on June 19, 1981 by the Santiago Notary Public, Mr. Patricio Zaldívar M. Our existence was approved by SVS Resolution 409-S of July 17, 1981 and we were registered on July 21, 1981 in the Commercial Registrar (Registro de Comercio del Conservador de Bienes Raíces y Comercio de Santiago), on pages 13099 No. 7269. We are registered with the SVS under the entry number 0175. We also registered with the United States Securities and Exchange Commission under the commission file number 001-12440 on October 19, 1993.

Reporting Requirements Regarding Acquisition or Sale of Shares

Under Article 12 of the Securities Market Law and General Rule 269 of the SVS, certain information regarding transactions in shares of a publicly held stock corporation or in contracts or securities whose price or results depend on, or are conditioned in whole or in part on the price of such shares, must be reported to the SVS and the Chilean stock exchanges. Since ADSs are deemed to represent the shares of common stock underlying the ADRs, transactions in ADRs will be subject to these reporting requirements and those established in Circular 1375 of the SVS. Shareholders of publicly held stock corporations are required to report to the SVS and the Chilean stock exchanges:

• any direct or indirect acquisition or sale of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held stock corporation’s subscribed capital;

• any direct or indirect acquisition or sale of contracts or securities whose price or results depend on or are conditioned in whole or in part on the price of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held stock corporation’s subscribed capital;

• any direct or indirect acquisition or sale of shares made by a holder who, due to an acquisition of shares of such publicly held stock company, results in the holder acquiring, directly or indirectly, at least 10% of a publicly held stock company’s subscribed capital; and

• any direct or indirect acquisition or sale of shares in any amount, made by a director, receiver, principal executive, general manager or manager of a publicly held stock company.

In addition, majority shareholders of a publicly held stock corporation must inform the SVS and the Chilean stock exchanges if such transactions are entered into with the intention of acquiring control of the company or if they are making a passive financial investment instead.

Under Article 54 of the Securities Market Law and General Rule 104 enacted by the SVS, any person who directly or indirectly intends to take control of a publicly held stock corporation must disclose this intent to the market at least ten business days in advance of the proposed change of control and, in any event, as soon as the negotiations for the change of control have taken place or reserved information of the publicly held stock corporation has been provided.

Corporate Objectives and Purposes

Article 4 of our by-laws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transmission, transformation, or sale of energy in any form, directly or through other companies, as well as to provide engineering consulting services related to these objectives, and to participate in the telecommunications business.

Board of Directors

Our Board of Directors consists of seven members who are appointed by shareholders at an OSM and are elected for a three-year term, at the end of which they will be re-elected or replaced.

The seven directors elected at the OSM are the seven individual nominees who receive the highest majority of the votes. Each shareholder may vote his shares in favor of one nominee or may apportion his shares among any number of nominees.

The effect of these voting provisions is to ensure that a shareholder owning more than 12.5% of our shares is able to elect a member of the Board.

The compensation of the directors is established annually at the OSM. See “Item 6. Directors, Senior Management and Employees — B. Compensation.”

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Agreements entered into by us with related parties can only be executed when such agreements serve our interest, and their price, terms and conditions are consistent with prevailing market conditions at the time of their approval and comply with all the requirements and procedures indicated in Article 147 of the Chilean Companies Act.

Certain Powers of the Board of Directors

Our by-laws provide that every agreement or contract that we enter into with our controlling shareholder, our directors or executives, or their related parties, must be previously approved by two-thirds of the Board of Directors and be included in the Board meetings, and must comply with the provisions of the Chilean Companies Act.

Our by-laws do not contain provisions relating to:

• the directors’ power, in the absence of an independent quorum, to vote on compensation for themselves or any members of their body;

• borrowing powers exercisable by the directors and how such borrowing powers can be varied;

• retirement or non-retirement of directors under an age limit requirement; or

• number of shares, if any, required for directors’ qualification.

Certain Provisions Regarding Shareholder Rights

As of the date of the filing of this Report, our capital is comprised of only one class of shares, all of which are ordinary shares and have the same rights.

Our by-laws do not contain any provisions relating to:

• redemption provisions;

• sinking funds; or

• liability for capital reductions by us.

Under Chilean law, the rights of our shareholders may only be modified by an amendment to the by-laws that complies with the requirements explained below under “Item 10. Additional Information — B. Memorandum and Articles of Association. — Shareholders’ Meetings and Voting Rights.”

Capitalization

Under Chilean law, only the shareholders of a company acting at an ESM have the power to authorize a capital increase. When an investor subscribes shares, these are officially issued and registered under his name, and the subscriber is treated as a shareholder for all purposes, except receipt of dividends and for return of capital in the event that the shares have been subscribed but not paid for. The subscriber becomes eligible to receive dividends only for the shares that he has actually paid for or, if the subscriber has paid for only a portion of such shares, the pro rata portion of the dividends declared with respect to such shares unless the company’s by-laws provide otherwise. If a subscriber does not fully pay for shares for which the subscriber has subscribed on or prior to the date agreed upon for payment, notwithstanding the actions intended by the company to collect payment, the company is entitled to auction the shares on the stock exchange where such shares are traded, for the account and risk of the debtor, the number of shares held by the debtor necessary for the company to pay the outstanding balances and disposal expenses. However, until such shares are sold at auction, the subscriber continues to hold all the rights of a shareholder, except the right to receive dividends and return of capital. The Chief Executive Officer, or the person replacing him, will reduce in the shareholders’ register the number of shares in the name of the debtor shareholder to the number of shares that remain, deducting the shares sold by the company and settling the debt in the amount necessary to cover the result of such disposal after the corresponding expenses. When there are authorized and issued shares for which full payment has not been made within the period fixed by shareholders at the same ESM at which the subscription was authorized (which in no case may exceed three years from the date of such meeting), these shall be reduced in the non-subscribed amount until that date. With respect to the shares subscribed and not paid following the term mentioned above, the Board must proceed to collect payment, unless the shareholders’ meeting authorizes (by two thirds of the voting shares) a reduction of the company’s capital to the amount effectively collected, in which case the capital shall be reduced by force of law to the amount effectively paid. Once collection actions have been exhausted, the Board should propose to the shareholders’ meeting the approval by simple majority of the write-off of the outstanding balance and the reduction of capital to the amount effectively recovered.

As of December 31, 2016, our subscribed and fully paid capital totaled Ch$ 4,622 billion and consisted of 58,324,975,387 shares, including 872,333,871 shares held as treasury stock purchased by us in connection with the 2016 Reorganization. On April 27, 2017,

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the EMS agreed to change our functional and reporting currency from Chilean Pesos to U.S. dollars, effective as of January 1, 2017. Consequently, our capital will be redenominated in U.S. dollars and after giving effect to the expected cancellation of the treasury shares, our subscribed and fully paid capital will be US$ 6,763,204,424 consisting of 57,452,641,316 shares.

Preemptive Rights and Increases of Share Capital

The Chilean Companies Act requires Chilean companies to grant shareholders preemptive rights to purchase a sufficient number of shares to maintain their existing ownership percentage of such company whenever such company issues new shares.

Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders during a 30-day period. The options to subscribe for shares in capital increases of the company or of any other securities convertible into shares or that confer future rights over these shares, should be offered, at least once, to the shareholders pro rata to the shares held registered in their name at midnight on the fifth business day prior to the date of the start of the preemptive rights period. The preemptive rights offering and the start of the 30-day period for exercising them shall be communicated through the publication of a prominent notice, at least once, in the newspaper that should be used for notifications of shareholders’ meetings. During such 30-day period, and for an additional period of up to 30-days immediately following the initial 30-day period, publicly held stock corporations are not permitted to offer any unsubscribed shares to third parties on terms which are more favorable than those offered to their shareholders. At the end of the second 30-day period, a Chilean publicly held stock corporation is authorized to sell non-subscribed shares to third parties on any terms, provided they are sold on one of the Chilean stock exchanges.

Shareholders’ Meetings and Voting Rights

An OSM must be held within the first four months following the end of our fiscal year. Our last OSM was held on April 27, 2017. An ESM may be called by the Board of Directors when deemed appropriate, or when requested by shareholders representing at least 10% of the issued shares with voting rights, or by the SVS. To convene an OSM or an ESM, notice must be given three times in a newspaper located in our corporate domicile. The newspaper designated by our shareholders is El Mercurio de Santiago. The first notice must be published not less than 15-days and no more than 20-days in advance of the scheduled meeting. Notice must also be mailed to each shareholder, to the SVS and to the Chilean stock exchanges.

The OSM shall be held on the day stated in the notice and should remain in session until having exhausted all the matters stated in the notice. However, once constituted, upon the proposal of the chairman or shareholders representing at least 10% of the shares with voting rights, the majority of the shareholders present may agree to suspend it and to continue it within the same day and place, with no new constitution of the meeting or qualification of powers being necessary, recorded in one set of minutes. Only those shareholders who were present or represented may attend the recommencement of the meeting with voting rights.

Under Chilean law, a quorum for a shareholders’ meeting is established by the presence, in person or by proxy, of shareholders representing at least a majority of the issued shares with voting rights of a company. If a quorum is not present at the first meeting, a reconvened meeting can take place at which the shareholders present are deemed to constitute a quorum regardless of the percentage of the shares represented. This second meeting must take place within 45-days following the scheduled date for the first meeting. Shareholders’ meetings adopt resolutions by the affirmative vote of a majority of those shares present or represented at the meeting. An ESM must be called to take the following actions:

• a transformation of the company into a form other than a publicly held stock corporation under the Chilean Companies Act, a merger or split-up of the company;

• an amendment to the term of duration or early dissolution of the company;

• a change in the company’s domicile;

• a decrease of corporate capital;

• an approval of capital contributions in kind and non-monetary assessments;

• a modification of the authority reserved to shareholders or limitations on the Board of Directors;

• a reduction in the number of members of the Board of Directors;

• a disposition of 50% or more of the assets of the company, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater that such percentage;

• the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the corporation, as well as any disposition of its shares that results in the parent company losing its position as controlling shareholder;

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• the form of distributing corporate benefits;

• issue of guarantees for third-party liabilities which exceed 50% of the assets, except when the third party is a subsidiary of the company, in which case approval of the Board of Directors is deemed sufficient;

• the purchase of the company’s own shares;

• other actions established by the by-laws or the laws;

• certain remedies for the nullification of the company’s by-laws;

• inclusion in the by-laws of the right to purchase shares from minority shareholders, when the controlling shareholders reaches 95% of the company’s shares by means of a tender offer for all of the company’s shares, where at least 15% of the shares have been acquired from unrelated shareholders; and

• approval or ratification of acts or contracts with related parties.

Regardless of the quorum present, the vote required for any of the actions above is at least two-thirds of the outstanding shares with voting rights.

By-law amendments for the creation of a new class of shares, or an amendment to or an elimination of those classes of shares that already exist, must be approved by at least two-thirds of the outstanding shares of the affected series.

Chilean law does not require a publicly held stock corporation to provide its shareholders the same level and type of information required by the U.S. securities laws regarding the solicitation of proxies. However, shareholders are entitled to examine the financial statements and corporate books of a publicly held stock corporation within the 15-day period before its scheduled OSM. Under Chilean law, a notice of a shareholders meeting listing matters to be addressed at the meeting must be mailed at least 15 days prior to the date of such meeting, and, an indication of the way complete copies of the documents that support the matters submitted for voting can be obtained, which must also be made available to shareholders on our website. In the case of an OSM, our annual report of activities, which includes audited financial statements, must also be made available to shareholders and published on our website at: www.enelamericas.cl.

The Chilean Companies Act provides that, upon the request by the Directors’ Committee or by shareholders representing at least 10% of the issued shares with voting rights, a Chilean company’s annual report must include, in addition to the materials provided by the Board of Directors to shareholders, such shareholders’ comments and proposals in relation to the company’s affairs. In accordance with Article 136 of the Chilean Companies Regulation (Reglamento de Sociedades Anónimas), the shareholder(s) holding or representing 10% or more of the shares issued with voting rights, may:

• make comments and proposals relating to the progress of the corporate businesses in the corresponding year, no shareholder being able to make individually or jointly more than one presentation. These observations should be presented in writing to the company concisely, responsibly and respectfully, and the respective shareholder(s) should state their willingness for these to be included as an appendix to the annual report. The board shall include in an appendix to the annual report of the year a faithful summary of the pertinent comments and proposals the interested parties had made, provided they are presented during the year or within 30-days after its ending; or

• make comments and proposals on matters that the board submits for the knowledge or voting of the shareholders. The board shall include a faithful summary of those comments and proposals in all information it sends to shareholders, provided the shareholders’ proposal is received at the offices of the company at least 10-days prior to the date of dispatch of the information by the company. The shareholders should present their comments and proposals to the company, expressing their willingness for these to be included in the appendix to the respective annual report or in information sent to shareholders, as the case may be. The observations referred to in this Article may be made separately by each shareholder holding 10% or more of the shares issued with voting rights or shareholders who together hold that percentage, who should act as one.

Similarly, the Chilean Companies Act provides that whenever the Board of Directors of a publicly held stock corporation convenes an OSM and solicits proxies for the meeting, or circulates information supporting its decisions or other similar material, it is obligated to include the pertinent comments and proposals that may have been made by the Directors’ Committee or by shareholders owning 10% or more of the shares with voting rights who request that such comments and proposals be so included.

Only shareholders registered as such with us, as of midnight on the fifth business day prior to the date of a meeting, are entitled to attend and vote their shares. A shareholder may appoint another individual, who does not need to be a shareholder, as his proxy to attend the meeting and vote on his behalf. Proxies for such representation shall be given for all the shares held by the owner. The proxy may contain specific instructions to approve, reject, or abstain with respect to any of the matters submitted for voting at the

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meeting and which were included in the notice. Every shareholder entitled to attend and vote at a shareholders’ meeting shall have one vote for every share subscribed.

There are no limitations imposed by Chilean law or our by-laws on the right of nonresidents or foreigners to hold or vote shares of common stock. However, the registered holder of the shares of common stock represented by ADSs, and evidenced by outstanding ADSs, is the custodian of the Depositary, currently Banco Santander-Chile, or any successor thereto. Accordingly, holders of ADSs are not entitled to receive notice of meetings of shareholders directly or to vote the underlying shares of common stock represented by ADS directly. The Deposit Agreement contains provisions pursuant to which the Depositary has agreed to solicit instructions from registered holders of ADSs as to the exercise of the voting rights pertaining to the shares of common stock represented by the ADSs. Subject to compliance with the requirements of the Deposit Agreement and receipt of such instructions, the Depositary has agreed to endeavor, insofar as practicable and permitted under Chilean law and the provisions of the by-laws, to vote or cause to be voted (or grant a discretionary proxy to the Chairman of the Board of Directors or to a person designated by the Chairman of the Board of Directors to vote) the shares of common stock represented by the ADSs in accordance with any such instruction. The Depositary shall not itself exercise any voting discretion over any shares of common stock underlying ADSs. If no voting instructions are received by the Depositary from a holder of ADSs with respect to the shares of common stock represented by the ADSs, on or before the date established by the Depositary for such purpose, the shares of common stock represented by the ADS, may be voted in the manner directed by the Chairman of the Board, or by a person designated by the Chairman of the Board, subject to limitations set forth in the Deposit Agreement.

Dividends and Liquidation Rights

According to the Chilean Companies Act, unless otherwise decided by unanimous vote of its issued shares eligible to vote, all companies must distribute a cash dividend in an amount equal to at least 30% of their consolidated net income, unless and except to the extent we have carried forward losses. The law provides that the Board of Directors must agree to the dividend policy and inform such policy to the shareholders at the OSM.

Any dividend in excess of 30% of net income may be paid, at the election of the shareholders, in cash, or in our shares, or in shares of publicly held corporations owned by us. Shareholders who do not expressly elect to receive a dividend other than in cash are legally presumed to have decided to receive the dividend in cash.

Dividends which are declared but not paid within the appropriate time period set forth in the Chilean Companies Act (as to minimum dividends, 30-days after declaration; as to additional dividends, the date set for payment at the time of declaration) are adjusted to reflect the change in the value of UF, from the date set for payment to the date such dividends are actually paid. Such dividends also accrue interest at the then-prevailing rate for UF-denominated deposits during such period. The right to receive a dividend lapses if it is not claimed within five years from the date such dividend is payable. Payments not collected in such period are transferred to the volunteer fire department.

In the event of our liquidation, the shareholders would participate in the assets available in proportion to the number of paid-in shares held by them, after payment to all creditors.

Approval of Financial Statements

The Board of Directors is required to submit our consolidated financial statements to the shareholders annually for their approval. If the shareholders by a vote of a majority of shares present (in person or by proxy) at the shareholders’ meeting reject the financial statements, the Board of Directors must submit new financial statements no later than 60-days from the date of such meeting. If the shareholders reject the new financial statements, the entire Board of Directors is deemed removed from office and a new board is elected at the same meeting. Directors who individually approved such financial statements are disqualified for reelection for the following period. Our shareholders have never rejected the financial statements presented by the Board of Directors.

Change of Control

The Capital Markets Law establishes a comprehensive regulation related to tender offers. The law defines a tender offer as the offer to purchase shares of companies which publicly offer their shares or securities convertibles into shares and which offer is made to shareholders to purchase their shares under conditions which allow the bidder to reach a certain percentage of ownership of the company within a fixed period of time. These provisions apply to both voluntary and hostile tender offers.

Acquisition of Shares

No provision in our by-laws discriminates against any existing or prospective holder of shares as a result of such shareholder owning a substantial number of shares. However, no person may directly or indirectly own more than 65% of the outstanding shares

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of our stock. The foregoing restriction does not apply to the depositary as record owner of shares represented by ADRs, but it does apply to each beneficial ADS holder. Additionally, our by-laws prohibit any shareholder from exercising voting power with respect to more than 65% of the common stock owned by such shareholder or on behalf of others representing more than 65% of the outstanding issued shares with voting rights.

Right of Dissenting Shareholders to Tender Their Shares

The Chilean Companies Act provides that upon the adoption of any of the resolutions enumerated below at a meeting of shareholders, dissenting shareholders acquire the right to withdraw from the company and to compel the company to repurchase their shares, subject to the fulfillment of certain terms and conditions. In order to exercise such withdrawal rights, holders of ADRs must first withdraw the shares represented by their ADRs pursuant to the terms of the Deposit Agreement.

“Dissenting” shareholders are defined as those who at a shareholders’ meeting vote against a resolution that results in the withdrawal right, or who if absent from such meeting, state in writing their opposition to the respective resolution, within the 30-days following the shareholders’ meeting. Shareholders present or represented at the meeting and who abstain in exercising their voting rights shall not be considered as dissenting. The right to withdraw should be exercised for all the shares that the dissenting shareholder had registered in their name on the date on which the right is determined to participate in the meeting at which the resolution is adopted that motivates the withdrawal and which remains on the date on which their intention to withdraw is communicated to the company. The price paid to a dissenting shareholder of a publicly held stock corporation whose shares are quoted and actively traded on one of the Chilean stock exchanges is the weighted average of the sales prices for the shares as reported on the Chilean stock exchanges on which the shares are quoted for the two-month period between the ninetieth and the thirtieth day before the shareholders’ meeting giving rise to the withdrawal right. If, because of the volume, frequency, number and diversity of the buyers and sellers, the SVS determines that the shares are not actively traded on a stock exchange, the price paid to the dissenting shareholder shall be the book value. Book value for this purpose shall equal paid capital plus reserves and profits, less losses, divided by the total number of subscribed shares, whether entirely or partially paid. For the purpose of making this calculation, the last consolidated statements of financial position is used, as adjusted to reflect inflation up to the date of the shareholders’ meeting which gave rise to the withdrawal right.

Article 126 of the Chilean Companies Act Regulations establishes that in cases where the right to withdraw arises, the company shall be obliged to inform the shareholders of this situation, the value per share that will be paid to shareholders exercising their right to withdraw and the term for exercising it. Such information should be given to shareholders at the same meeting at which the resolutions are adopted giving rise to the right of withdrawal, prior to its voting. A special communication should be given to the shareholders with rights, within two days following the date on which the rights to withdraw are born. In the case of publicly held companies, such information shall be communicated by a prominent notice in a newspaper with a wide national circulation and on its website, plus a written communication addressed to the shareholders with rights at the address they have registered with the company. The notice of the shareholders meeting that should pronounce on a matter that could originate withdrawal rights should mention this circumstance.

The resolutions that result in a shareholder’s right to withdraw include, among others, the following:

• the transformation of the company into an entity which is not a publicly held stock corporation governed by Chilean Companies Act;

• the merger of the company with another company;

• disposition of 50% or more of the assets of the company, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater than such percentage;

• the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the company, as well as any disposition of its shares that results in the parent company losing its position of controlling shareholder;

• issue of guarantees for third parties’ liabilities which exceed 50% of the assets (if the third party is a subsidiary of the company, the approval of the Board of Directors is sufficient);

• the creation of preferential rights for a class of shares or an amendment to the existing ones. In this case the right to withdraw only accrues to the dissenting shareholders of the class or classes of shares adversely affected;

• certain remedies for the nullification of the corporate by-laws; and

• such other causes as may be established by the law or by the company’s by-laws.

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Investments by AFPs

The Pension Funds’ System Law permits AFPs to invest their funds in companies that are subject to Title XII and these companies are subject to greater restrictions than other companies. The determination of which stocks may be purchased by AFPs is made by the Risk Classification Committee. The Risk Classification Committee establishes investment guidelines and is empowered to approve or disapprove those companies that are eligible for AFP investments. Except for the period from March 2003 to March 2004, we have been a Title XII company since 1985 and we are approved by the Risk Classification Committee.

Title XII companies are required to have by-laws that: limit the ownership of any shareholder to a specified maximum percentage, currently at 65%; require that certain actions be taken only at a meeting of the shareholders, and give the shareholders the right to approve certain investment and financing policies.

Registrations and Transfers

Shares issued by us are registered with an administrative agent, which is DCV Registros S.A. This entity is also responsible for our shareholders registry. In case of jointly-owned shares, an attorney-in-fact must be appointed to represent the joint owners in dealing with us.

C. Material Contracts.

None.

D. Exchange Controls.

The Central Bank of Chile is responsible for, among other things, monetary policies and exchange controls in Chile. Currently applicable foreign exchange regulations are set forth in the Compendium of Foreign Exchange Regulations (the “Compendium”) approved by the Central Bank of Chile in 2002. Appropriate registration of a foreign investment in Chile permits the investor access to the Formal Exchange Market. Foreign investments can be registered with the Foreign Investment Committee under D.L. 600 of 1974 or can be registered with the Central Bank of Chile under the Central Bank Act, Law 18,840 of October 1989.

a) Chapter XIV

The following is a summary of certain provisions of Chapter XIV that are applicable to all existing shareholders (and ADS holders). This summary does not purport to be complete and is qualified in its entirety by reference to Chapter XIV. Chapter XIV regulates the following type of investments: credits, deposits, investments and equity contributions. A Chapter XIV investor may at any time repatriate an investment made in us upon sale of our shares, and the profits derived therefrom, with no monetary ceiling, subject to the then effective regulations, which must be reported to the Central Bank of Chile.

Except for compliance with tax regulations and some reporting requirements, currently there are no rules in Chile affecting repatriation rights, except that the remittance of foreign currency must be made through a Formal Exchange Market entity. However, the Central Bank of Chile has the authority to change such rules and impose exchange controls.

b) The Compendium and International Bond Issuances

Chilean issuers may offer bonds issued by the Central Bank of Chile internationally under Chapter XIV, as amended, of the Compendium.

E. Taxation.

Chilean Tax Considerations

The following discussion summarizes material Chilean income and withholding tax consequences to foreign holders arising from the ownership and disposition of shares and ADSs. The summary that follows does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a decision to purchase, own or dispose of shares or ADSs, if any, and does not purport to deal with the tax consequences applicable to all categories of investors, some of which may be subject to special rules. Holders of shares and ADSs are advised to consult their own tax advisors concerning the Chilean and other tax consequences of the ownership of shares or ADSs. The summary that follows is based on Chilean law, in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions contained in statutes such as tax rates applicable to foreign investors, the computation of taxable income for Chilean purposes and the manner in which Chilean taxes are imposed and collected may be amended only by another law. In addition, the Chilean tax authorities enact

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rulings and regulations of either general or specific application and interpret the provisions of the Chilean Income Tax Law. Chilean tax may not be assessed retroactively against taxpayers who act in good faith relying on such rulings, regulations and interpretations, but Chilean tax authorities may change their rulings, regulations and interpretations in the future. The discussion that follows is also based, in part, on representations of the depositary, and assumes that each obligation in the Deposit Agreement and any related agreements will be performed in accordance with its terms. As of this date, there is currently no applicable income tax treaty in effect between the United States and Chile. However, in 2010 the United States and Chile signed an income tax treaty that will enter into force once the treaty is ratified by both countries, which has not happened as of the date of this Report. There can be no assurance that the treaty will be ratified by either country. The following summary assumes that there is no applicable income tax treaty in effect between the United States and Chile.

As used in this Report, the term “foreign holder” means either:

• in the case of an individual holder, a person who is not a resident of Chile; for purposes of Chilean taxation, an individual is resident of Chile if he or she has resided in Chile for more than six months in one calendar year, or a total of more than six months in two consecutive fiscal years; or

• in the case of a legal entity holder, an entity that is not organized under the laws of Chile, unless the shares or ADSs are assigned to a branch, agent, representative or permanent establishment of such entity in Chile.

Taxation of Shares and ADSs

Taxation of Cash Dividends and Property Distributions

General Rule: The following taxation of cash dividends and property distributions applies until 2016. Cash dividends paid with respect to the shares or ADSs held by a foreign holder will be subject to Chilean withholding tax, which is withheld and paid by the company. As described in the example below, the amount of the Chilean withholding tax is determined by applying a 35% rate to a “grossed-up” distribution amount (such amount equal to the sum of the actual distribution amount and the correlative Chilean corporate income tax paid by the issuer), and then subtracting as a credit such Chilean corporate income tax paid by the issuer.

In September 2014, a tax reform was enacted (Law 20,780) which, among other topics, progressively increased the corporate income tax (“CIT”). The CIT rate will be adjusted as follows: in 2014 it increased from 20% to 21%; in 2015 it increased to 22.5%; in 2016 it increased to 24%; in 2017, depending on which of the two new alternative systems enacted as part of the 2014 tax reform (discussed below) is chosen, the rate increases to 25% for companies electing the accrued income basis and 25.5% for companies electing the cash basis for shareholders. As of 2018, the CIT rate will remain at 25% for companies that elected the accrued income basis and will increase to 27% for companies that elected the cash basis for shareholders. The example below illustrates the effective Chilean withholding tax burden on a cash dividend received by a foreign holder, assuming a Chilean withholding tax base rate of 35%, an effective Chilean corporate income tax rate of 24 % (CIT rate for 2016) and a distribution of 50% of the net income of the company distributable after payment of the Chilean corporate income tax:

Line	Concept and calculation assumptions	Amount
1	Company taxable income (based on Line 1 = 100)		100.0
2	Chilean corporate income tax : 24% x Line 1		24
3	Net distributable income: Line 1 — Line 2		76
4	Dividend distributed (50% of net distributable income): 50% of Line 3		38
5	Withholding tax: (35% of (the sum of Line 4 and 50% of Line 2))		(17.5	)
6	Credit for 50% of Chilean corporate income tax : 50% of Line 2		12
7	Net withholding tax : Line 5 + Line 6		(5.6	)
8	Net dividend received: Line 4 - Line 7		33
9	Effective dividend withholding rate : Line 7 / Line 4		14.5

In general, the effective Chilean dividend withholding tax rate, after giving effect to the credit for the Chilean corporate income tax paid by the company, can be computed using the following formula:

Effective Dividend       =	(Withholding tax rate) - (Chilean corporate income tax rate)
Withholding Tax Rate	1 - (Chilean corporate income tax rate)

Using the rates prevailing until 2016, the Effective Dividend Withholding Rate is

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(35%-24%) / (100%-24%) = 14.47%

Dividends are generally assumed to have been paid out of our oldest retained profits for purposes of determining the level of Chilean corporate income tax that was paid by us. For information as to our retained earnings for tax purposes and the tax credit available on the distribution of such retained earnings, see Note 17 of the Notes to our consolidated financial statements.

Under Chilean Income Tax Law, dividend distributions made in property are subject to the same Chilean tax rules as cash dividends. Stock dividends that represent free shares distributed to foreign shareholders as a consequence of a capitalization made on the same corporation are not subject to Chilean taxation.

Exceptions: Despite the aforementioned general rule, there are special circumstances under which a different tax treatment would apply depending on the source of the income or due to special circumstances existing at the date of the dividend distribution. The most common special cases are briefly described below:

1) Circumstances where there is no CIT credit against the Chilean withholding tax: These cases are when: (i) profits paid as dividends (following the seniority rule indicated above) exceed a company’s taxable income (such dividend distributions in excess of a company’s taxable income determined as of December 31 of the distribution’s year will be subject to the Chilean withholding tax rate of 35%, without the CIT credit; in relation to the provisional withholding rule applicable on the date of the dividend payment, please see number 3 below); or (ii) the income was not subject to CIT due to an exemption of the Chilean corporate income tax, in which case the foreign holder will be also subject to the Chilean withholding tax rate of 35% without the CIT credit.

2) Circumstances where dividends have been attributed to income exempted from all the Chilean income taxes: In these cases, dividends distributed by a company to the foreign holder will not be subject to Chilean withholding tax. Income exempted from Chilean income tax is expressly listed in the Chilean Income Tax Law.

3) Circumstances where dividends are subject to a provisional withholding tax: In the event that on the date of the dividend distribution there are no earnings on which income tax has been paid and there are no tax-exempt earnings, a 35% Chilean withholding tax with a provisional 24% Chilean CIT credit is applicable. This provisional 24% Chilean corporate income tax credit must be confirmed with the information of a company’s taxable income as of December 31 of the year in which the dividend was paid. A company can agree with the foreign holders to withhold a higher amount in order to avoid under withholding of the Chilean withholding tax.

4) Circumstances when it is possible to use certain credits in Chile against income taxes paid abroad, or “foreign tax credit”: This occurs when dividends distributed by the Chilean company have income generated by companies domiciled in third countries as their source. If that income was subject to withholding tax or corporate income tax in those third countries, such income will have a credit or “foreign tax credit” against corresponding Chilean taxes, which can be proportionally transferred to the shareholders of a Chilean company.

New System in effect starting in 2017

The tax reform released in September 2014, as amended by Law 20,899 enacted on February 8, 2016, created two alternative mechanisms of shareholder-level income taxation beginning on January 1, 2017: a) accrued income basis (known as attributed-income system in Chile) shareholder taxation and b) cash basis (known as partially-integrated system in Chile and most similar to the current system) shareholder taxation. Since we are a public limited company (“Sociedad Anónima” in Spanish), no election is available to us, and therefore the cash basis system is mandatory for us according to the law.

In addition, the aforementioned Law 20,899 expanded the 100% CIT credit against the Chilean shareholder tax to taxpayers who are residents in countries with which Chile has an effective or signed tax treaty to avoid international double taxation prior to January 1, 2017, even if not in force as of such date. This is currently the status of the treaty signed between Chile and the United States. This temporary rule will be in force from January 1, 2017 through December 31, 2019.

Under the cash basis system, we will pay CIT (at 25% in 2017 and at 27% thereafter) on our annual result. Foreign and local individual shareholders will only pay in Chile the relevant tax (as described below) on effective profit distributions and will be allowed to use the tax paid by the distributing company as credit, with certain limitations. Only 65% of the CIT is creditable against the 35% shareholder- level tax (as opposed to 100% under the current FUT regime and under the accrued income basis). However, if there is an effective or signed tax treaty with Chile before January 1, 2017 (even if not in effect), the CIT is fully creditable against the 35% shareholder tax.

Taxation in two stages:

• Company:27% of accrued profits (using the maximum CIT applicable from 2018 and forward).

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• Shareholder:35% of cash disbursement (65% of CIT tax is creditable against the shareholder level tax, resulting in an effective tax rate to the shareholder of 17.5%. However, if the shareholder is a resident of a country with an effective or signed tax treaty with Chile before January 1, 2017 (even if not in effect), CIT tax is fully creditable, resulting in an effective tax rate to the shareholder of 8%).

Total Tax Burden: 44.45% (35% for residents of countries with tax treaties).

Taxation on sale or exchange of ADSs, outside of Chile

Gains obtained by a foreign holder from the sale or exchange of ADSs outside Chile will not be subject to Chilean taxation.

Taxation on sale or exchange of Shares

Until December 31, 2016, the Chilean Income Tax Law included a tax exemption on capital gains arising from the sale of shares of listed companies traded in the stock markets. Although there were certain restrictions, in general terms, the amendment provided that in order to qualify for the capital gain exemption: (i) the shares must be of a publicly held stock corporation with a certain minimum level of trading on a stock exchange; (ii) the sale must be carried out in a Chilean stock exchange, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law; (iii) the shares which were being sold must have been acquired on a Chilean stock exchange, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law, or in an initial public offering (due to the creation of a company or to a capital increase), or due to the exchange of convertible bonds; and (iv) the shares must have been acquired after April 19, 2001.

If the shares did not qualify for the above exemption, capital gains on their sale or exchange of shares (as distinguished from sales or exchanges of ADSs representing such shares of common stock) could be subject to two alternative tax regimes: (a) the general tax regime, with a 24% Chilean CIT and a 35% Chilean withholding tax, the former being creditable against the latter; or (b) a 24% Chilean CIT as sole tax regime, when all the following circumstances were met: (i) the sale was made between unrelated parties, (ii) the sale of shares was not a recurrent or habitual activity for the seller and (iii) at least one year had elapsed between the acquisition and the sale of the shares.

The date of acquisition of the ADSs was considered to be the date of acquisition of the shares for which the ADSs were exchanged.

Since January 1, 2017, the capital gains obtained in the sales of shares owned by foreign holders are subject to CIT and Chilean withholding tax, where the CIT serves as a credit in Chile to reduce the withholding tax.  

Other Chilean Taxes

There is no gift, inheritance or succession tax applicable to the ownership, transfer or disposition of ADSs by foreign holders, but such taxes will generally apply to the transfer at death or by gift of the shares by a foreign holder. There is no Chilean stamp, issue, registration or similar taxes or duties payable by holders of shares or ADSs.

Material U.S. Income Tax Considerations

This discussion is based on the Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions and final, temporary and proposed Treasury regulations, all as of the date hereof. These authorities are subject to change, possibly with retroactive effect. This discussion assumes that the depositary’s activities are clearly and appropriately defined so as to ensure that the tax treatment of ADSs will be identical to the tax treatment of the underlying shares.

The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning, and disposing of shares or ADSs, but it does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a particular person’s decision to hold such securities and is based on the assumption stated above under “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations” that there is no applicable income tax treaty in effect between the United States and Chile. The discussion applies only if the beneficial owner holds shares or ADSs as capital assets for U.S. federal income tax purposes and it does not describe all of the tax consequences that may be relevant in light of the beneficial owner’s particular circumstances. For instance, it does not describe all the tax consequences that may be relevant to:

• certain financial institutions;

• insurance companies;

• dealers and traders in securities who use a mark-to-market method of tax accounting;

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• persons holding shares or ADSs as part of a “straddle” integrated transaction or similar transaction;

• persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

• partnerships or other entities classified as partnerships for U.S. federal income tax purposes;

• persons liable for the alternative minimum tax;

• tax-exempt organizations;

• persons holding shares or ADSs that own or are deemed to own ten percent or more of our stock; or

• persons holding shares or ADSs in connection with a trade or business conducted outside of the United States.

If an entity classified as a partnership for U.S. federal income tax purposes holds shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and upon the activities of the partnership. Partnerships holding shares or ADSs and partners in such partnerships should consult their tax advisors as to the particular U.S. federal income tax consequences of holding and disposing of the shares or ADSs.

You will be a “U.S. Holder” for purposes of this discussion if you become a beneficial owner of our shares or ADSs and if you are, for U.S. federal income tax purposes:

• a citizen or individual resident of the United States; or

• a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or any political subdivision thereof; or

• an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or

• a trust (i) that validly elects to be treated as a U.S. person for U.S. federal income tax purposes or (ii) if (A) a court within the United States is able to exercise primary supervision over the administration of the trust and (B) one or more U.S. persons have the authority to control all substantial decisions of the trust.

In general, if a beneficial owner owns ADSs, such owner will be treated as the owner of the shares represented by those ADSs for U.S. federal income tax purposes. Accordingly, no gain or loss will be recognized if a beneficial owner exchanges ADSs for the underlying shares represented by those ADSs.

The U.S. Treasury has expressed concerns that parties to whom ADSs are released before shares are delivered to the depositary (pre-release) or intermediaries in the chain of ownership between beneficial owners and the issuer of the security underlying the ADSs may be taking actions that are inconsistent with the claiming of foreign tax credits for beneficial owners of depositary shares. Such actions would also be inconsistent with the claiming of the reduced tax rate, described below, applicable to dividends received by certain non-corporate beneficial owners. Accordingly, the analysis of the creditability of Chilean taxes, and the availability of the reduced tax rate for dividends received by certain non-corporate holders, each described below, could be affected by actions taken by such parties or intermediaries.

This discussion assumes that we will not be a passive foreign investment company, as described below.

Beneficial owners should consult their tax advisors with respect to their particular tax consequences of owning or disposing of shares or ADSs, including the applicability and effect of state, local, non-U.S. and other tax laws and the possibility of changes in tax laws.

Taxation of Distributions

The following discussion is based on the current regime for taxation of cash dividends and distributions applicable in Chile until 2016. For 2017 and later, the U.S. federal income tax treatment will depend on which of the two regimes we elect to adopt. We adopted the cash basis system, which is very similar to the regime that was in effect until 2016. See “Item 10. Additional Information—E. Taxation — Chilean Tax Considerations — Taxation of shares and ADSs — Taxation of Cash Dividends and Property Distributions” above.

Distributions paid on shares or ADSs other than certain pro rata distributions of shares of common stock will be treated as dividends taxable as ordinary income to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported as dividends.

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If a beneficial owner is a U.S. Holder, subject to applicable limitations and the discussion above regarding concerns expressed by the U.S. Treasury, dividends paid by qualified foreign corporations to the beneficial owner that is not a corporation are taxable at a maximum rate of 20%. A foreign company is treated as a qualified foreign corporation with respect to dividends paid on stock that is readily tradable on an established securities market in the United States, such as the New York Stock Exchange where our ADSs are traded. Beneficial owners should consult their tax advisors to determine whether the favorable rate will apply to dividends they receive and whether they are subject to any special rules that limit their ability to be taxed at this favorable rate.

The amount of a dividend will include the net amount withheld by us in respect of Chilean withholding taxes on the distribution. The amount of the dividend will be treated as foreign-source dividend income to a beneficial owner and will not be eligible for the dividends-received deduction generally allowed to U.S. corporations under the Code. Dividends will be included in a beneficial owner’s income on the date of the beneficial owner’s, or in the case of ADSs, the Depositary’s receipt of the dividend. The amount of any dividend paid in Chilean pesos will be a U.S. dollar amount calculated by reference to the exchange rate for converting Chilean pesos into U.S. dollars in effect on the date of such receipt regardless of whether the payment is in fact converted into U.S. dollars. If the dividend is converted into U.S. dollars on the date of receipt, a beneficial owner generally should not be required to recognize foreign currency gain or loss in respect of the dividend income. A beneficial owner may have foreign currency gain or loss if the dividend is converted into U.S. dollars on a date after the date of receipt.

Subject to applicable limitations that may vary depending upon a beneficial owner’s circumstances and subject to the discussion above regarding concerns expressed by the U.S. Treasury, the net amount of Chilean withholding tax (after reduction for the credit for Chilean corporate income tax, as discussed above under “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADSs — Taxation of Cash Dividends and Property Distributions”) withheld from dividends on shares or ADSs will be creditable against a beneficial owner’s U.S. federal income tax liability. The rules governing foreign tax credits are complex and, therefore, a beneficial owner should consult the beneficial owner’s tax advisor regarding the availability of foreign tax credits in the beneficial owner’s particular circumstances. Instead of claiming a credit, a beneficial owner may, at the beneficial owner’s election, deduct such Chilean taxes in computing the beneficial owner’s taxable income, subject to generally applicable limitations under U.S. law. An election to deduct foreign taxes instead of claiming foreign tax credits applies to all taxes paid or accrued in the taxable year to foreign countries and possessions of the United States.

Sale or Other Disposition of Shares or ADSs

If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or ADSs will be a capital gain or loss, and will be a long- term capital gain or loss if the beneficial holder has held the shares or ADSs for more than one year. The amount of a beneficial owner’s gain or loss will equal the difference between the beneficial owner’s tax basis in the shares or ADSs disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. Such gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. In addition, certain limitations exist on the deductibility of capital losses by both corporate and individual taxpayers.

In certain circumstances prior to 2017, and in all circumstances starting in 2017, Chilean taxes may be imposed upon the sale of shares (but not ADSs). See “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADSs.” If a Chilean tax is imposed on the sale or disposition of shares, and a beneficial owner that is a U.S. Holder does not receive significant foreign source income from other sources, such beneficial owner may not be able to credit such Chilean tax against the beneficial owner’s U.S. federal income tax liability.

Passive Foreign Investment Company Rules

We believe that we will not be a “passive foreign investment company” (“PFIC”) for U.S. federal income tax purposes for our 2017 taxable year or for the foreseeable future. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any taxable year. If we were to become a PFIC for any taxable year during which a beneficial owner held shares or ADSs, certain adverse consequences could apply to the beneficial owner, including the imposition of higher amounts of tax than would otherwise apply, and additional filing requirements. Beneficial owners should consult their tax advisors regarding the consequences to them if we were to become a PFIC, as well as the availability and advisability of making any election that might mitigate the adverse consequences of PFIC status.

Information Reporting and Backup Withholding

Payments of dividends and sales proceeds that are made within the United States or through certain U.S.- related financial intermediaries generally are subject to information reporting and to backup withholding unless:

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(i) the beneficial owner is an exempt recipient or (ii) in the case of backup withholding, the beneficial owner provides a correct taxpayer identification number and certifies that the beneficial owner is not subject to backup withholding.

The amount of any backup withholding from a payment to a beneficial owner will be allowed as a credit against the beneficial owner’s U.S. federal income tax liability and may entitle the beneficial owner to a refund, provided that the required information is furnished in a timely fashion to the Internal Revenue Service.

Medicare Contribution Tax

Legislation enacted in 2010 generally imposes a tax of 3.8% on the “net investment income” of certain individuals, trusts and estates. Among other items, net investment income generally includes gross income from dividends and net gain attributable to the disposition of certain property, like the shares or ADSs, less certain deductions. A beneficial owner should consult the beneficial owner’s tax advisor regarding the possible application of this legislation in the beneficial owner’s particular circumstances.

Beneficial owners should consult their tax advisors with respect to the particular consequences to them of receiving, owning or disposing of shares or ADSs.

F. Dividends and Paying Agents.

Not applicable.

G. Statement by Experts.

Not applicable.

H. Documents on Display.

We are subject to the information requirements of the Exchange Act, except that as a foreign issuer, we are not subject to the SEC proxy rules (other than general anti-fraud rules) or the short-swing profit disclosure rules of the Exchange Act. In accordance with these statutory requirements, we file or furnish reports and other information with the SEC. Reports and other information filed or furnished with the SEC may be inspected and copied at the public reference facilities maintained by the SEC at Room 1024, 100 F Street, N.E., Washington, D.C. 20549. Copies of such material may also be inspected at the offices of the New York Stock Exchange, at 11 Wall Street, New York, New York 10005, on which our ADSs are listed. In addition, the SEC maintains a website that contains electronically filed information, which can be accessed at http://www.sec.gov.

I. Subsidiary Information.

Not applicable.

Item  11.Quantitative and Qualitative Disclosures About Market Risk

We are exposed to risks arising from changes in commodity prices, interest rates and foreign exchange rates that affect the generation, transmission and distribution businesses in the countries where we operate. Our Board of Directors approves risk management policies at all levels.

Commodity Price Risk

In our electricity generation and transmission business segment, we are exposed to market risks arising from the price volatility of electricity, natural gas, diesel oil, and coal. We seek to ensure our fuel supply by securing long-term contracts with our suppliers for periods that are expected to match the lifetime of our generation assets. As of December 31, 2016 and 2015, we did not hold contracts classified as derivative financial instruments or financial instruments related to natural gas.

In the countries where we operate using coal and diesel oil, the dispatch or bidding mechanism allows the thermal power plants to cover their operating costs. However, under certain circumstances, fuel price fluctuations might affect marginal costs. As of December 31, 2016 and 2015, we did not hold any contracts classified as either derivative financial instruments or financial instruments related either to coal or petroleum-based liquid fuels.

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Additionally, through adequate commercial risk mitigation policies, and a hydro-thermal power plant mix, we seek to protect our operating income from electricity price volatility. During 2016, Emgesa entered the energy derivatives market to mitigate spot price volatility. As of December 31, 2016, we held contracts classified as derivative financial instruments related to energy futures (69.8 GWh of energy future purchases and 15.1 GWh of energy future sales). As of December 31, 2016, we did not hold electricity price-sensitive instruments.

We are continually analyzing strategies to hedge commodity price risk, like transferring commodity price variations to the customers’ contract prices and/or permanently adjusting commodity indexed price formulas for new Power Purchase Agreements (“PPAs”) according to our exposure and/or analyzing ways to mitigate risk through hydrological insurance in dry years. In the future we may use price-sensitive instruments.

Interest Rate and Foreign Currency Risk

As of December 31, 2016, the carrying values according to maturity and the corresponding fair value of our interest bearing debt are detailed below.  Values do not include derivatives.  

	Expected maturity date
For the year ended December 31,	2017			2018			2019			2020			2021			Thereafter			Total			Fair Value(2)
	(in millions of Ch$)(1)
Fixed Rate
Ch$/UF	—			—			—			—			—			—			—			—
Weighted average interest rate	—			—			—			—			—			—			—			—
US$		18,584			19,724			17,666			26,764			7,329			429,394			519,461			532,678
Weighted average interest rate		2.7	%		5.1	%		5.5	%		5.1	%		3.1	%		4.1	%		4.2	%	—
Other currencies(3)		76,452			47,819			117,005			76,580			190,670			221,187			729,712			809,321
Weighted average interest rate		6.9	%		6.1	%		7.5	%		7.4	%		9.7	%		6.7	%		7.7	%	—
Total fixed rate		95,036			67,543			134,671			103,344			197,999			650,581			1,249,173			1,341,999
Weighted average interest rate		6.1	%		5.8	%		7.3	%		6.8	%		9.4	%		5.0	%		6.2	%	—
Variable Rate
Ch$/UF		3,646			3,856			4,077			4,312			4,560			2,377			22,828			26,186
Weighted average interest rate		9.0	%		9.0	%		9.0	%		9.0	%		9.0	%		9.0	%		9.0	%	—
US$		32,026			42,688			50,922		—			—				764			126,400			126,400
Weighted average interest rate		2.1	%		3.1	%		2.9	%	—			—				1.9	%		2.7	%
Other currencies(3)		318,699			283,540			256,771			92,085			89,531			408,785			1,449,411			1,588,253
Weighted average interest rate		12.5	%		12.4	%		12.1	%		11.3	%		11.8	%		11.5	%		12.0	%	—
Total variable rate		354,371			330,084			311,770			96,397			94,091			411,162			1,598,639			1,740,839
Weighted average interest rate		11.5	%		11.1	%		10.5	%		11.2	%		11.7	%		11.5	%		11.2	%	—
Total		449,407			397,627			446,441			199,741			292,090			1,061,743			2,847,812			3,082,838

(1) Calculated based on the Observed Exchange Rate as of December 31, 2016, which was Ch$ 669.47 per US$ 1.00.

(2) As of December 31, 2016, fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(3) “Other currencies” include the Brazilian real, Colombian peso, Argentine peso and Peruvian Nuevo Sol.

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As of December 31, 2015, the carrying values according to maturity and the corresponding fair value of our interest bearing debt are detailed below.  Values do not include derivatives.

	Expected maturity date
For the year ended December 31,	2016			2017			2018			2019			2020			Thereafter			Total			Fair Value(2)
	(in millions of Ch$)(1)
Fixed Rate
Ch$/UF	0.06			—			—			—			—			—			0.06			0.06
Weighted average interest rate	6.7%			—			—			—			—			—				6.7	%	—
US$		200,507			12,413			15,499			13,397			23,248			31,006			296,069			314,917
Weighted average interest rate	6.6%				2.8	%		5.0	%		5.6	%		5.0	%		2.4	%		5.7	%	—
Other currencies(3)		94,032			65,649			34,309			53,084			37,152			296,933			581,159			599,493
Weighted average interest rate	6.9%				7.0	%		5.6	%		6.1	%		6.5	%		8.4	%		7.5	%	—
Total fixed rate		294,539			78,062			49,808			66,481			60,400			327,939			877,228			914,410
Weighted average interest rate		6.7	%		6.4	%		5.4	%		6.0	%		5.9	%		7.8	%		6.9	%	—
Variable Rate
Ch$/UF		3,354			3,547			3,750			3,966			4,194			6,748			25,559			29,494
Weighted average interest rate		10.2	%		10.2	%		10.2	%		10.2	%		10.2	%		10.2	%		10.2	%	—
US$		41,995			18,154			18,024		—			—				810			78,984			78,984
Weighted average interest rate		2.6	%		2.0	%		2.0	%	—			—				1.5	%		2.3	%	—
Other currencies(3)		227,250			286,590			252,238			182,614			76,134			424,389			1,449,214			1,450,013
Weighted average interest rate		12.0	%		12.6	%		12.3	%		11.8	%		8.9	%		9.2	%		11.2	%	—
Total variable rate		272,599			308,291			274,012			186,580			80,328			431,947			1,553,757			1,558,491
Weighted average interest rate		10.5	%		12.0	%		11.6	%		11.8	%		9.0	%		9.2	%		10.7	%	—
Total		567,138			386,353			323,820			253,061			140,728			759,886			2,430,985			2,472,901

(1) Calculated based on the Observed Exchange Rate as of December 31, 2015, which was Ch$ 710.16 per US$ 1.00.

(2) As of December 31, 2015, fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(3) “Other currencies” include the Brazilian real, Colombian peso, Argentine peso and Peruvian Nuevo Sol.

Interest Rate Risk

Our policy aims to minimize the average cost of debt and reduce the volatility of our financial results. Depending on our estimates and the debt structure, we sometimes manage interest rate risk through the use of interest rate derivatives.

As of December 31, 2016 and 2015, 44% and 30%, respectively of our total outstanding debt was denominated in fixed terms and 56% and 70% respectively was subject to variable interest rates. Because of the exposure to variable interest rate risks, we engage in derivative hedging instruments.

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As of December 31, 2016, the carrying values for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2017		2018		2019		2020		2021		Thereafter		Total		Fair Value(2)
	(in millions of Ch$)(1)
Variable to fixed rates		22,735		—		—		—		—		—		22,735		126
Fixed to variable rates		—		—		—		—		—		—		—		—
Total		22,735		—		—		—		—		—		22,735		126

(1) Calculated based on the Observed Exchange Rate as of December 31, 2016, which was Ch$ 669.47 per US$ 1.00.

(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

As of December 31, 2015, the carrying values for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2016		2017		2018		2019		2020		Thereafter		Total		Fair Value(2)
	(in millions of Ch$)(1)
Variable to fixed rates		20,096		40,423		—		—		—		—		60,519		1,603
Fixed to variable rates		—		—		—		—		—		—		—		—
Total		20,096		40,423		—		—		—		—		60,519		1,603

(1) Calculated based on the Observed Exchange Rate as of December 31, 2015, which was Ch$ 710.16 per US$ 1.00.

(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

Foreign Currency Risk

Our policy seeks to maintain a balance between the currency in which cash flows are indexed and the currency of the principal debt of each company. Most of our subsidiaries have access to funding in the same currency as their revenues, therefore reducing the exchange rate volatility impact. In some cases, we cannot fully benefit from this, and therefore, we try to manage the exposure with financial derivatives such as cross currency swaps or currency forwards, among others. However, this may not always be possible due to market conditions. This is the case of Costanera in Argentina which has its revenues linked to the Argentine peso, and a substantial part of its debt denominated in U.S. dollars, with no possibility of hedging this debt under reasonable market conditions. Costanera’s debt denominated in U.S. dollars amounted to Ch$ 34.1 billion as of December 31, 2016.

As of December 31, 2016, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2017		2018		2019		2020		2021		Thereafter		Total		Fair Value(2)
	(in millions of Ch$)(1)
UF to US$		—		—		—		—		—		—		—		—
US$ to Ch$/UF		—		—		—		—		—		—		—
US$ to R$		—		30,812		57,048		—		—		—		87,860		(13,518	)
US$ to other currencies(3)		—		—		—		—		—		—		—		—
Other currencies to US$		—		—		—		—		—		—		—		—
Total		—		30,812		57,048		—		—		—		87,860		(13,518	)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2016, which was Ch$ 669.47 per US$ 1.00.

(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

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(3) “Other currencies” include the Euro, Brazilian real, Colombian peso, Argentine peso and Peruvian Nuevo Sol.

As of December 31, 2015, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2016		2017		2018		2019		2020		Thereafter		Total		Fair Value(2)
	(in millions of Ch$)(1)
UF to US$		—		—		—		—				—		—
US$ to Ch$/UF		242,753				—		—		—		—		242,753		(67,966	)
Ch$ to US$		45,243		—		—		—		—		—		45,243		(311	)
US$ to other currencies(3)		—		—		—		—		—		—		—		—
Other currencies to US$		—		—		—		—		—		—		—		—
Total		287,996		—		—		—	—			—		287,996		(68,277	)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2015, which was Ch$ 710.16 per US$ 1.00.

(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

(3) “Other currencies” include the Euro, Brazilian real, Colombian peso, Argentine peso and Peruvian Nuevo Sol.

For further detail please refer to Note 19.6 of the Notes to our consolidated financial statements.

Effective January 1, 2017, our functional currency is the U.S. dollar. For further information on the change in functional currency 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—e. Critical Accounting Policies— Change in Functional and Reporting Currency for Financial Reporting” and “Item 3. Key Information—D. Risk Factors.”

(d) Safe Harbor

The information in this “Item 11. Quantitative and Qualitative Disclosures About Market Risk,” contains information that may constitute forward-looking statements. See “Forward-Looking Statements” in the Introduction of this Report for safe harbor provisions.

Item 12.Description of Securities Other Than Equity Securities

A. Debt Securities.

Not applicable.

B. Warrants and Rights.

Not applicable.

C. Other Securities.

Not applicable.

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D. American Depositary Shares.

Depositary Fees and Charges

Our ADS program’s depositary is Citibank, N.A. The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. In the case of distributions other than cash, the Depositary will invoice the applicable ADS record date holders. The Depositary may generally refuse to provide the requested services until its fees for those services are paid. Under the terms of the Deposit Agreement, an ADS holder may have to pay the following service fees to the Depositary:

Service Fees	Fees
(1) Issuance of ADS upon deposit of shares (excluding issuances as a result of distributions described in paragraph (4) below)	Up to US$ 5 per 100 ADSs (or fraction thereof) issued
(2) Delivery of deposited securities against surrender of ADS	Up to US$ 5 per 100 ADSs (or fraction thereof) surrendered
(3) Distribution of cash dividends or other cash distributions (i.e., sale of rights and other entitlements)	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(4) Distribution of ADS pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADS	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(5) Distribution of securities other than ADS or rights to purchase additional ADS (i.e., spin-off of shares)	Up to US$ 5 per 100 ADSs (or fraction thereof) held
(6) Depositary services	Up to US$ 5 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary

The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. In the case of distributions other than cash, the Depositary will invoice the applicable ADS record date holders. The Depositary may generally refuse to provide the requested services until its fees for those services are paid.

Depositary Payments for Fiscal Year 2016

The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2016, the Depositary reimbursed expenses related primarily to investor relations’ activities for a total amount of US$ 2.8 million (after the deduction of applicable U.S. taxes).

PART II

Item 13.Defaults, Dividend Arrearages and Delinquencies

None.

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

None.

Item 15.Controls and Procedures

(a) Disclosure Controls and Procedures

We carried out an evaluation under the supervision and with the participation of our senior management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) for the year ended December 31, 2016.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error, and the circumvention or overriding of the controls and procedures. Accordingly, our disclosure controls and procedures are designed to provide reasonable assurance of achieving their control objectives.

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Based upon our evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is gathered and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives, and our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

As required by Section 404 of the Sarbanes-Oxley Act of 2002, our management is responsible for establishing and maintaining “adequate internal control over financial reporting” (as defined in Rule 13 a-15 (f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS, as issued by the IASB.

Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.

Management assessed the effectiveness of its internal control over financial reporting for the year ended December 31, 2016. The assessment was based on criteria established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 framework”). Based on the assessment, our management has concluded that as of December 31, 2016, our internal control over financial reporting was effective.

(c) Attestation Report of the Registered Public Accounting Firm

Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2016. Their attestation report appears on page F-3.

(d) Changes in Internal Control Over Financial Reporting

During the first half of 2016, we finalized the implementation of our new “Internal Control Over Financial reporting Model” in our Colombian operations, which applies an end-to-end approach in order to enhance the design and documentation of our internal control over financial reporting processes and their related controls to maintain suitable controls over our financial reporting.

Except as described above, there were no additional changes in our internal control over financial reporting identified in connection with the evaluation required by Rules 13a-15(d)  or 15d-15(d)  under the Exchange Act that occurred during 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting model.

Item 16.Reserved

Item 16A.Audit Committee Financial Expert

As of December 31, 2016, the Directors’ Committee (which performs the functions of the Audit Committee) financial expert was Mr. Hernán Somerville, as determined by the Board of Directors. Mr. Somerville is an independent member of the Directors’ Committee pursuant to the requirement of both Chilean law and NYSE corporate governance rules.

Item 16B.Code of Ethics

Our standards of ethical conduct are governed by means of the following seven corporate rulings or policies: the Charter Governing Executives (“Estatuto del Directivo”), the Employee Code of Conduct, the Code of Ethics, the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Human Rights Policy, the Manual for the Management of Information of Interest to the Market (the “Manual”) and the Diversity Policy.

The Charter Governing Executives was adopted by the Board of Directors in May 2003 and is applicable to all executives contractually related to us or our subsidiaries in which we are the majority shareholder, including the Chief Executive Officer, the Chief Financial Officer and other senior officers of the Company. The objective of this set of rules is to establish standards for the

175

governance of our management’s actions, the behavior of management with respect to the principles governing their actions and the limitations and incompatibilities involved, all within the context of our vision, mission and values. Likewise, the Employee Code of Conduct explains our principles and ethical values, establishes the rules governing our contact with customers and suppliers, and establishes the principles that should be followed by employees, including ethical conduct, professionalism and confidentiality. Both documents also impose limitations on the activities that our executives and other employees may undertake outside the scope of their employment with us.

The Manual, adopted by our Board of Directors in May 2008 and amended in February 2010, addresses the following issues: applicable standards and blackout periods regarding the information in connection with transactions of our securities or those of our affiliates, entered into by directors, management, principal executives, employees and other related parties; the existence of mechanisms for the continuous disclosure of information that is of interest to the market; and mechanisms that provide protection for confidential information.

In addition to the corporate governance rules described above, our Board approved the Code of Ethics and the ZTAC Plan in its meeting held on June 24, 2010. The Code of Ethics is based on general principles such as impartiality, honesty, integrity and other values of similar importance, which are translated into detailed behavioral criteria. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with a special emphasis in avoiding corruption in the form of bribes, preferential treatment, and other similar matters.

On October 30, 2013, the Board approved the Human Rights Policy, which incorporates and adapts the general human rights principles championed by the United Nations into a corporate reality.

The Diversity Policy was approved by the Board of Directors on March 23, 2016. This policy aims to define the key principles required to spread a culture that focuses on diversity and is based on the respect and promotion of the principles of preventing arbitrary discrimination and encouraging equal opportunities and inclusion, which are fundamental values in the development of the Company’s activities. Under this policy, the Company seeks to improve the work environment and make possible a better quality of life at work. The Company is committed to creating an inclusive work environment where workers can develop their potential and maximize their contribution.

A copy of these documents is available on our webpage at www.enelamericas.clas well as upon request, free of charge, by writing or calling us at:

Enel Américas S.A.

Investor Relations Department

Santa Rosa 76, Piso 15

Santiago, Chile

(56-2) 2353-4682

During fiscal year 2016, there have been no amendments to any provisions of the documents described above. No waivers from any provisions of the Charter Governing Executives, the Employee Code of Conduct, the Code of Ethics, the ZTAC Plan or the Manual, were expressly or implicitly granted to the Chief Executive Officer, the Chief Financial Officer or any other senior financial officers of the Company in fiscal year 2016. However, at its meeting held on January 19, 2017, our Board of Directors approved an amendment to the Code of Ethics and ZTAC Plan to eliminate the reference to Law 19,885 in connection with political donations and to forbid them under all circumstances.

Item 16C.Principal Accountant Fees and Services

The following table provides information on the aggregate fees for approved services billed by our independent registered accounting firm, as well as the other members firms and their respective affiliates, by type of services for the periods indicated.

Services Rendered	2016		2015
	(in millions of Ch$)
Audit fees		1,789		1,872
Audit-related fees(1)		3,948		3,840
Tax fees(2)		20		—
All other fees (3)		—		663
Total		5,757		6,375

176

(1) Audit-related fees include audit services related to the group’s reorganization of Ch$ 3,087 million in 2016 and of Ch$ 3,487 million in 2015. In addition, 2016 audit-related fees include audit services related to the Yankee Bond we issued, totaling Ch$ 337 million, the special audit related to debt issuance in Colombia for Ch$ 146 million and the service of verification of sustainability report in Colombia for Ch$ 54 million.

(2) This amount corresponds to tax advice for the purpose of obtaining the tax benefit SUDENE (a benefit promoted by the Superintendence of Development of Northeast in Brazil) for Coelce.

(3)  The amount for 2015 corresponds to audit services mainly related to a project with respect to the research and development of energy efficiency in Brazil.

All of the fees disclosed under audit-related fees and all other fees were pre-approved by the Directors’ Committee pre-approval policies and procedures.

The amounts included in the table above and the related footnotes have been classified in accordance with SEC guidance.

Directors’ Committee Pre-Approval Policies and Procedures

Our external auditors are appointed by our shareholders at the OSM. Similarly, the shareholders of our subsidiaries, which are located in countries where applicable law and regulation so establishes, appoint their own external auditors.

The Directors’ Committee (which performs the functions of the Audit Committee), reviews engagement letters with external auditors, ensures quality control in respect of the services provided, reviews and controls independence issues, and other related matters.

The Directors’ Committee has a pre-approval policy regarding the contracting of our external auditor, or any affiliate of the external auditor, for professional services. The professional services covered by such policy include audit and non-audit services provided to us.

Fees payable in connection with recurring audit services are pre-approved as part of our annual budget. Fees payable in connection with non-recurring audit services, once they have been analyzed by the CFO, are submitted to the Directors’ Committee for approval or rejection.

The pre-approval policy established by the Directors’ Committee for non-audit services and audit-related fees is as follows:

• The business unit that has requested the service and the audit firm expected to perform the service must request that the CFO review the nature of the service to be provided.

• The CFO then analyzes the request and requires the selected audit firm to issue a certificate signed by the partner responsible for the audit of our consolidated financial statements confirming such audit firm’s independence.

• Finally, the proposal is submitted to the Directors’ Committee for approval or denial.

The Directors’ Committee has designed, approved, and implemented the necessary procedures to fulfill the new requirements described in SEC release number 34-53677, File No. PCAOB-2006-01 (Audit Committee Pre-Approval of Certain Tax Services).

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

Not applicable.

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

During 2016, we acquired the following number of our own shares:

Period	Total Number of Shares		Price (Ch$ per Share)
November 2016(1)		119,185,929		112.0

(1) Shares purchased by Enel Américas in connection with the exercise by shareholders of Enel Américas of statutory merger dissenters’ withdrawal rights in connection with the merger of Endesa Américas and Chilectra Américas with and into Enel Américas.  In addition to these shares, Enel Américas holds an additional 753,147,942 treasury shares which were deemed acquired by Enel Américas as a result of shares of Enel Américas that were authorized to be issued in the merger with respect to

177

the following but were instead retained by Enel Américas:  (i) shares of Endesa Américas acquired by Enel Américas in connection with the Enel Américas tender offer for shares and ADSs of Endesa Américas; (ii) treasury shares of Endesa Américas reacquired by Endesa Américas in connection with the exercise by shareholders of Endesa Américas of statutory merger dissenters’ withdrawal rights in connection with the merger; (iii) treasury shares of Chilectra Américas reacquired by Chilectra Américas in connection with the exercise by shareholders of Chilectra Américas of statutory merger dissenters’ withdrawal rights in connection with the merger; and (iv) the aggregated fractional shares that were instead paid in cash.

At the ESM held on April 27, 2017, our shareholders approved the cancellation of all treasury shares and the change in the functional currency to U.S. dollars, which will result in a reduction of share capital from Ch$ 4,621,809,178,631 divided into 58,324,975,387 registered common shares (same series and no par value), to US$ 6,763,204,424 divided into 57,452,641,516 registered common shares (same series and no par value).

Item 16F.Change in Registrant’s Certifying Accountant

None.

Item 16G.Corporate Governance

For a summary of the significant differences between our corporate governance practices and those applicable to domestic issuers under the corporate governance rules of the NYSE, see “Item 6. Directors, Senior Management and Employees — C. Board Practices.”

Item 16H.Mine Safety Disclosure

Not applicable.

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PART III

Item 17.Financial Statements

Not Applicable.

Item 18.Financial Statements

ENEL AMÉRICAS S.A. and Subsidiaries

Index to the Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firms:

Report of EY Servicios Profesionales de Auditoría y Asesorías SpA— Enel Américas S.A. 2016, 2015 and 2014	F-1
Report of EY Servicios Profesionales de Auditoría y Asesorías SpA — Enel Américas S.A. — Internal Control Over Financial Reporting 2016	F-3
Report of KPMG Auditores Consultores Ltda. — Enel Generación Chile S.A. 2015, and 2014	F-5
Consolidated Financial Statements:
Consolidated Statements of Financial Position as of December 31, 2016 and 2015	F-6
Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015 and 2014	F-8
Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015, and 2014	F-10
Consolidated Statements of Direct Cash Flows for the years ended December 31, 2016, 2015, and 2014	F-12
Notes to the Consolidated Financial Statements	F-13

Ch$	Chilean pesos
US$	U.S. dollars
UF	The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
ThCh$	Thousands of Chilean pesos
ThUS$	Thousands of U.S. dollars

Item 19.Exhibits

Exhibit	Description
1.1	By-laws (Estatutos) of Enel Américas S.A., as amended.
8.1	List of Principal Subsidiaries as of December 31, 2016
12.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
12.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
13.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act
23.1	Consent of EY Servicios Profesionales de Auditoría y Asesorías SpA., an independent registered public accounting firm (Enel Américas S.A.)
23.2	Consent of KPMG Auditores Consultores Ltda., an independent registered public accounting firm (Enel Generación Chile S.A.).

We will furnish to the Securities and Exchange Commission, upon request, copies of any not filed instruments that define the rights of stakeholders of Enel Américas.

179

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

ENEL AMÉRICAS S.A.
By:	/s/ Luca D’Agnese
Name:	Luca D’Agnese
Title:	Chief Executive Officer

Date:  April 28, 2017

180

Enel Américas S.A. (formerly named Enersis Américas S.A.) and its Subsidiaries

Consolidated financial statements as of December 31, 2016

Index to the Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm
Report of EY Servicios Profesionales de Auditoría y Asesorías Limitada SpA — Enel Américas S.A. 2016, 2015 and 2014	F-1
Report of EY Servicios Profesionales de Auditoría y Asesorías Limitada SpA — Enel Américas S.A. — Internal Control Over Financial Reporting 2016	F-3
Report of KPMG Auditores Consultores Ltda. — Enel Generación Chile S.A. 2015 and 2014	F-5
Consolidated Financial Statements:
Consolidated Statements of Financial Position as of December 31, 2016 and 2015	F-6
Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015 and 2014	F-8
Consolidated Statements of Changes in Equity for the years ended December 31, 2016, 2015 and 2014	F-10
Consolidated Statements of Direct Cash Flows for the years ended December 31, 2016, 2015 and 2014	F-12
Notes to the Consolidated Financial Statements	F-13

Ch$	Chilean pesos
US$	U. S. dollars
UF	The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
ThCh$	Thousands of Chilean pesos
ThUS$	Thousands of U.S. dollars

    EY Audit SpA Avda. Presidente Riesco 5435, piso 4, Santiago     Tel: +56 (2) 2676 1000 www.eychile.cl

Report of Independent Registered Public Accounting Firm

To Shareholders and Directors of

Enel Américas S.A.

We have audited the accompanying consolidated statements of financial position of Enel Américas S.A. (formerly Enersis Américas S.A.) and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

The consolidated financial statements of the Company include the 2015 and 2014 consolidated financial statements of its former subsidiary, Enel Generación Chile S.A. (Formerly Empresa Nacional de Electridad S.A (“Enel Generación Chile”)). The consolidated financial statements of Enel Generación Chile for 2015 and 2014 include the financial statements of the following entities, each having been prepared in conformity with its respective local statutory accounting basis: Emgesa S.A. E.S.P (“Emgesa”) and Enel Argentina S.A. (Formerly Endesa Argentina S.A. “Enel Argentina”) (both former subsidiaries of Enel Generación Chile), and of Enel Brasil S.A. (“Enel Brasil”) (a consolidated subsidiary of the Company that was also a 38.64% percent owned investee of Enel Generación Chile accounted for using the equity method). Except for the amounts included in Enel Generación Chile’s consolidated financial statements for 2015 and 2014 relating to Emgesa, Enel Argentina and Enel Brasil, which we subjected to our audit procedures in the context of the consolidated financial statements of Enel Americas, taken as a whole, we did not audit the consolidated financial statements of Enel Generación Chile for 2015 and 2014. The consolidated financial statements of Enel Generación Chile for 2015 and 2014, exclusive of the amounts relating to Emgesa, Enel Argentina and Enel Brasil, reflect total assets constituting 28.3% at December 31, 2015, total revenues and other operating income constituting 5.5% in 2015 and 5.4 % in 2014 and income (loss) after tax from discontinued operations constituting (17.5) % in 2015 and (94.5) % in 2014 of the related consolidated totals. Enel Generación Chile’s consolidated financial statements for 2015 and 2014 were audited by other auditors whose report has been furnished to us, and our opinion on the Company’s consolidated financial statements, insofar as it relates to the amounts included for Enel Generación Chile (but exclusive of the amounts for Emgesa, Enel Argentina and Enel Brasil), is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors (see second paragraph above), the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Enel Américas S.A. and subsidiaries at December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board.

F-1

    EY Audit SpA Avda. Presidente Riesco 5435, piso 4, Santiago     Tel: +56 (2) 2676 1000 www.eychile.cl

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Enel Americas S.A.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated April 27, 2017 expressed an unqualified opinion thereon.

/s/ EY Audit SpA.                

EY Audit SpA.

Santiago, Chile

April 27, 2017

F-2

    EY Audit SpA Avda. Presidente Riesco 5435, piso 4, Santiago     Tel: +56 (2) 2676 1000 www.eychile.cl

Report of Independent Registered Public Accounting Firm On Internal Control Over Financial Reporting

The Board of Directors and Shareholders of Enel Américas S.A.

We have audited the internal control over financial reporting of Enel Américas S.A. (formerly Enersis Américas S.A.) and subsidiaries (the “Company”) as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria).  The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F-3

    EY Audit SpA Avda. Presidente Riesco 5435, piso 4, Santiago     Tel: +56 (2) 2676 1000 www.eychile.cl

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, based on our audit and the report of other auditors, Enel Américas S.A. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the  consolidated statements of financial position of Enel Américas S.A. and subsidiaries as of December 31, 2016 and 2015 and the related consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016, and our report dated April 27, 2017 expressed an unqualified opinion thereon based on our audits and the report of other auditors.

/s/ EY Audit SpA.          .

EY Audit SpA.

Santiago, Chile

April 27, 2017

F-4

  KPMG Auditores Consultores Ltda. Av. Isidora Goyenechea 3520, Piso 2 Las Condes, Santiago, Chile     Teléfono  +56 (2) 2798 1000 Fax  +56 (2) 2798 1001 www.kpmg.cl

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Enel Generación Chile S.A. (Enel Generación Chile) Formerly Named Empresa Nacional de Electricidad S.A. (Endesa−Chile):

We have audited the consolidated statement of financial position of Enel Generación and subsidiaries (the Company) as of December 31, 2015, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for the years ended December 31, 2015 and 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Emgesa S.A. E.S.P. and its subsidiaries and Endesa Argentina S.A. and its subsidiaries which are classified as available for distribution, which statements reflect total assets constituting 33.52 percent of the Company’s consolidated total assets as of December 31, 2015, and ThCh$ 321,253,877 and ThCh$ 345,341,681 of the Company’s consolidated profit from discontinued operations for the years ended December 31, 2015 and 2014, respectively. In addition, we did not audit the financial statements of Enel Brasil S.A. classified as available for distribution (a 38.64 percent owner investee company). The Company’s investment in Enel Brasil S.A. as of December 31, 2015 was ThCh$ 444,182,602, and its equity in earnings was ThCh$36,473,505 and ThCh$62,181,301 for the years ended December 31, 2015 and 2014, respectively. Those consolidated financial statements prepared in accordance with the local statutory accounting basis were audited by other auditors whose reports have been furnished to us and our opinion, insofar as it relates to the amounts included for those entities on such basis of accounting, is based solely on the reports of the other auditors. Accordingly, we have audited the conversion adjustments to the financial statements of these subsidiaries and nonsubsidiary investees prepared in accordance with the local statutory accounting basis to conform them to the Company’s accounting basis referred to below.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Enel Generación Chile and subsidiaries as of December 31, 2015, and the results of their operations and their cash flows for the years ended December 31, 2015 and 2014, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

/s/ KPMG

KPMG Auditores Consultores Ltda.

Santiago, Chile

April 29, 2016

KPMG Auditores Consultores Ltda, a Chilean limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

F-5

ENEL AMÉRICAS S.A. (FORMERLY NAMED ENERSIS AMÉRICAS S.A.) AND SUBSIDIARIES

Consolidated Statements of Financial Position

As of December 31, 2016 and 2015

(In thousands of Chilean pesos)

ASSETS	Note	12-31-2016	12-31-2015
		ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	7	1,800,510,297	1,185,163,344
Other current financial assets	8	91,219,605	68,262,446
Other current non-financial assets		96,025,225	101,989,057
Trade and other current receivables	9	1,030,219,227	1,088,131,567
Current accounts receivable from related parties	10	30,541,199	3,566,930
Inventories	11	66,410,049	95,057,897
Current tax assets	12	82,325,259	47,454,588
Total current assets other than assets or groups of assets for disposal classified as held for sale or as held for distribution to owners		3,197,250,861	2,589,625,829
Non-current assets or disposal groups held for sale or for distribution to owners	5	-	5,323,935,881
TOTAL CURRENT ASSETS		3,197,250,861	7,913,561,710
NON-CURRENT ASSETS
Other non-current financial assets	8	689,092,438	489,528,204
Other non-current non-financial assets		72,575,180	77,562,708
Trade and other non-current receivables	9	359,647,596	398,695,864
Non-current accounts receivable from related parties	10	240,677	355,485
Investments accounted for using the equity method	13	1,184,961	30,960,445
Intangible assets other than goodwill	14	1,211,846,744	981,399,272
Goodwill	15	478,509,122	444,199,047
Property, plant and equipment	16	5,150,337,059	5,003,566,633
Deferred tax assets	17	120,870,868	109,325,023
TOTAL NON-CURRENT ASSETS		8,084,304,645	7,535,592,681
TOTAL ASSETS		11,281,555,506	15,449,154,391

F-6

ENEL AMÉRICAS S.A. (FORMERLY NAMED ENERSIS AMÉRICAS S.A.) AND SUBSIDIARIES

Consolidated Statements of Financial Position

As of December 31, 2016 and 2015

(In thousands of Chilean pesos)

LIABILITIES AND EQUITY	Note	12-31-2016	12-31-2015
		ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	18	504,684,363	687,873,508
Trade and other current payables	21	1,655,340,875	1,452,824,207
Current accounts payable to related parties	10	111,704,039	109,897,508
Other current provisions	22	120,013,445	127,299,176
Current tax liabilities	12	134,876,333	142,607,960
Other current non-financial liabilities		32,171,299	39,226,339
Total current liabilities other than those associated with groups of assets for disposal classified as held for sale		2,558,790,354	2,559,728,698
Liabilities associated with disposal groups held for sale or for distribution to owners	5	-	1,945,652,102
TOTAL CURRENT LIABILITIES		2,558,790,354	4,505,380,800
NON-CURRENT LIABILITIES
Other non-current financial liabilities	18	2,396,753,894	1,847,296,592
Trade and other non-current payables	21	342,774,881	283,544,254
Other long-term provisions	22	233,279,486	183,848,284
Deferred tax liabilities	17	220,629,657	231,904,615
Non-current provisions for employee benefits	23	228,525,324	187,270,474
Other non-current non-financial liabilities		25,553,337	20,100,992
TOTAL NON-CURRENT LIABILITIES		3,447,516,579	2,753,965,211
TOTAL LIABILITIES		6,006,306,933	7,259,346,011
EQUITY
Issued capital	24.1	4,621,809,178	5,804,447,986
Treasury shares	24.1	(94,046,713)	-
Retained earnings		2,143,057,158	3,380,661,523
Other reserves	24.5	(2,520,350,733)	(3,158,960,224)
Equity attributable to shareholders of Enel Américas		4,150,468,890	6,026,149,285
Non-controlling interests	24.6	1,124,779,683	2,163,659,095
TOTAL EQUITY		5,275,248,573	8,189,808,380
TOTAL LIABILITIES AND EQUITY		11,281,555,506	15,449,154,391

F-7

ENEL AMÉRICAS S.A. (FORMERLY NAMED ENERSIS AMÉRICAS S.A.) AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Nature

For the years ended December 31, 2016, 2015 and 2014

(In thousands of Chilean pesos)

		For the years ended December 31,
STATEMENTS OF PROFIT (LOSS)	Note	2016	2015	2014
		ThCh$	ThCh$	ThCh$
Revenues	25	4,768,125,691	4,667,645,310	4,806,455,737
Other operating income	25	429,160,279	633,794,268	399,914,051
Revenues and Other Operating Income		5,197,285,970	5,301,439,578	5,206,369,788
Raw materials and consumables used	26	(2,645,098,805)	(2,777,201,512)	(2,631,669,436)
Contribution Margin		2,552,187,165	2,524,238,066	2,574,700,352
Other work performed by the entity and capitalized		67,246,385	67,101,269	55,770,418
Employee benefits expenses	27	(423,364,098)	(487,698,147)	(389,668,473)
Depreciation and amortization expense	28	(319,999,041)	(320,542,197)	(350,742,750)
Impairment loss recognized in the period’s profit or loss	28	(106,214,656)	(39,811,756)	(38,329,942)
Other expenses	29	(552,700,730)	(488,528,749)	(463,729,264)
Operating income		1,217,155,025	1,254,758,486	1,388,000,341
Other gains (losses)	30	8,209,483	(6,566,225)	876,554
Financial income	31	186,937,514	294,770,272	251,121,762
Financial costs	31	(522,800,993)	(385,455,340)	(432,314,329)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	13	1,830,147	3,332,971	2,560,023
Foreign currency exchange differences	31	39,850,562	128,238,047	(18,493,594)
Gains (losses) from indexed assets and liabilities	31	(698,141)	(9,266,040)	(13,630,068)
Income from continuing operations, before taxes		930,483,597	1,279,812,171	1,178,120,689
Income tax expenses, continuing operations	17	(359,368,522)	(523,663,212)	(425,957,462)
INCOME AFTER TAX FROM CONTINUING OPERATIONS		571,115,075	756,148,959	752,163,227
Income after tax from discontinued operations	5.1.II.iii	115,130,387	388,320,526	215,331,981
NET INCOME		686,245,462	1,144,469,485	967,495,208
Net income attributable to:
Shareholders of Enel Américas		383,059,534	661,586,917	571,873,342
Non-controlling interests	24.6	303,185,928	482,882,568	395,621,866
NET INCOME		686,245,462	1,144,469,485	967,495,208
		-	-	-
Basic earnings per share
Basic earnings per share from continuing operations	Ch$/Share	6.13	8.35	8.34
Basic earnings per share from discontinued operations	Ch$/Share	1.57	5.13	3.31
Basic earnings per share	Ch$/Share	7.70	13.48	11.65
Weighted average number of shares of common stock		49,768,783,340	49,092,772,762	49,092,772,762
Diluted earnings per share
Diluted earnings per share from continuing operations	Ch$/Share	6.13	8.35	8.34
Diluted earnings per share from discontinued operations	Ch$/Share	1.57	5.13	3.31
Diluted earnings per share	Ch$/Share	7.70	13.48	11.65
Weighted average number of shares of common stock		49,768,783,340	49,092,772,762	49,092,772,762

F-8

ENEL AMÉRICAS S.A. (FORMERLY NAMED ENERSIS AMÉRICAS S.A.) AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income, by Nature (continued)

For the years ended December 31, 2016, 2015 and 2014

(In thousands of Chilean pesos)

		For the years ended December 31,
STATEMENTS OF COMPREHENSIVE INCOME	Note	2016	2015	2014
		ThCh$	ThCh$	ThCh$
Net Income		686,245,462	1,144,469,485	967,495,208
Components of other comprehensive income that will not be reclassified subsequently to profit or loss, before taxes
Remeasurment (loss) from defined benefit plans	23.2.b	(19,879,558)	(19,027,368)	(36,681,734)
Other comprehensive loss that will not be reclassified subsequently to profit or loss		(19,879,558)	(19,027,368)	(36,681,734)
Components of other comprehensive income that will be reclassified subsequently to profit or loss, before taxes
Foreign currency translation gains (losses)		145,304,104	(644,537,672)	4,370,648
Gains (losses) from available-for-sale financial assets		659,734	(442,864)	1,849
Share of other comprehensive income (loss) from associates and joint ventures accounted for using the equity method		(14,086,364)	(552,420)	13,476,871
Gains (losses) from cash flow hedge		14,896,221	(155,456,845)	(138,993,868)
Adjustments from reclassification of cash flow hedges, transferred to profit or loss		4,531,325	17,215,453	(6,898,502)
Other comprehensive income (loss) that will be reclassified subsequently to profit or loss		151,305,020	(783,774,348)	(128,043,002)
Total components of other comprehensive income (loss), before taxes		131,425,462	(802,801,716)	(164,724,736)
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss
Income tax related to defined benefit plans		6,486,162	6,018,363	12,694,514
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss		6,486,162	6,018,363	12,694,514
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss
Income tax related to cash flow hedge		(4,608,636)	36,399,000	35,887,996
Income tax related to available-for-sale financial assets		-	(291)	(1,462)
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss		(4,608,636)	36,398,709	35,886,534
Total Other Comprehensive Income (Loss)		133,302,988	(760,384,644)	(116,143,688)
TOTAL COMPREHENSIVE INCOME		819,548,450	384,084,841	851,351,520
Comprehensive income attributable to:
Shareholders of Enel Américas		533,275,016	145,175,235	524,282,247
Non-controlling interests		286,273,434	238,909,606	327,069,273
TOTAL COMPREHENSIVE INCOME		819,548,450	384,084,841	851,351,520

F-9

ENEL AMÉRICAS S.A. (FORMERLY NAMED ENERSIS AMÉRICAS S.A.) AND SUBSIDIARIES

Consolidated Statements of Changes in Equity

For years ended December 31, 2016, 2015 and 2014

(In thousands of Chilean pesos)

Statement of Changes in Equity			Issued Capital	Treasury Shares	Changes in Other Reserves							Retained Earnings	Equity Attributable to Shareholders of Enel Américas	Non-Controlling Interests	Total Equity
					Reserve for Exchange Differences in Translation	Reserves for Cash Flow Hedges	Reserve for Gains and Losses for Defined Benefit Plans	Reserve for Gains and Losses on Remeasuring Available-for-Sale Financial Assets	Other Miscellaneous Reserves	Amounts recognized in other comprehensive income and accumulated in equity related to non-current assets or groups of assets for disposal classified as held for sale (1)	Other Reserves
Equity at beginning of period 1/1/2016			5,804,447,986	-	(418,992,914)	(9,826,557)	-	(167,739)	(2,628,536,018)	(101,436,996)	(3,158,960,224)	3,380,661,523	6,026,149,285	2,163,659,095	8,189,808,380
Changes in equity
	Comprehensive income:
		Profit (loss)										383,059,534	383,059,534	303,185,928	686,245,462
		Other comprehensive income (loss)			158,607,583	2,179,035	(8,941,891)	319,842	(127,887)	(1,821,200)	150,215,482		150,215,482	(16,912,494)	133,302,988
		Comprehensive income											533,275,016	286,273,434	819,548,450
	Dividends											(196,867,561)	(196,867,561)	(190,520,285)	(387,387,846)
	Increase (decrease) through other distribution by owners		(2,229,108,976)	-	-	-	-	-	915,743,914	103,258,196	1,019,002,110	(1,414,854,447)	(2,624,961,313)	(639,795,698)	(3,264,757,011)
	Increase (decrease) from other changes		1,046,470,168	-	-	-	8,941,891	-	(539,549,992)	-	(530,608,101)	(8,941,891)	506,920,176	(494,836,863)	12,083,313
	Increase (decrease) through treasury share transactions		-	(94,046,713)								-	-	-	(94,046,713)
	Total changes in equity		(1,182,638,808)	(94,046,713)	158,607,583	2,179,035	-	319,842	376,066,035	101,436,996	638,609,491	(1,237,604,365)	(1,875,680,395)	(1,038,879,412)	(2,914,559,807)
Equity at end of period 12/31/2016			4,621,809,178	(94,046,713)	(260,385,331)	(7,647,522)	-	152,103	(2,252,469,983)	-	(2,520,350,733)	2,143,057,158	4,150,468,890	1,124,779,683	5,275,248,573
Statement of Changes in Equity			Issued Capital	Share Premium	Changes in Other Reserves							Retained Earnings	Equity Attributable to Shareholders of Enel Américas	Non-Controlling Interests	Total Equity
					Reserve for Exchange Differences in Translation	Reserves for Cash Flow Hedges	Reserve for Gains and Losses for Defined Benefit Plans	Reserve for Gains and Losses on Remeasuring Available-for-Sale Financial Assets	Other Miscellaneous Reserves	Amounts recognized in other comprehensive income and accumulated in equity related to non-current assets or groups of assets for disposal classified as held for sale (1)	Other Reserves
Equity at beginning of period 1/1/2015			5,804,447,986	-	35,154,874	(69,404,677)	-	14,046	(2,619,970,627)	-	(2,654,206,384)	3,051,734,445	6,201,976,047	2,077,242,699	8,279,218,746
Changes in equity
	Comprehensive income
		Profit (loss)										661,586,917	661,586,917	482,882,568	1,144,469,485
		Other comprehensive income (loss)			(442,819,275)	(60,939,077)	(12,152,091)	(166,950)	(334,289)	-	(516,411,682)		(516,411,682)	(243,972,962)	(760,384,644)
		Comprehensive income											145,175,235	238,909,606	384,084,841
	Dividends											(320,507,748)	(320,507,748)	(151,308,255)	(471,816,003)
	Increase (decrease) from other changes		-	-	(11,328,513)	120,517,197	12,152,091	(14,835)	(8,231,102)	(101,436,996)	11,657,842	(12,152,091)	(494,249)	(1,184,955)	(1,679,204)
	Total changes in equity		-	-	(454,147,788)	59,578,120	-	(181,785)	(8,565,391)	(101,436,996)	(504,753,840)	328,927,078	(175,826,762)	86,416,396	(89,410,366)
Equity at end of period 12/31/2015			5,804,447,986	-	(418,992,914)	(9,826,557)	-	(167,739)	(2,628,536,018)	(101,436,996)	(3,158,960,224)	3,380,661,523	6,026,149,285	2,163,659,095	8,189,808,380

(1) See Note 5.1.II.ii

The accompanying notes are an integral part of these consolidated financial statements.

F-10

Statement of Changes in Equity			Issued Capital	Share Premium	Changes in Other Reserves							Retained Earnings	Equity Attributable to Shareholders of Enel Américas	Non-Controlling Interests	Total Equity
					Reserve for Exchange Differences in Translation	Reserves for Cash Flow Hedges	Reserve for Gains and Losses for Defined Benefit Plans	Reserve for Gains and Losses on Remeasuring Available-for-Sale Financial Assets	Other Miscellaneous Reserves	Amounts recognized in other comprehensive income and accumulated in equity related to non-current assets or groups of assets for disposal classified as held for sale	Other Reserves
Equity at beginning of period 1/1/2014			5,669,280,725	158,759,648	(56,022,016)	(3,086,726)	-	11,811	(2,414,023,486)	-	(2,473,120,417)	2,813,634,297	6,168,554,253	2,338,910,608	8,507,464,861
Changes in equity
	Comprehensive income
		Profit (loss)										571,873,342	571,873,342	395,621,866	967,495,208
		Other comprehensive income (loss)			29,929,142	(66,317,951)	(19,023,003)	2,235	7,818,482	-	(47,591,095)		(47,591,095)	(68,552,593)	(116,143,688)
		Comprehensive income											524,282,247	327,069,273	851,351,520
	Dividends											(314,750,191)	(314,750,191)	(459,728,319)	(774,478,510)
	Increase (decrease) from other changes		135,167,261	(158,759,648)	-	-	19,023,003	-	25,112,860	-	44,135,863	(19,023,003)	1,520,473	-	1,520,473
	Increase (decrease) from changes in ownership interests in subsidiaries that do not result in loss of control				61,247,748				(238,878,483)	-	(177,630,735)	-	(177,630,735)	(129,008,863)	(306,639,598)
	Total changes in equity		135,167,261	(158,759,648)	91,176,890	(66,317,951)	-	2,235	(205,947,141)	-	(181,085,967)	238,100,148	33,421,794	(261,667,909)	(228,246,115)
Equity at end of period 12/31/2014			5,804,447,986	-	35,154,874	(69,404,677)	-	14,046	(2,619,970,627)	-	(2,654,206,384)	3,051,734,445	6,201,976,047	2,077,242,699	8,279,218,746

The accompanying notes are an integral part of these consolidated financial statements.

F-11

ENEL AMÉRICAS S.A. (FORMERLY NAMED ENERSIS AMÉRICAS S.A.) AND SUBSIDIARIES

Consolidated Statements of Cash Flows, Direct

For the years ended December 31, 2016, 2015 and 2014

(In thousands of Chilean pesos)

		For the years ended December 31,
Statements of Direct Cash Flows	Note	2016	2015	2014
		ThCh$	ThCh$	ThCh$
Cash flows from (used in) operating activities
Types of collection from operating activities
Collections from the sale of goods and services		7,115,644,913	8,983,646,820	7,786,425,908
Collections from royalties, payments, commissions, and other income from ordinary activities		33,855,586	40,395,210	53,736,441
Collections from premiums and services, annual payments, and other benefits from policies held		11,554,520	24,800,978	20,348,278
Other collections from operating activities		406,066,541	593,726,467	793,806,980
Types of payment in cash from operating activities
Payments to suppliers for goods and services		(3,385,083,048)	(4,875,217,622)	(4,395,777,186)
Payments to and on behalf of employees		(459,014,411)	(554,559,784)	(482,784,407)
Payments on premiums and services, annual payments, and other obligations from policies held		(8,984,406)	(14,484,698)	(15,147,534)
Other payments for operating activities, net	7.f	(1,564,758,074)	(1,572,807,177)	(1,418,097,022)
Cash flows from (used in) operating activities
Income taxes paid		(377,099,387)	(451,694,741)	(428,343,722)
Other outflows of cash		(59,942,762)	(250,354,851)	(216,129,742)
Net cash flows from operating activities		1,712,239,472	1,923,450,602	1,698,037,994
Cash flows from (used in) investing activities
Cash flows from the loss of control of subsidiaries or other businesses	7.d	-	6,639,653	40,861,571
Cash flows used to obtain control of subsidiaries or other businesses		(3,004)	-	(37,654,762)
Other collections from the sale of equity or debt instruments belonging to other entities		507,884,254	395,810,811	1,126,402,278
Other payments to acquire equity or debt instruments belonging to other entities		(498,511,704)	(353,112,647)	(480,297,836)
Other payments to acquire stakes in joint ventures		-	(2,550,000)	(3,315,000)
Loans to related parties		(23,139,778)	-	-
Proceeds from the sale of property, plant and equipment		69,660,900	49,916	167,486
Purchases of property, plant and equipment		(557,243,206)	(1,090,624,099)	(825,909,425)
Purchases of intangible assets		(274,461,262)	(271,937,266)	(260,500,759)
Proceeds from the sale of other long-term assets		-	1,729,727	2,037,930
Purchases of other long-term assets		-	-	(2,952,035)
Payments from future, forward, option and swap contracts		(5,877,542)	(6,888,344)	(26,683,724)
Collections from future, forward, option and swap contracts		7,446,742	17,266,466	16,957,654
Collections from related parties		171,001,337	-	-
Dividends received		1,183,497	11,313,451	13,567,998
Interest received		85,494,100	58,724,646	93,410,873
Other inflows (outflows) of cash, net		19,594,150	18,278,638	44,220,761
Net cash flows used in investing activities		(496,971,516)	(1,215,299,048)	(299,686,990)
Cash flows from (used in) financing activities
Proceeds from issuing shares		-	-	8,783,766
Payments from changes in ownership interests in subsidiaries that do not result in loss of control		-	(2,374,346)	(385,132,160)
Payments to acquire or redeem own shares		(94,046,713)	-	-
Total proceeds from loans		1,066,820,517	475,558,223	774,199,941
Proceeds from long-term loans		913,506,531	105,645,839	740,518,825
Proceeds from short-term loans		153,313,986	369,912,384	33,681,116
Loans from related parties		72,355,078	-	-
Payment on borrowings		(699,474,041)	(614,937,402)	(622,496,486)
Payment on financial lease liabilities		(20,851,905)	(19,737,180)	(16,559,995)
Payments on loans to related parties		(71,836,483)	-	(17,236,440)
Dividends paid		(431,317,234)	(612,045,894)	(632,808,121)
Interest paid		(243,555,814)	(266,756,065)	(246,769,836)
Other inflows (outflows) of cash, net	7.e	(317,744,798)	(19,921,715)	(145,440,332)
Net cash flows from (used in) financing activities		(739,651,393)	(1,060,214,379)	(1,283,459,663)
Net increase (decrease) in cash and cash equivalents before effect of exchange rate changes		475,616,563	(352,062,825)	114,891,341
Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents		(4,531,455)	(23,287,179)	(16,503,717)
Net increase (decrease) in cash and cash equivalents		471,085,108	(375,350,004)	98,387,624
Cash and cash equivalents at beginning of period	7.c	1,329,425,189	1,704,775,193	1,606,387,569
Cash and cash equivalents at end of period	7.c	1,800,510,297	1,329,425,189	1,704,775,193

The accompanying notes are an integral part of these consolidated financial statements.

F-12

ENEL AMÉRICAS S.A. (FORMERLY NAMED Enersis Américas s.a.) AND SUBSIDIARIES

NotEs TO THE ConsolidaTED FINANCIAL STATEMENTS

Contents		Page
1.	THE GROUP’S ACTIVITIES AND FINANCIAL STATEMENTS	F-16
2.	BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS	F-16
2.1	Accounting principles	F-16
2.2	New accounting pronouncements	F-17
2.3	Responsibility for the information, judgments and estimates provided	F-24
2.4	Subsidiaries	F-25
	2.4.1 Changes in the scope of consolidation	F-25
	2.4.2 Consolidated companies with an economic equity interest of less than 50%	F-26
2.5	Investments in associates	F-26
2.6	Investments in joint arrangements	F-26
2.7	Basis of consolidation and business combinations	F-27
3.	ACCOUNTING POLICIES APPLIED	F-29
a)	Property, plant and equipment	F-29
b)	Goodwill	F-31
c)	Intangible assets other than goodwill	F-31
	c.1) Concessions	F-31
	c.2) Research and development expenses	F-32
	c.3) Other intangible assets	F-32
d)	Impairment of non-financial assets	F-32
e)	Leases	F-34
f)	Financial instruments	F-34
	f.1) Financial assets other than derivatives	F-34
	f.2) Cash and cash equivalents	F-35
	f.3) Impairment of financial assets	F-35
	f.4) Financial liabilities other than derivatives	F-35
	f.5) Derivative financial instruments and hedging transactions	F-35
	f.6) Derecognition of financial assets and liabilities	F-36
	f.7) Offsetting financial assets and liabilities	F-37
	f.8) Financial guarantee contracts	F-37
g)	Measurement of fair value	F-37
h)	Investments accounted for using the equity method	F-38
i)	Inventories	F-38
j)	Non-current assets (or disposal groups) classified as held for sale or as held for distribution to owners and discontinued operations	F-39
k)	Treasury shares	F-40
l)	Provisions	F-40
	l.1) Provisions for post-employment benefits and similar obligations	F-40
m)	Translation of balances in foreign currency	F-41
n)	Current/non-current classification	F-41
o)	Income taxes	F-41
p)	Revenues and expense recognition	F-42
q)	Earnings per share	F-43
r)	Dividends	F-43
s)	Share issuance costs	F-44
t)	Statement of cash flows	F-44
4.	SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS	F-45
a)	Regulatory framework	F-45
b)	Tariff Revisions	F-56

The accompanying notes are an integral part of these consolidated financial statements.

F-13

5.	NON-CURRENT ASSETS OR DISPOSAL GROUPS HELD FOR SALE OR HELD FOR DISTRIBUTION TO OWNERS AND DISCONTINUED OPERATIONS	F-61
6.	BUSINESS COMBINATION – MERGER BETWEEN CODENSA S.A. AND DISTRIBUIDORA ELECTRICA DE CUNDINAMARCA S.A. (DECSA) AND EMPRESA ELECTRICA DE CUNDINAMARCA S.A. (EEC)	F-66
7.	CASH AND CASH EQUIVALENTS	F-69
8.	OTHER FINANCIAL ASSETS	F-71
9.	TRADE AND OTHER RECEIVABLES	F-72
10.	BALANCES AND TRANSACTIONS WITH RELATED PARTIES	F-74
10.1	Balances and transactions with related parties	F-74
	a) Receivables from related companies	F-74
	b) Accounts payable to related companies	F-75
	c) Significant transactions and effects on income/expenses:	F-76
10.2	Board of directors and key management personnel	F-77
	a) Accounts receivable and payable and other transactions	F-77
	b) Compensation for directors	F-77
	c) Guarantees given by the Company in favor of the directors	F-79
10.3	Compensation for key management personnel	F-80
	a) Remunerations received by key management personnel	F-80
	b) Guarantees established by the Company in favor of key management personnel	F-80
10.4	Compensation plans linked to share price	F-80
11.	INVENTORIES	F-81
12.	CURRENT TAX ASSETS AND LIABILITIES	F-82
13.	INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD	F-83
13.1.	Investments accounted for using the equity method	F-83
14.	INTANGIBLE ASSETS OTHER THAN GOODWILL	F-85
15.	GOODWILL	F-87
16.	PROPERTY, PLANT AND EQUIPMENT	F-89
	a) Main investments	F-90
	b) Capitalized expenses	F-90
	c) Finance leases	F-91
	d) Operating leases	F-91
	e) Other information	F-91
17.	INCOME TAXES	F-93
	a) Income taxes	F-93
	b) Deferred taxes	F-94
18.	OTHER FINANCIAL LIABILITIES	F-97
18.1	Interest-bearing borrowings	F-97
18.2	Unsecured liabilities	F-100
18.3	Secured liabilities	F-100
18.4	Hedged debt	F-103
18.5	Other information	F-103
19.	RISK MANAGEMENT POLICY	F-104
19.1	Interest rate risk	F-104
19.2	Exchange rate risk	F-105
19.3	Commodities risk	F-105
19.4	Liquidity risk	F-105
19.5	Credit risk	F-106
19.6	Risk measurement	F-106
20.	FINANCIAL INSTRUMENTS	F-108
20.1	Financial instruments, classified by type and category	F-108
20.2	Derivative instruments	F-110
20.3	Fair value hierarchies	F-112
21.	TRADE AND OTHER CURRENT PAYABLES	F-113
22.	PROVISIONS	F-114
23.	EMPLOYEE BENEFIT OBLIGATIONS	F-115
23.1	General information	F-115
23.2	Details, changes and presentation in financial statements	F-116

The accompanying notes are an integral part of these consolidated financial statements.

F-14

24.	EQUITY	F-121
24.1	Equity attributable to the shareholders of Enel Américas	F-121
24.2	Foreign currency translation reserves	F-124
24.3	Capital Management	F-124
24.4	Restrictions on subsidiaries transferring funds to the parent	F-124
24.5	Other reserves	F-125
24.6	Non-controlling Interests	F-127
25.	REVENUE AND OTHER OPERATING INCOME	F-128
26.	RAW MATERIALS AND CONSUMABLES USED	F-129
27.	EMPLOYEE BENEFITS EXPENSE	F-129
28.	DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES	F-129
29.	OTHER EXPENSES	F-130
30.	OTHER GAINS (LOSSES)	F-130
31.	FINANCIAL RESULTS	F-131
32.	INFORMATION BY SEGMENT	F-133
32.1	Basis of segmentation	F-133
32.2	Generation and transmission, distribution and others	F-135
32.3	Segment information by country	F-137
32.4	Generation and Transmission, and Distribution by Country	F-139
33.	THIRD PARTY GUARANTEES, CONTINGENT ASSETS, LIABILITIES, AND OTHER COMMITMENTS	F-143
33.1	Direct guarantees	F-143
33.2	Indirect guarantees	F-143
33.3	Lawsuits and Arbitrations Proceedings	F-144
33.4	Financial restrictions	F-157
33.5	Other Information	F-160
34.	PERSONNEL FIGURES	F-167
35.	SANCTIONS	F-167
36.	ENVIRONMENT	F-168
37.	FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED	F-169
38.	SUBSEQUENT EVENTS	F-171
APPENDIX 1 ENEL AMÉRICAS GROUP ENTITIES:		F-173
APPENDIX 2 CHANGES IN THE SCOPE OF CONSOLIDATION:		F-174
APPENDIX 3 ASSOCIATES AND JOINT VENTURES:		F-175
APPENDIX 4 ADDITIONAL INFORMATION ON FINANCIAL DEBT:		F-176
APPENDIX 5 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY:		F-181
APPENDIX 6 ADDITIONAL INFORMATION OFFICIAL BULLETIN No. 715 OF FEBRUARY 3, 2012:		F-182
APPENDIX 6.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:		F-184
APPENDIX 6.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY:		F-187
APPENDIX 7 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS:		F-188

The accompanying notes are an integral part of these consolidated financial statements.

F-15

ENEL AMÉRICAS S.A. (FORMERLY NAMED ENERSIS AMÉRICAS S.A.) AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2106

(In thousands of Chilean pesos)

1. THE GROUP’S ACTIVITIES AND FINANCIAL STATEMENTS

Enel Américas S.A. (formerly named Enersis Américas S.A.) (hereinafter “the Company”) and its subsidiaries comprise the Enel Américas Group (hereinafter “the Group”).

The Company is a publicly traded corporation with registered address and head office located at Avenida Santa Rosa, No. 76, in Santiago, Chile. The Company is registered in the securities register of the Superintendence of Securities and Insurance of Chile (Superintendencia de Valores y Seguros or SVS) under number 175. In addition, the Company is registered with the Securities and Exchange Commission of the United States of America (hereinafter U.S. SEC) and its shares have been listed on the New York Stock Exchange since 1993.

The Company is a subsidiary of Enel Iberoamérica S.R.L., a company controlled by Enel S.p.A. (hereinafter “Enel”).

The Company was initially created in 1981 under the corporate name of Compañía Chilena Metropolitana de Distribución Eléctrica S.A. Later on, the Company changed its by-laws and its name to Enersis S.A., effective August 1, 1988. On March 1, 2016, as part of the reorganization process carried out by the Group (See Note 5.1), the Company by amending its by-laws, changed its corporate name to Enersis Américas S.A. Subsequently, on December 1, 2016, its corporate name was changed to Enel Américas S.A. For tax purposes, the Company operates under Chilean tax identification number 94.271.000-3.

As of December 31, 2016, the Group had 10,324 employees. During the year 2016, the Group averaged a total of 10,350 employees. See Note 34 for additional information regarding employee distribution by category and geographic location.

The Company’s corporate purpose consists of exploring for, developing, operating, generating, distributing, transmitting, transforming, and/or selling energy of any kind or form, whether in Chile or abroad, either directly or through other companies. It is also engaged in telecommunications activities, and it provides engineering consultation services in Chile and abroad. The Company’s corporate purpose also includes investing in, and managing, its investments in subsidiaries and associates which generate, transmit, distribute, or sell electricity, or whose corporate purpose includes any of the following:

(i)   Energy of any kind or form,

(ii)   Supplying public services, or services whose main component is energy,

(iii)   Telecommunications and information technology services, and

(iv)   Internet-based intermediation business.

The Group’s 2015 consolidated financial statements were approved by the Board of Directors at meeting held on February 26, 2016. The consolidated financial statements were then submitted to the consideration of a General Shareholders’ Meeting held on April 29, 2016, which finally approved the consolidated financial statements.

2. BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1 Accounting principles

These consolidated financial statements as of December 31, 2016 of the Group, approved by the Company’s Board of Directors at its meeting held on April 27, 2017, have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

These consolidated financial statements present fairly the financial position of the Company and its subsidiaries as of December 31, 2016 and 2015, as well as the results of their operations, the changes in equity, and their cash flows for the years ended December 31, 2016, 2015 and 2014.

These consolidated financial statements have been prepared under going concern assumptions on a historical cost basis except for, in accordance with IFRS, those assets and liabilities that are measured at fair value and those non-current assets and disposal groups held for sale, which are recognized at their carrying amount or fair value less cost of disposal, whichever is lower (see Note 3.g and 3.j).

These consolidated financial statements have been prepared from accounting records maintained by the Company and its subsidiaries. Each entity prepares its financial statements according to the accounting principles and standards in force in

The accompanying notes are an integral part of these consolidated financial statements.

F-16

each country, so the necessary adjustments and reclassifications have been made in the consolidation process in order to present the consolidated financial statements in accordance with IFRS.

These consolidated financial statements are presented in thousands of Chilean pesos (unless otherwise stated), as the Chilean peso is the functional currency of the Company and the presentation currency of the Group. Foreign operations are incorporated in accordance with the accounting policies stated in Notes 2.7 and 3.m.

2.2 New accounting pronouncements

a) Accounting pronouncements effective from January 1, 2016:

Improvements and Amendments	Mandatory application for annual periods beginning on or after:
Amendment to IFRS 11: Accounting for Acquisitions of Interests in Joint Operations This amendment to IFRS 11 “Joint Arrangements” states that the accounting standards contained in IFRS 3 and other standards that are pertinent to business combinations accounting must be applied to the accounting for acquiring an interest in a joint operation in which the activities constitute a business.	January 1, 2016
Improvements to IFRS (Cycles 2012-2014) These are a set of improvements that were necessary, but not urgent, and that amend the following standards IFRS 5 – Non-current assets held for sale and discontinued operations; IFRS7 - Financial Instruments: Disclosures; IAS 19 – Employee Benefits; and IAS 34 – Interim Financial Reporting.	January 1, 2016
Amendment to IAS 16 and IAS 38: Clarification of Acceptable Methods of Depreciation and Amortization The amendment to IAS 16 explicitly prohibits the use of revenue-based depreciation for property, plant and equipment. The amendment to IAS 38 introduces the rebuttable presumption that, for intangible assets, the revenue-based amortization method is inappropriate and establishes two limited exceptions.	January 1, 2016
Amendment to IAS 1: Disclosure Initiative The IASB has issued amendments to IAS 1 as part of its principal initiative to improve the presentation and disclosure of information in financial statements. These improvements are designed to assist companies in applying professional judgment to determine what type of information to disclose in their financial statements.	January 1, 2016
Amendment to IFRS 10, IFRS 12 and IAS 28: Investment Entities, Application of the Consolidation Exception The modifications, which have a restricted scope, introduce clarifications to the requirements for the accounting of investment entities. The modifications also provide relief in some circumstances, which will reduce the costs of applying the Standards.	January 1, 2016

The amendments and improvements to the standards, which came into effect on January 1, 2016, had no significant effect on the consolidated financial statements of the Company and its subsidiaries.

The accompanying notes are an integral part of these consolidated financial statements.

F-17

b) Accounting pronouncements effective from January 1, 2017, and subsequent periods:

As of the date of issue of these consolidated financial statements, the following accounting pronouncements had been issued by the IASB, but their application was not yet mandatory:

New Standards	Mandatory application for annual periods beginning on or after:
IFRS 9: Financial Instruments	January 1, 2018
IFRS 15: Revenue from Contracts with Customers.	January 1, 2018
IFRS 16: Leases	January 1, 2019

• IFRS 9 – Financial Instruments

In July 2014, the IASB issued the final version of IFRS 9 that replaces IAS 39 Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. This new standard brings together all three phases of the IASB’s project on financial instruments: (i) classification and measurement, (ii) impairment and (iii) hedge accounting.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early application permitted.  The standard has several specific requirements on transition, exceptions and exemptions, but, as a general rule, it will be applied retrospectively, except for most of the hedge accounting requirements that will be applied prospectively. IFRS 9 does not mandatorily require to restate prior periods. The Group does not expect to early adopt the Standard.

The actual impact of adopting IFRS 9 on the Group’s consolidated financial statements in 2018 is not known and cannot be reliably estimated because it will be dependent on the financial instruments that the Group holds and economic conditions at that time as well as accounting elections and judgments that it will make during the implementation period. However, the Group has performed a preliminary assessment of the potential impact, based on currently available information and, therefore, it may be subject to changes based on detailed analyses to be carried out or new information available in the future.

ii) Classification and measurement

The accompanying notes are an integral part of these consolidated financial statements.

F-18

IFRS 9 introduces a new classification approach for financial assets, based on two concepts: the characteristics of the contractual cash flows of the financial assets and the business model of the entity. Under this new approach, the four classification categories of IAS 39 are replaced by the following three categories:

- amortized cost;

- fair value through other comprehensive income; and

- fair value through profit or loss.

For financial liabilities, IFRS 9 retains most of the classification requirements from IAS 39. However, there are new accounting requirements for those financial liabilities designated at initial recognition under the fair value option to be measured at fair value through profit or loss. In this case, the change in the fair value attributable to changes in “own credit risk” is recognized in other comprehensive income.

Based on its preliminary assessment, the Group does not believe that the new classification requirements, if applied at December 31, 2016, would have had a material impact on its consolidated financial statements.

ii) Impairment

The new impairment model in IFRS 9 is based on expected credit losses, which differs from the incurred loss model in IAS 39. Consequently, under IFRS 9 impairment losses will be recognized, as a general rule, earlier than current practice.

The new impairment model will be applied to financial assets measured at amortized cost and those measured at fair value through other comprehensive income. The allowance for impairment losses will be measured based on:

- 12-month expected credit losses; or

- lifetime expected credit losses, if the credit risk of a financial asset at the reporting date has increased significantly since initial recognition.

The standard allows the application of a simplified approach for trade receivables, contract assets and lease receivables so that the impairment is always recognized in reference to the lifetime expected credit losses. The Group preliminarily expects to apply the simplified approach to all of its trade receivables.

The accompanying notes are an integral part of these consolidated financial statements.

F-19

ii) Hedge Accounting

IFRS 9 introduces a new model for hedge accounting in order to more closely align the accounting treatment with risk management activities of the entities and to establish a new principle-based approach. The new model will enable entities to better reflect risk management activities in the financial statements, and allow more items to be eligible as hedged items, such as: non-financial risk component, net positions, and aggregated exposures (i.e., a combination of derivative and non-derivative exposure).

When initially applying IFRS 9, the Group may choose as its accounting policy to continue to apply the hedge accounting requirements of IAS 39 instead of the requirements in IFRS 9. The Group currently intends to apply the new requirements of IFRS 9.

The Group believes that all existing hedge relationships that are currently designated in effective hedging relationships will still qualify for hedge accounting under IFRS 9. The Group will assess possible changes related to the accounting for the time value of options, forward points or the currency basis spread in more detail in the future.

• IFRS 15 – Revenue from Contracts with Customers

IFRS 15 was issued in May 2014 and establishes a five-step model to account for revenue arising from contracts with customers. Under IFRS 15, revenue is recognized at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer.

The new revenue standard will supersede all current standards related to revenue recognition:

- IAS 11Construction Contracts;

- IAS 18 Revenue;

- IFRIC 13 Customer Loyalty Programs;

- IFRIC 15 Agreements for the Construction of Real Estate;

- IFRIC 18 Transfers of Assets from Customers; and

- SIC-31 Revenue – Barter Transactions Involving Advertising Services.

The standard shall be applied for annual periods beginning on or after January 1, 2018, either under a full retrospective method or a modified retrospective method. Early adoption is permitted. The Group preliminarily plans to adopt the new standard on the required effective date using the modified retrospective method. Consequently, the Group will apply IFRS 15 retrospectively only to those contracts effective on the initial application date, recognizing the cumulative effect of initially applying the standard as an adjustment to the opening balance of retained earnings of the annual reporting period that includes the date of initial application.

The accompanying notes are an integral part of these consolidated financial statements.

F-20

Based on its preliminary assessment of IFRS 15, the Group does not believe that the new standard, if applied at December 31, 2016, would have had a material impact on its consolidated financial statements.

IFRS 15 requires more detailed disclosures than the current requirements. The disclosure requirements represent a significant change as compared to current practice and increase significantly the volume of disclosures to be included in the Group’s financial statements. During 2017, in accordance with the Group’s IFRS 15 implementation timetable, an assessment and the necessary changes and enhancements will be made to the systems, internal controls, policies and procedures, to gather and disclose the required information.

• IFRS 16 - Leases

IFRS 16 was issued by the IASB in January 2016, and establishes principles for the recognition, measurement, presentation and disclosure of leases. The new standard replaces IAS 17 Leases, IFRIC 4 Determining whether an Arrangement contains a Lease, SIC-15 Operating Leases-Incentives and SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a Lease.

The standard is effective for annual periods beginning on or after January 1, 2019. Early application is permitted for entities that apply IFRS 15 at or before the date of initial application of IFRS 16. The Group does not plan to adopt the standard early.

IFRS 16 provides a series of practical expedients for the transition, both for the definition of a lease and for retrospective application of the standard. The Group has not yet decided if it will use certain or all of the practical expedients.

i) Lessee accounting under IFRS 16 requires lessees to account for all leases under a single on-balance sheet model similar to the accounting for finance leases under IAS 17. Consequently, at the commencement date of a lease contract, the lessee will recognize a right-of-use asset and a liability for future lease payments to be made. The standard includes two optional recognition exceptions for leases of low value items and short-term leases.

ii) Lessor accounting under IFRS 16 is substantially unchanged from current accounting under IAS 17. Lessors will continue to classify leases using the same classification principles as in IAS 17 as operating and finance leases.  

The Group is currently carrying out an initial assessment of the potential impact of IFRS 16 on its consolidated financial statements. The quantitative effect will depend on, among others, the chosen transition method, the extent to which the Group

The accompanying notes are an integral part of these consolidated financial statements.

F-21

uses the practical expedients and recognition exemptions, and any additional lease contract entered into by the Group in the future. The Group expects to disclose its transition method selected and quantitative information before the initial application of the standard.

The accompanying notes are an integral part of these consolidated financial statements.

F-22

Standards, Interpretations and Amendments		Mandatory application for annual periods beginning on or after:
IFRIC 22: Foreign Currency Transactions and Advance Consideration This interpretation addresses the exchange rate to be used in foreign currency transactions when the consideration is paid or received before recognizing related revenues, expenses or assets.	January 1, 2018
Amendment to IAS 12: Recognition of Deferred Tax Assets for Unrealized Losses The purpose of the amendments to IAS 12 “Income Taxes” is to provide requirements on recognition of deferred tax assets for unrealized losses, and clarify how to account for deferred tax assets related to debt instruments measured at fair value.	January 1, 2017
Amendment to IAS 7: Disclosure Initiative The amendments to IAS 7 “Statement of Cash Flows” are part of the IASB’s initiative aimed at improving presentation and disclosure of information in the financial statements. The amendments add additional disclosure requirements relating to financing activities in the statement of cash flows.	January 1, 2017

The accompanying notes are an integral part of these consolidated financial statements.

F-23

Standards, Interpretations and Amendments		Mandatory application for annual Periods beginning on or after:
Annual Improvements to IFRS (Cycles 2014-2016) Annual improvements correspond to a series of minor amendments clarifying, correcting or eliminating redundancy in the following standards: IFRS 1 “First-time Adoption of IFRS”, IFRS 12 “Disclosures of Interests in Other Entities” and IAS 28 “Investments in Associates and Joint Ventures”.	IFRS 12: January 1, 2017. IFRS 1: January 1, 2018 IAS 28: January 1, 2018
Amendment to IFRS 2: Classification and Measurement of Share-based Payment Transactions
The amendments provide specific accounting requirements for: (i) the effects of vesting and non-vesting conditions on the measurement of cash-settled share-based payments; ii) share-based payment transactions with a net settlement feature for withholding tax obligations; and iii) a modification to the terms and conditions of a share-based payment that changes the classification of the transaction from cash-settled to equity-settled.	January 1, 2018.
Amendments to IAS 40: Transfers of investment property The IASB issued this amendment to clarify that a change in management’s intentions for the use of a property by itself does not constitute evidence of a change in use and not a sufficient reclassification criteria.	January 1, 2017.
Amendment to IFRS 10 and IAS 28: Sale or Contribution of Assets
The amendment corrects an inconsistency between IFRS 10 “Consolidated Financial Statements” and IAS 28 “Investments in Associates and Joint Ventures” relating to the accounting treatment of the sale or contributions of assets between an Investor and its Associate or Joint Venture. The IASB decided to postpone the effective date of application of the amendment, until obtaining the results of its research Project on the equity method of accounting.	Effective date deferred indefinitely.

In Management’s opinion, the future application of IFRIC 22 and the foregoing amendments is not expected to have a significant effect on the consolidated financial statements of the Group.

2.3 Responsibility for the information, judgments and estimates provided

The Company’s Board of Directors is responsible for the information contained in these consolidated financial statements and expressly states that all IFRS principles and standards have been fully implemented.

In preparing the consolidated financial statements, certain judgments and estimates made by the Group’s Management have been used to quantify some of the assets, liabilities, income, expenses and commitments recognized in these consolidated financial statements.

The most important areas where critical judgment was required are:

- In a service concession agreement, the decision as to whether a grantor controls or regulates which services the operator should provide, to whom and at what price. These are essential factors when applying IFRIC 12 (see Note 3.c.1).

- The identification of Cash Generating Units (CGU) for impairment testing (see Note 3.d).

- The hierarchy of inputs used to measure assets and liabilities at fair value (see Note 3.g).

The accompanying notes are an integral part of these consolidated financial statements.

F-24

The estimates refer basically to:

- The valuations performed to determine the existence of impairment losses among assets and goodwill (see Note 3.d).

- The assumptions used to calculate the post-employment defined benefit obligations to employees, such as discount rates, mortality tables, salary increases, etc. (see Notes 3.l.1 and 23).

- The useful lives of property, plant and equipment and intangible assets (see Notes 3.a and 3.c).

- The assumptions used to calculate the fair value of financial instruments (see Notes 3.g and 20).

- Energy supplied to customers whose meter readings are pending.

- Certain assumptions inherent in the electricity system affecting transactions with other companies, such as production, customer billings, energy consumption, etc. that allow for estimating electricity system settlements that must occur on the corresponding final settlement dates, but that are pending as of the date of issuance of the consolidated financial statements and could affect the balances of assets, liabilities, income and expenses recognized in the financial statements (see Appendix 6.2).

- The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 3.l).

- Future disbursements for the closure of facilities and restoration of land, as well as the discount rates to be used (see Note 3.a).

- The tax results of the various subsidiaries of the Group that will be reported to the respective tax authorities in the future, and other estimates that have been used as the basis for recording different balances related to income taxes in these consolidated financial statements (see Note 3.o).

- The fair values of assets acquired and liabilities assumed, and any pre-existing interest in an entity acquired in a business combination.

Although these judgments and estimates have been based on the best information available on the issuance date of these consolidated financial statements, future events may occur that would require a change (increase or decrease) to these estimates in subsequent periods. This change would be made prospectively, recognizing the effects of such judgment or estimation change in the corresponding future consolidated financial statements.

2.4 Subsidiaries

Subsidiaries are defined as those entities controlled either, directly or indirectly, by the Company. Control is exercised if, and only if, the following conditions are met: the Company has i) power over the subsidiary; ii) exposure or rights to variable returns from these entities; and iii) the ability to use its power to influence the amount of these returns.

The Company has power over its subsidiaries when it holds the majority of the substantive voting rights or, should that not be the case, when it has rights granting the practical ability to direct the entities’ relevant activities, that is, the activities that significantly affect the subsidiary’s results.

The Group will reassess whether or not it controls a subsidiary if the facts and circumstances indicate that there are changes to one or more of the three elements of control listed above.

Subsidiaries are consolidated as described in Note 2.7.

Appendix 1. “Enel Américas Group Entities” to these consolidated financial statements describes the relationship of the Company with each of its subsidiaries.

2.4.1 Changes in the scope of consolidation

On March 1, 2016, as part of the corporate reorganization and as a result of the spin-off described in Note 5.1, all subsidiaries that were part of the generation and distribution businesses in Chile have been deconsolidated, which are detailed in Appendix 2. The effects of this transaction in the consolidated financial statements as of December 31, 2016 are described in Note 5.1.

On October 1, 2016, the merger by incorporation of our Colombian subsidiary Codensa S.A. E.S.P. (the “surviving company”) with Distribuidora Eléctrica de Cundinamarca S.A. E.S.P. and Empresa de Energía de Cundinamarca S.A. E.S.P. (the “merged entities”) was completed, both of which until the merger date were considered joint ventures. The effects of this transaction in the consolidated financial statements as of December 31, 2016 are described in Note 6.

The accompanying notes are an integral part of these consolidated financial statements.

F-25

2.4.2 Consolidated companies with an economic equity interest of less than 50%

Although the Group holds, directly or indirectly, 48.48% equity interest in Comercializadora de Energía S.A. (“Codensa”) and 37.73% equity interest in Empresa Generadora de Energía Eléctrica S.A. (“Emgesa”), they are considered as subsidiaries since the Company exercises control over these entities through contracts or agreements with shareholders, or as a consequence of their structure, composition and shareholder classes. The Group holds 57.15% and 56.43% of the voting shares of Codensa and Emgesa, respectively.

2.5 Investments in associates

Associates are those entities in which the Company, either directly or indirectly, exercises significant influence.

Significant influence is the power to participate in the financial and operational policy decisions of the associate but is not control or joint control over those policies. In assessing significant influence, the Group takes into account the existence and effect of potential exercisable voting rights or convertible rights at the end of each reporting period, including potential voting rights held by the Company or other entities. In general, significant influence is presumed to be those cases in which the Group has an ownership interest of more than 20%.

Associates are incorporated to the consolidated financial statements using the equity method, as described in Note 3.h.

Appendix 3. “Associates and Joint Ventures” to these consolidated financial statements describes the relationship of the Company with each of these companies.

2.6 Investments in joint arrangements

Joint arrangements are defined as those entities in which the Group exercises control under an agreement with other shareholders and jointly with them, in other words, when decisions on the entities’ relevant activities require the unanimous consent of the parties sharing control.

Depending on the rights and obligations of the parties, joint arrangements are classified as:

- Joint ventures: an agreement whereby the parties exercising joint control have rights to the entity’s net assets. Joint ventures are incorporated to the consolidated financial statements using the equity method, as described in Note 3.h.

- Joint operation: an agreement whereby the parties exercising joint control have rights to the assets and obligations with respect to the liabilities relating to the arrangement. Joint operations are incorporated to the consolidated financial statements recognizing the interest in the assets and liabilities held in the joint operation.

In determining the type of joint arrangement in which it is involved, the management of the Group assesses its rights and obligations arising from the arrangement by considering the structure and legal form of the arrangement, the terms agreed by the parties in the contractual arrangement and, when relevant, other facts and circumstances. If facts and circumstances change, the Group reassesses whether the type of joint arrangement in which it is involved has changed.

Currently, the Group is not involved in any joint arrangement that qualifies as a joint operation.

Appendix 3. “Associates and Joint Ventures” to these consolidated financial statements describes the relationship of the Company with each of these companies.

The accompanying notes are an integral part of these consolidated financial statements.

F-26

2.7 Basis of consolidation and business combinations

The subsidiaries are consolidated and all of their assets, liabilities, income, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations from intragroup transactions have been made.

The comprehensive income of subsidiaries is included in the consolidated comprehensive income statement from the date when the parent company obtains control of the subsidiary and until the date on which it loses control of the subsidiary.

The operations of the parent company and its subsidiaries have been consolidated under the following basic principles:

1. At the date the parent obtains control, the subsidiary’s assets acquired and its liabilities assumed are recorded at fair value, except for certain assets and liabilities that are recorded using valuation principles established in other IFRS standards. If the fair value of the consideration transferred plus the fair value of any non-controlling interests exceeds the fair value of the net assets acquired, this difference is recorded as goodwill. In the case of a bargain purchase, the resulting gain is recognized in profit or loss for the period after reassessing whether all of the assets acquired and the liabilities assumed have been properly identified and following a review of the procedures used to measure the fair value of these amounts.

For each business combination, the Group chooses whether to measure the non-controlling interests in the acquiree at fair value or at the proportional share of the net identifiable assets acquired.

If the fair value of all assets acquired and liabilities assumed at the acquisition date has not been completed, the Group reports the provisional values accounted for in the business combination. During the measurement period, which shall not exceed one year from the acquisition date, the provisional values recognized will be adjusted retrospectively as if the accounting for the business combination had been completed at the acquisition date, and also additional assets or liabilities will be recognized to reflect new information obtained on events and circumstances that existed on the acquisition date, but which were unknown to the management at that time. Comparative information for prior periods presented in the financial statements is revised as needed, including making any change in depreciation, amortization or other income effects recognized in completing the initial accounting.

For business combinations achieved in stages, the fair value of the equity interest previously held in the acquired company’s equity is measured on the date of acquisition and any gain or loss is recognized in the results for that period.

2. Non-controlling interests in equity and in the comprehensive income of the consolidated subsidiaries are presented, respectively, under the line items “Total Equity: Non-controlling interests” in the consolidated statement of financial position and “Net income attributable to non-controlling interests” and “Comprehensive income attributable to non-controlling interests” in the consolidated statement of comprehensive income.

3. The financial statements of foreign companies with functional currencies other than the Chilean peso are translated as follows:

a. For assets and liabilities, the prevailing exchange rate on the closing date of the financial statements is used.

b. For items in the comprehensive income statement, the average exchange rate for the period is used (unless this average is not a reasonable approximation of the cumulative effect of the exchange rates in effect on the dates of the transactions, in which case the exchange rate in effect on the date of each transaction is used).

c. 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.

d. Exchange differences arising in translation of financial statements are recognized in the item “Foreign currency translation gains (losses)” within the consolidated statement of comprehensive income in other comprehensive income (see Note 24.2).

The accompanying notes are an integral part of these consolidated financial statements.

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4. Balances and transactions between consolidated companies were fully eliminated in the consolidation process.

5. Changes in interests in subsidiaries that do not result in obtaining or losing control are recognized as equity transactions, and the carrying amount of the controlling and non-controlling interests is adjusted to reflect the change in relative interest in the subsidiary. Any difference that may exist, between the value for which a non-controlling interest is adjusted and the fair value of a compensation paid or received, is recognized directly in equity attributable to shareholders of Enersis Américas.

6. Business combinations of entities under common control are recorded using, as a reference, the ‘pooling of interest’ method. Under this method, the assets and liabilities involved in the transaction remain reflected at the same carrying amount at which they were recorded in the ultimate controlling company, although subsequent accounting adjustments may need to be made to align the accounting policies of the companies involved.

Any difference between the assets and liabilities contributed to the consolidation and the compensation given is recorded directly in equity as a debit or credit to other reserves. The Group does not apply retrospective accounting recognition of business combinations under common control.

The accompanying notes are an integral part of these consolidated financial statements.

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3. ACCOUNTING POLICIES APPLIED

The main accounting policies used in preparing the accompanying consolidated financial statements are the following:

a) Property, plant and equipment

Property, plant and equipment are measured at acquisition cost, net of accumulated depreciation and any impairment losses they may have experienced. In addition to the price paid to acquire each item, the cost also includes, where applicable, the following concepts:

- Financing expenses accrued during the construction period that are directly attributable to the acquisition, construction, or production of qualified assets, which require a substantial period of time before being ready for use such as, for example, electricity generation or distribution facilities. The Group defines “substantial period” as one that exceeds twelve months. The interest rate used is that of the specific financing or, if none exists, the weighted average financing rate of the company carrying out the investment (see Note 16.b.1).

- Employee expenses directly related to construction in progress (see Note 16.b.2).

- Future disbursements that the Group will have to incur to close its facilities are added to the value of the asset at fair value, recognizing the corresponding provision for dismantling or restoration. The Group reviews its estimate of these future disbursements on an annual basis, increasing or decreasing the value of the asset based on the results of this estimate (see Note 22).

Items for construction work in progress are transferred to operating assets once the testing period has been completed and they are available for use, at which time depreciation begins.

Expansion, modernization or improvement costs that represent an increase in productivity, capacity or efficiency, or a longer useful life are capitalized as increasing the cost of the corresponding assets.

The replacement or overhaul of entire components that increase the asset’s useful life or economic capacity are recognized as an increase in the carrying amount of the respective assets, derecognizing the replaced or overhauled components.

Expenditures for periodic maintenance, conservation and repair are recognized directly as an expense for the period in which they are incurred.

Property, plant and equipment, net of its residual value, is depreciated by distributing the cost of the different items that comprise it on a straight-line basis over its estimated useful life, which is the period where the companies expect to use the assets. Useful life estimates and residual values are reviewed on an annual basis and if appropriate adjusted prospectively.

The following table sets forth the main categories of property, plant and equipment with their respective estimated useful lives:

Categories of Property, plant and equipment	Years of estimated useful life
Buildings	10 – 85
Plant and equipment	10 – 90
IT equipment	3 – 15
Fixtures and fittings	3 – 75
Motor vehicles	5 – 20

The accompanying notes are an integral part of these consolidated financial statements.

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Additionally, the following table sets forth more details on the useful lives of plant and equipment items:

Categories of Property, plant and equipment	Years of estimated useful life
Generating plant and equipment:
Hydroelectric plants
Civil engineering works	10 – 90
Electromechanical equipment	10 – 80
Coal/Fuel power plants	10 – 40
Combined cycle power plants	10 – 50
Distribution plant and equipment:
High-voltage network	15 – 50
Low- and medium-voltage network	30 – 50
Measuring and remote control equipment	10 – 30
Primary substations	20 – 40

Land is not depreciated since it has an indefinite useful life.

Regarding the administrative concessions held by the Group’s electric companies, the following table lists the remaining periods until expiration of the concessions that do not have an indefinite term:

Concession holder and operator	Country	Year   concession   started	Concession   term	Remaining period to expiration
Empresa Distribuidora Sur S.A. - Edesur (Distribution)	Argentina	1992	95 years	71 years
Enel Generación El Chocón S.A. (Generation)	Argentina	1993	30 years	7 years
Transportadora de Energía S.A. (Transmission)	Argentina	2002	85 years	71 years
Compañía de Transmisión del Mercosur S.A. (Transmission)	Argentina	2000	87 years	71 years
Central Eléctrica Cachoeira Dourada S.A. (Generation)	Brazil	1997	30 years	11 years
Central Generadora Termoeléctrica Fortaleza S.A (Generation)	Brazil	2001	30 years	15 years
Compañía de Interconexión Energética S.A. (CIEN - Line 1)	Brazil	2000	20 years	3 years
Compañía de Interconexión Energética S.A (CIEN - Line 2)	Brazil	2002	20 years	5 years

To the extent that the Group recognizes the assets as Property, plant and equipment, they are amortized over their economic life or the concession term, whichever is shorter, when the economic benefit from the asset is limited to its use during the concession term.

Any required investment, improvement or replacement made by the Group is considered in the impairment test to Property, plant, and equipment as a future contractual cash outflow that is necessary to obtain future cash inflow.

The Group’s management analyzed the specific contract terms of each of the aforementioned concessions, which vary by country, business activity and jurisdiction, and concluded that, with the exception of Enel CIEN, there are no determining factors indicating that the grantor, which in every case is a government entity, controls the infrastructure and, at the same time, can continuously set the price to be charged for the services. These requirements are essential for applying IFRIC 12, Service Concession Arrangements, an interpretation that establishes how to recognize and measure certain types of concessions (see Note 3.c.1 for concession agreements within the scope of IFRIC 12).

On April 19, 2011, the subsidiary Enel CIEN successfully completed its change in business model. Under the new agreement, the government continues to control the infrastructure, but Enel CIEN receives fixed payments, which puts it on an equal footing with a public transmission concession (with regulated prices). Under this business model, its concessions fall within the scope of IFRIC 12; however, the infrastructure has not been derecognized due to the fact that Enel CIEN has not substantially transferred the significant risks and benefits to the Brazilian government.

Gains or losses that arise from the sale or disposal of items of Property, plant and equipment are recognized as other gains (losses) in the comprehensive income statement and are calculated by deducting the net carrying amount of the asset and any sales costs from the consideration received in the sale.

The accompanying notes are an integral part of these consolidated financial statements.

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b) Goodwill

Goodwill arising from business combinations, and reflected upon consolidation, represents the excess value of the consideration paid plus the amount of any non-controlling interests over the Group’s share of the net value of the assets acquired and liabilities assumed, measured at fair value at the acquisition date. If the accounting for a business combination is completed within the following year after the acquisition date, and so is the goodwill determination, the entity recognizes the corresponding adjustments to the provisional amounts as if the accounting for the business combination had been completed at the acquisition date. Thus, comparative information for prior periods presented in financial statements is revised as needed, including making any change in depreciation, amortization or other income effects recognized in completing the initial accounting (see Note 2.7.1).

Goodwill arising from acquisition of companies with functional currencies other than the Chilean peso is measured in the functional currency of the acquired company and translated to Chilean pesos using the exchange rate effective as of the date of the statement of financial position.

Goodwill is not amortized; instead, at the end of each reporting period or when there are indicators, the Company estimates whether any impairment has reduced its recoverable amount to an amount less than carrying amount and, if so, it is immediately adjusted for impairment (see Note 3.d).

c) Intangible assets other than goodwill

Intangible assets are initially recognized at their acquisition cost or production cost, and are subsequently measured at their cost, net of accumulated amortization and impairment losses they may have experienced.

Intangible assets are amortized on a straight line basis during their useful lives, starting from the date when they are ready for use, except for those with an indefinite useful life, which are not amortized. As of December 31, 2016 and 2015, there were no significant amounts in intangible assets with an indefinite useful life.

An intangible asset is derecognized on disposal, or when no future economic benefits are expected from use or disposal.

Gains or losses arising from derecognition of an intangible asset, measured as the difference between the net disposal proceeds and the carrying amount of the asset are recognized in profit or loss when the asset is derecognized.

The criteria for recognizing these assets’ impairment losses and, if applicable, recovery of impairment losses recorded in previous fiscal years are explained in letter d) of this Note.

c.1) Concessions

Public-to-private service concession agreements are recognized according to IFRIC 12 “Service Concession Agreements.” This accounting interpretation applies if:

a) The grantor controls or regulates which services the operator should provide with the infrastructure, to whom it must provide them, and at what price; and

b) The grantor controls – through ownership, beneficial entitlement, or otherwise – any significant residual interest in the infrastructure at the end of the term of the agreement.

If both of the above conditions are met simultaneously, the consideration received by the Group for the constructed infrastructure is initially recognized at its fair value, as either an intangible asset when the Group receives the right to charge users of the public service, as long as these charges are conditional on the degree to which the service is used; or as a financial asset when the Group has an unconditional contractual right to receive cash or another financial asset directly from the grantor or from a third party.

The Group recognizes the contractual obligations assumed for maintenance of the infrastructure during its use, or for its return to the grantor at the end of the concession agreement within the conditions specified in the agreement, as long as it does not involve an activity that generates income, in accordance with the Group’s accounting policy to recognized provisions (see Note 3.l).

Finance expenses attributable to the concession agreements are capitalized based on criteria established in Note 3.a) above, provided that the Group has a contractual right to receive an intangible asset. No finance expenses were capitalized during the years ended December 31, 2016, 2015 and 2014.

The accompanying notes are an integral part of these consolidated financial statements.

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The Company’s subsidiaries that have recognized an intangible asset from their service concession agreements are the following:

Concession holder and operator	Country	Year   concession   started	Concession   term	Period  remaining to expiration
Ampla Energía e Serviços S.A. (*) (Distribution)	Brazil	1996	30 years	10 years
Companhia Energética do Ceará S.A. (*) (Distribution)	Brazil	1997	30 years	11 years

(*) Considering that part of the rights acquired by our subsidiaries is unconditional, an available-for-sale financial asset has been recognized (see Notes 3.f.1 and 8).

At the end of each concession period it can be renewed at the discretion of the granting authority, otherwise all assets and facilities will be returned to the government or its designee, upon reimbursement for investments made and not yet amortized.

c.2) Research and development expenses

The Group recognizes in the statement of financial position the costs incurred in a project’s development phase as intangible assets as long as the project’s technical feasibility and economic returns are reasonably assured.

Research expenditures are recognized in the consolidated statement of comprehensive income when incurred.

c.3) Other intangible assets

These intangible assets correspond primarily to computer software, water rights, and easements. They are initially recognized at acquisition or production cost and are subsequently measured at cost less accumulated amortization and impairment losses, if any.

Computer software programs are amortized, on average, over five years. Certain easements and water rights have indefinite useful lives and are therefore not amortized, while others have useful lives ranging from 40 to 60 years, depending on their characteristics, and they are amortized over that term.

d) Impairment of non-financial assets

During the period, and principally at the end of each reporting period, the Group evaluates whether there is any indication that an asset has been impaired. If any such indication exists, the Company estimates the recoverable amount of that asset to determine the amount of the impairment loss. In the case of identifiable assets that do not generate cash flows independently, the Company estimates the recoverable amount of the Cash Generating Unit (CGU) to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

Notwithstanding the preceding paragraph, in the case of CGUs to which goodwill or intangible assets with an indefinite useful life have been allocated, a recoverability analysis is performed routinely at the end of each reporting period.

The recoverable amount is the higher of fair value less the cost of disposal and value in use, which is defined as the present value of the estimated future cash flows. In order to calculate the recoverable amount of Property, plant, and equipment, as well as of goodwill, and intangible assets, the Group uses value in use criteria in practically all cases.

In determining the recoverable amount of Edesur’s CGU, a scenario probability-weighted model is used that takes into account reasonably possible changes in key assumptions:

- Base case “Industrial Plan”, which incorporates management’s assessment of expected cash flows. The recoverable amount calculated in accordance with base case exceeded the carrying value of Edesur’s CGU as of December 31, 2016. This scenario was weighted using a 40% likelihood of occurrence.

- “Sensitive” case, which incorporates the same assumptions of the base case, but considers a decrease in the tariff adjustments for the next tariff period to be carried out in year 2021, resulting in an amount below the carrying value of Edesur’s CGU as of December 31, 2016. This scenario was weighted using a 40% probability.

The accompanying notes are an integral part of these consolidated financial statements.

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- “Business continuity” case, which implies no recoverable amount, was weighted using a 20% probability.

Reasonably possible major changes in key assumptions are already incorporated in the impairment test model that applies probability weighted stress-testing scenarios to determine the recoverable amount of Edesur’s CGU.

The Group’s management believes that any reasonably possible change in the other key assumptions on which recoverable amount is based would not cause Edesur’s CGU carrying amount to exceed its recoverable amount.

To estimate the value in use of the other CGUs, the Group prepares future pre-tax cash flow projections based on the most recent budgets available. These budgets incorporate management’s best estimates of CGUs’ revenue and costs using sector projections, past experience and future expectations.

In general, these projections cover the next five years, estimating cash flows for subsequent years by applying reasonable growth rates which, in neither case, are increasing rates nor exceed the average long-term growth rates for the particular sector and country in which the Company operates. As of December 31, 2016 and 2015, projections were extrapolated from the following rates:

Country	Currency	Growth rates (g)
		12-31-2016	12-31-2015
Argentina	Argentine peso	11.1%	11.1%
Brazil	Real	4.6% - 5.9%	4.1% - 5.6%
Peru	Peruvian sol	3.2% - 4.5%	3.1% - 4.8%
Colombia	Colombian peso	3.8% - 3.8%	3.5% - 5.2%

These cash flows are discounted to calculate their present value at a pre-tax rate that covers the cost of capital for the business activity and the geographic area in which it is being carried out. The time value of money and the risk premiums generally used among analysts for the business activity and the geographic zone are taken into account to calculate the pre-tax rate.

The following are the pre-tax discount rates applied as of December 31, 2016 and 2015, expressed in nominal terms:

Country	Currency	December 31, 2016		December 31, 2015
		Minimum	Maximum	Minimum	Maximum
Argentina	Argentine peso	29.8%	40.6%	32.7%	39.4%
Brazil	Real	11.0%	21.8%	11.1%	21.1%
Peru	Peruvian sol	7.2%	11.5%	7.3%	13.5%
Colombia	Colombian peso	10.0%	10.7%	8.5%	15.1%

If the recoverable amount of the CGU is less than the net carrying amount of the asset, the corresponding impairment loss is recognized for the difference, and charged to “Reversal of impairment loss (impairment loss) recognized in profit or loss” in the consolidated statement of comprehensive income. The impairment is first allocated to the CGU’s goodwill carrying amount, if any, and then to the other assets comprising it, prorated on the basis of the carrying amount of each one, limited to its fair value less costs of disposal, or its value in use, a negative amount may not be obtained.

Impairment losses recognized in prior periods for an asset other than goodwill are reversed, if and only if, there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If this is the case, the carrying amount of the asset is increased to its recoverable amount and crediting profit or loss, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the asset. In the case of goodwill, impairment losses are not reversed.

The accompanying notes are an integral part of these consolidated financial statements.

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e) Leases

In order to determine whether an arrangement is, or contains, a lease, the Group assesses the economic substance of the agreement, to assess whether fulfillment of the arrangement depends on the use of a specific asset and whether the agreement conveys the right to the use of the asset. If both conditions are met, at the inception of the arrangement, the Group separates the payments and other considerations relating to the lease, at their fair values, from those corresponding to the other components of the arrangement.

Leases that substantially transfer all of the risks and rewards of ownership to the Group are classified as finance leases. All other leases are classified as operating leases.

Finance leases in which the Group acts as a lessee are recognized at the inception of the arrangement. At that time, the Group records an asset based on the nature of the lease and a liability for the same amount, equal to the fair value of the leased asset or the present value of the minimum lease payments, if the latter is lower. Subsequently, the minimum lease payments are apportioned between finance expenses and reduction of the lease obligation. Finance expenses are recognized in the income statement and allocated over the lease term, so as to obtain a constant interest rate for each period over the remaining balance of the liability. Leased assets are depreciated on the same terms as other similar depreciable assets, as long as there is reasonable certainty that the lessee will acquire ownership of the asset at the end of the lease. If no such certainty exists, the leased asset is depreciated over the shorter term of the useful lives of the asset and the lease term.

In the case of operating leases, payments are recognized as an expense in the case of the lessee and as income in the case of the lessor, both on a straight-line basis, over the term of the lease unless another type of systematic basis of distribution is deemed more representative.

f) Financial instruments

Financial instruments are contracts that give rise to both a financial asset in one entity and a financial liability or equity instrument in another entity.

f.1) Financial assets other than derivatives

The Group classifies its financial assets other than derivatives, whether permanent or temporary, except for investments accounted for using the equity method (see Notes 3.h and 13) and non-current assets held for sale (see Note 3.j), into four categories:

- Loans and account receivables: Trade and other receivables and accounts receivable from related parties are recognized at amortized cost, which is the initial fair value less principal repayments made, plus accrued and uncollected interest, calculated using the effective interest method.

The effective interest method is used to calculate the amortized cost of a financial asset or liability (or group of financial assets or financial liabilities) and of allocating finance income or cost over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash flows to be received or paid through the expected life of the financial instrument (or, when appropriate, over a shorter period) to the net carrying amount of the financial asset or financial liability.

- Held-to-maturity investments: Investments that the Group intends to hold and is capable of holding until their maturity are accounted for at amortized cost as defined in the preceding paragraph.

- Financial assets at fair value through profit or loss: This includes the trading portfolio and those financial assets that have been designated as such upon initial recognition and that are managed and evaluated on a fair value basis. They are measured in the consolidated statement of financial position at fair value, with changes in value recognized directly in profit or loss when they occur.

- Available-for-sale financial assets: These are financial assets specifically designated as available-for-sale or that do not fit within any of the three preceding categories. They are mainly all financial investments in equity instruments and financial assets in accordance with IFRIC 12 “Service Concession Arrangements” (see Note 8).

These investments are recognized in the consolidated statement of financial position at fair value when it can be reliably determined. For equity interests in unlisted companies or companies with lower levels of liquidity, normally the fair

The accompanying notes are an integral part of these consolidated financial statements.

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value cannot be reliably determined. When this occurs, those equity interests are measured at acquisition cost or a lesser amount if evidence of impairment exists.

Changes in fair value, net of taxes, are recognized in the consolidated statement of comprehensive income: Other comprehensive income, until the investments are disposed of, at which date the amount accumulated in this account for that investment is reclassified to profit or loss.

If the fair value is lower than the acquisition cost, and if there is objective evidence that the asset has been more than temporarily impaired, the difference is recognized directly in profit or loss.

Purchases and sales of financial assets are accounted for using their trade date.

f.2) Cash and cash equivalents

This item within the consolidated statement of financial position includes cash and bank balances, time deposits, and other highly liquid investments (with a maturity of 90 days or less from its acquisition date) that are readily convertible to cash and are subject to insignificant risk of changes in value.

f.3) Impairment of financial assets

The following criteria are used to determine if a financial asset has been impaired:

- For trade receivables in the electricity generation, transmission and distribution segments, the Company’s policy is to recognize impairment losses when there is objective evidence that the balance will not be recoverable. In general terms, the Group’s entities have a defined policy to recognize an allowance for impairment losses based on aging of past-due balances, except in those cases where a specific collective basis analysis is recommended, such as in the case of receivables from government-owned companies (see Note 9).

- In the case of receivables of a financial nature, that are included in the “Loan and receivables” and “Investment held-to-maturity”, impairment is determined on a case-by-case basis and is measured as the difference between the carrying amount and the present value of the future estimated cash flows discounted at the original effective interest rate (see Notes 8 and 20).

- For financial investments available-for-sale, the criteria for impairment applied are described in Note 3.f.1.

f.4) Financial liabilities other than derivatives

Financial liabilities are recognized based on cash received, net of any costs incurred in the transaction. In subsequent periods, these obligations are measured at their amortized cost, using the effective interest method (see Note 3.f.1).

In the particular case that a liability is the hedged item in a fair value hedge, as an exception, such liability will be measured at its fair value for the portion of the hedged risk.

In order to calculate the fair value of debt, both when it is recorded in the statement of financial position and for fair value disclosure purposes as shown in Note 20, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and variable interest rate debt (hereinafter “floating-rate debt”). Fixed-rate debt is that on which fixed-interest coupons established at the beginning of the transaction are paid explicitly or implicitly over its term. Floating-rate debt is that issued at a variable interest rate, i.e., each coupon is established at the beginning of each period based on the reference interest rate. All debt has been measured by discounting expected future cash flows with a market interest rate curve based on the payment currency.

f.5) Derivative financial instruments and hedging transactions

Derivatives held by the Group are primarily transactions entered into to hedge interest and/or exchange rate risk, intended to eliminate or significantly reduce these risks in the underlying transactions being hedged.

Derivatives are recognized at fair value as of the date of the statement of financial position as follows: if their fair value is positive, they are recognized within “Other financial assets” and if their fair value is negative, they are recognized within “Other financial liabilities.” For derivatives on commodities, the positive value is recorded in “Trade and other receivables,” and negative fair values are recognized in “Trade and other liabilities.”

The accompanying notes are an integral part of these consolidated financial statements.

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Changes in fair value are recognized directly in profit or loss except when the derivative has been designated for accounting purposes as a hedging instrument and all of the conditions established under IFRS for applying hedge accounting are met, including that the hedge be highly effective. In this case, changes are recognized as follows:

- Fair value hedges: The underlying portion for which the risk is being hedged is measured at its fair value and the hedging instrument are measured at fair value, and any changes in the value of both items are recognized in the comprehensive income statement by offsetting the effects within the same comprehensive income statement account.

- Cash flow hedges: Changes in the fair value of the effective portion of derivatives are recorded in an equity reserve known as “Reserve for cash flow hedges.” The cumulative loss or gain in this reserve is reclassified to the comprehensive income statement to the extent that the underlying item impacts the comprehensive income statement offsetting the effect in the same comprehensive income statement account. Gains or losses from the ineffective portion of the hedge relationship are recognized directly in the comprehensive income statement.

A hedge relationship is considered highly effective when changes in fair value or in cash flows of the underlying item directly attributable to the hedged risk are offset by changes in fair value or cash flows of the hedging instrument, with an effectiveness ranging from 80% to 125%.

The Group does not apply hedge accounting to its investments abroad.

As a general rule, long-term commodity purchase or sale agreements are recognized in the consolidated statement of financial position at their fair value at the end of each reporting period, recognizing any differences in value directly in profit or loss, except for, when all of the following conditions are met:

- The sole purpose of the agreement is for the Group’s own use, which is understood as: (i) in the case of fuel purchase agreements, its used to generate electricity; (ii) in the case of electrical energy purchased for sale, its sale to the end-customer; and (iii) in the case of electricity sales its sales to the end-customer.

- The Group’s future projections evidence the existence of these agreements for its own use.

- Past experience with agreements evidence that they have been utilized for the Group’s own use, except in certain isolated cases for exceptional reasons or reasons associated with logistical issues have been used beyond the control and projection of the Group.

- The agreement does not stipulate settlement by differences and the parties have not made it a practice to settle similar contracts by differences in the past.

The long-term commodity purchase or sale agreements maintained by the Group, which are mainly for electricity, fuel, and other supplies, meet the conditions described above. Thus, the purpose of fuel purchase agreements is to use them to generate electricity, the electricity purchase contracts are used to sell to end-customers, and the electricity sale contracts are used to sell the Company’s own products.

The Group also evaluates the existence of derivatives embedded in contracts or financial instruments to determine if their characteristics and risk are closely related to the principal contract, provided that when taken as a whole they are not being accounted for at fair value. If they are not closely related, they are recorded separately and changes in value are accounted for directly in the comprehensive income statement.

f.6) Derecognition of financial assets and liabilities

Financial assets are derecognized when:

- The contractual rights to receive cash flows from the financial asset expire or have been transferred or, if the contractual rights are retained, the Group has assumed a contractual obligation to pay these cash flows to one or more recipients.

- The Group has substantially transferred all the risks and rewards of ownership of the financial asset, or, if it has neither transferred nor retained substantially all the risks and rewards, when it does not retain control of the asset.

The accompanying notes are an integral part of these consolidated financial statements.

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Transactions in which the Group retains substantially all the inherent risks and rewards of ownership of the transferred asset, it continues recognizing the transferred asset in its entirety and recognizes a financial liability for the consideration received. Transactions costs are recognized in profit and loss by using the effective interest method (see Note 3.f.1).

Financial liabilities are derecognized when they are extinguished, that is, when the obligation arising from the liability has been paid or cancelled, or has expired.

 f.7) Offsetting financial assets and liabilities

The Group offsets financial assets and liabilities and the net amount is presented in the statement of financial position when and only when:

- There is a legally enforceable right to set off the recognized amounts; and

- There is an intention to settle on a net basis, or to realize the asset and settle the liability simultaneously.

The right of set-off is enforceable in the normal course of business, in an event of default, and in the event of insolvency or bankruptcy, of one and all of the counterparties.

f.8) Financial guarantee contracts

Financial guarantee contracts, such as guarantees given by the Group to third parties, are initially recognized at fair value, adjusting the transaction costs that are directly attributable to the issuance of the guarantee.

Subsequently to initial recognition, financial guarantee contracts are measured at the higher of:

- the amount of the liability determined under the accounting policy described in Note 3.l; and

- the amount of the asset initially recognized less, if appropriate, any accumulated amortization recognized in accordance with the revenue recognition accounting policy (see Note 3.p).

g) Measurement of fair value

The fair value of an asset or liability is defined as the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market, namely, the market with the greatest volume and level of activity for that asset or liability. In the absence of a principal market, it is assumed that the transaction is carried out in the most advantageous market available to the entity, namely, the market that maximizes the amount that would be received on selling the asset or minimizes the amount that would be paid to transfer the liability.

In estimating fair value, the Group uses valuation techniques that are appropriate for the circumstances and for which there are sufficient data to conduct the measurement. The Group maximizes the use of relevant observable data and minimizes the use of unobservable data.

Considering the hierarchy of the data used in these valuation techniques, the assets and liabilities measured at fair value can be classified into the following levels:

Level 1: Quoted price (unadjusted) in active markets for identical assets or liabilities;

Level 2: Inputs other than quoted prices included within Level 1 that are observable for the assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices). The methods and assumptions used to determine the fair values at Level 2 by type of financial asset or financial liability take into consideration estimated future cash flows discounted at zero coupon interest rate curves for each currency. All the valuations described are carried out using external tools such as “Bloomberg.”

Level 3: Inputs for assets or liabilities that are not based on observable market data (unobservable inputs).

The accompanying notes are an integral part of these consolidated financial statements.

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The Group takes into account the characteristics of the asset or liability when measuring fair value, in particular:

- For non-financial assets, fair value measurement takes into account the ability of a market participant to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use;

- For liabilities and equity instruments, the fair value measurement assumes that the liability would not be settled and an equity instrument would not be cancelled, or otherwise extinguished on the measurement date. The fair value of the liability reflects the effect of non-performance risk, namely, the risk that an entity will not fulfill the obligation, which includes but is not limited to, the Company’s own credit risk;

- For derivatives non-quoted in an organized market, the Group uses the discounted cash flow method and generally accepted options valuation models, based on current and future market conditions as of year-end. This methodology also adjusts the value based on the Company’s own credit risk (Debt Valuation Adjustment, DVA), and the counterparty risk (Credit Valuation Adjustment, CVA). These CVA and DVA adjustments are measured on the basis of the potential future exposure of the instrument (creditor or borrower position) and the risk profile of both the counterparties and the Group itself.

- In the case of financial assets and financial liabilities with offsetting positions in market risks or counterparty credit risks, it is permitted to measure the fair value on a net basis. However, this must be consistent with the manner in which market participants would price the net risk exposure at the measurement date.

Assets and liabilities measured at fair value are shown in Note 20.3.

h) Investments accounted for using the equity method

The Group’s interests in joint ventures and associates are recognized using the equity method.

Under the equity method, an investment in an associate or joint venture is initially recognized at cost. As of the acquisition date, the investment is recognized in the statement of financial position based on the share of its equity that the Group’s interest represents in its capital, adjusted for, if appropriate, the effect of transactions with Group’s entities, plus any goodwill generated in acquiring the entity. If the resulting amount is negative, zero is recorded for that investment in the statement of financial position, unless the Group has a present obligation (either legal or constructive) to support the investee’s negative equity situation, in which case a provision is recognized.

Goodwill from associates or joint ventures is included in the carrying amount of the investment. It is not amortized but is subject to impairment testing as part of the overall investment carrying amount when impairment indicators exist.

Dividends received from these investments are deducted from the carrying amount of the investment, and any profit or loss obtained from them to which the Group is entitled based on its ownership interest is recognized under “Share of profit (loss) of associates accounted for using equity method.”

Appendix 3: “Associates and Joint Ventures” to these consolidated financial statements, provides information about the relationship of the Company with each of these entities.

i) Inventories

Inventories are measured at their weighted average acquisition price or the net realizable value, whichever is lower.

The net realizable value is the estimated selling price in the ordinary course of business less the estimated costs necessary to make the sale.

The accompanying notes are an integral part of these consolidated financial statements.

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j) Non-current assets (or disposal groups) classified as held for sale or as held for distribution to owners and discontinued operations

Non-current assets, including property, plant and equipment; intangible assets; investments accounted for using the equity method, joint ventures, and disposal groups (a group of assets to be disposed of and the liabilities directly associated with those assets), are classified as:

- Held for sale, if their carrying amount will be recovered principally through a sale transaction rather than through continuing use.

- Held for distribution to owners, when the Company is committed to distribute the asset (or disposal group) to the owners.

For the above classification, the assets must be available for immediate sale or distribution in their present condition and its sale or distribution is highly probable. For this transaction to be considered highly probable, management must be committed to the sale or distribution and actions to complete the transaction must have been initiated and should be expected to be completed within one year from the date of classification.

Actions required to complete the sale or distribution plan should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. The probability of shareholders’ approval (if required in the jurisdiction) should be considered as part of the assessment of whether the sale or distribution is highly probable.

Non-current assets or disposal groups held-for-sale or held for distribution to owners are measured at the lower of their carrying amount and fair value less costs to sell or costs to distribute, as appropriate.

Depreciation and amortization on these assets cease when they meet the criteria to be classified as non-current assets held for sale or held for distribution to owners.

Assets that are no longer classified as held for sale or held for distribution to owners, or are no longer part of a disposal group, are measured at the lower of their carrying amounts before being classified as held for sale or held for distribution less any depreciations, amortizations or revaluations that would have been recognized if they had not been classified as held for sale or held for distribution to owners and their recoverable amount at the date of subsequent decision where they would be reclassified as non-current assets.

Non-current assets held for sale and the components of the disposal groups classified as held for sale or held for distribution to owners are presented in the consolidated statement of financial position as a single line item within assets called “Non-current assets or disposal groups held for sale or for distribution to owners,” and the respective liabilities are presented as a single line item within liabilities called “Liabilities included in disposal groups held for sale or for distribution to owners.”

The Group classifies as discontinued operations those components of the Group that either have been disposed of, or are classified as held for sale, and:

(i) represents a separate major lines of business or geographical area of operations;

(ii) is a part of a single coordinated plan to dispose a separate major line of business or geographical area of operations; or

(iii) is a subsidiary acquired exclusively with a view to resale.

The components of profit or loss after taxes from discontinued operations and the post-tax gain or loss recognized on the measurement to fair value less costs to sell or on the disposal of the assets or groups constituting the discontinued operation are presented as a single line item in the consolidated comprehensive income statement as “Income after tax from discontinued operations.”

The accompanying notes are an integral part of these consolidated financial statements.

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k) Treasury shares

Treasury shares are deducted from equity in the consolidated statement of financial position and measured at acquisition cost.

Gains and losses from the disposal of treasury shares are recognized directly in “Equity – Retained earnings”, without affecting profit or loss for the period.

l) Provisions

Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material). The unwinding of the discount is recognized as finance cost. Incremental legal cost expected to be incurred in resolving a legal claim is included in measuring of the provision.

Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of resources embodying economic benefits will be required to settle the obligation, the provision is reversed.

A contingent liability does not result in the recognition of a provision. Legal costs expected to be incurred in defending a legal claim are expensed as they are incurred. Significant contingent liabilities are disclosed unless the likelihood of an outflow of resources embodying economic benefits is remote.

l.1) Provisions for post-employment benefits and similar obligations

Some of the Group’s subsidiaries have pension and similar obligations to their employees. Such obligations, which combine defined benefits and defined contributions, are basically formalized through pension plans, except for certain non-monetary benefits, mainly electricity supply commitments, which, due to their nature, have not been externalized and are covered by the related in-house provisions.

For defined benefit plans, the cost of providing benefits is determined using the Projected Unit Credit Method, with actuarial valuations being carried out at the end of each reporting period. Past service costs relating to changes in benefits are recognized immediately.

The defined benefit plan obligations in the statement of financial position represent the present value of the accrued obligations, adjusted, once the fair value of the different plans’ assets has been deducted, if applicable.

For each of the defined benefit plans, any deficit between the actuarial liability for past services and the plan assets is recognized under line item “Provisions for employee benefits” within current and non-current liabilities in the consolidated statement of financial position, and any surplus is recognized under line item “Other financial assets” within non-current assets in the consolidated statement of financial position, provided that any surplus is recoverable by the Group, usually through a reduction in future contributions and taking into consideration the limit established in IFRIC 14, IAS 19 The limit on a defined benefit asset, minimum funding requirements, and their interaction.

Actuarial gains and losses arising in the measurement of both the plan liabilities and the plan assets, including the limit in IFRIC 14, are recognized directly as a component of other comprehensive income.

Contributions to defined contribution benefit plans are recognized as an expense when the employees have rendered their services.

The accompanying notes are an integral part of these consolidated financial statements.

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m) Translation of balances in foreign currency

Transactions carried out by each company in a currency other than its functional currency are recognized using the exchange rates prevailing as of the date of each transaction. During the period, any differences that arise between the prevailing exchange at the date of the transaction and the exchange rate as of the date of collection or payment are recognized as “Foreign currency exchange differences” in the statement of comprehensive income.

Likewise, at the end of each reporting period, receivable or payable balances denominated in a currency other than each company’s functional currency are translated using the closing exchange rate. Any differences are recognized as “Foreign currency exchange differences” in the statement of comprehensive income.

The Group has established a policy to hedge the portion of revenue from its subsidiaries that is directly linked to variations in the U.S. dollar, through obtaining financing in such currency. Exchange differences related to this debt, as they are cash flow hedge transactions, are recognized, net of taxes, as a component of other comprehensive income in item “Gains (losses) from cash flow hedge” and reclassified to profit or loss when the hedged cash flows impact profit or loss. This term has been estimated at ten years.

n) Current/non-current classification

In these consolidated statements of financial position, assets and liabilities expected to be recovered or settled within twelve months are presented as current items, except for post-employment and other similar obligations; and those assets and liabilities expected to be recovered or settled in more than twelve months are presented as non-current items. Deferred income tax assets and liabilities are classified as non-current.

When the Company have any obligations that mature in less than twelve months but can be refinanced over the long term at the Company’s discretion, through unconditionally available credit agreements with long-term maturities, such obligations are classified as long-term liabilities.

o) Income taxes

Income tax expense for the year is determined as the sum of current taxes from each of the Group’s subsidiaries and results from applying the tax rate to the taxable income for the year, after permitted deductions have been made, plus any changes in deferred tax assets and liabilities and tax credits, both for tax losses and deductions. Differences between the carrying amount and tax basis of assets and liabilities originate deferred tax asset and liability balances, which are calculated using the tax rates expected to apply when the assets and liabilities are realized or settled, based on tax rates that have been enacted or substantively enacted by the end of the reporting period.

Deferred tax assets are recognized for all deductible temporary differences, tax losses and unused tax credits to the extent that it is probable that sufficient future taxable profits exist to recover the deductible temporary differences and make use of tax credits. Such deferred tax asset is not recognized if the deductible temporary difference arises from the initial recognition of an asset or liability that:

- Did not arise from a business combination, and

- At initial recognition affected neither accounting profit nor taxable profit (loss).

In respect of deductible temporary differences associated with investments in subsidiaries, associates and joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profits will be available against which the temporary differences can be utilized.

Deferred tax liabilities are recognized for all temporary differences, except those derived from the initial recognition of goodwill and those that arose from measuring investments in subsidiaries, associates and joint ventures in which the Group can control their reversal and where it is probable that they will not be reversed in the foreseeable future.

The accompanying notes are an integral part of these consolidated financial statements.

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Current tax and changes in deferred tax assets or liabilities are recorded in profit or loss or in equity within the statement of financial position, depending on where the gains or losses that triggered these tax entries have been recognized.

Any tax deductions that can be applied to current tax liabilities are credited to earnings within the line item “Income tax expenses”, except when doubts exist about their tax realization, in which case they are not recognized until they are effectively realized, or when they correspond to specific tax incentives, in which case they are recorded as government grants.

At the end of each reporting period, the Company reviews the deferred taxes assets and liabilities recognized, and makes any necessary corrections based on the results of this analysis.

Deferred tax assets and deferred tax liabilities are offset in the statement of financial position if it has a legally enforceable right to set off current tax assets against current tax liabilities, and only when the deferred taxes relate to income taxes levied by the same taxation authority.

p) Revenues and expense recognition

Revenue is recognized when the gross inflow of economic benefits arising in the course of the Group’s ordinary activities in the period occurs, provided that this inflow of economic benefits results in an increase in total equity other than increases relating to contributions from equity participants and such benefits can be measured reliably.

Revenues and expenses are recognized on an accrual basis and depending on the type of transaction; the following criteria for recognition are taken:

- Generation and transmission of electricity: Revenue is recognized based on physical delivery of energy and power, at prices established in the respective contracts, at prices stipulated in the electricity market by applicable regulations or at marginal cost determined on the spot market, as the case. This revenue includes an estimate of the service provided and not billed until the closing date (see Note 2.3).

- Distribution of electricity: Revenue is recognized based on the amount of energy supplied to customers during the period, at prices established in the respective contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate. This revenue includes an estimate of the energy supplied but not yet billed and for which customers’ meters have not been read yet (see Note 2.3).

Revenue from rendering of services is only recognized when it can be estimated reliably, by reference to the stage of completion of the service rendered at the date of the statement of financial position.

Revenue from sales of goods is recognized based on the economic substance of the transaction and are recognized when all and each of the following conditions are met:

- the entity has transferred to the buyer the significant risks and rewards of ownership of the goods;

- the entity retains neither continuing managerial involvement to the degree usually associated with ownership nor effective control over the goods sold;

- the amount of revenue can be measured reliably;

- it is probable that the economic benefits associated with the transaction will flow to the entity; and

- the costs incurred or to be incurred in respect of the transaction can be measured reliably.

Revenue is measured at the fair value of the consideration received or receivable that gives rise to the revenue.

In arrangements under which the Group will perform multiple revenue-generating activities (multiple-element arrangement), the recognition criteria are applied to the separately identifiable components of the transaction in order to reflect the substance of the transaction or to two or more transactions together when they are linked in such a way that the commercial effect cannot be understood without reference to the series of transactions as a whole. The Group excludes from revenue those gross inflows of economic benefits it receives when it acts as an agent or commission agent on behalf of third parties, and only recognizes as revenue economic benefits received for its own activity.

The accompanying notes are an integral part of these consolidated financial statements.

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When goods or services are exchanged or swapped for goods or services of a similar nature and value, the exchange is not regarded as a revenue-generating transaction.

The Group recognizes the net amount of non-financial asset purchase or sale contracts that are settled for a net amount of cash or through some other financial instruments. Contracts entered into and maintained for the purpose of receiving or delivering these non-financial assets are recognized on the basis of the contractual terms of the purchase, sale, or usage requirements expected by the entity.

Interest income (expense) is recognized using the effective interest rate applicable to the outstanding principal to be amortized over the repayment period.

Expenses are recognized on an accruals basis, immediately in the event of expenditures that do not generate future economic benefits or when they not meet the requirements for recording them as assets.

q) Earnings per share

Basic earnings per share are calculated by dividing net income attributable to shareholders of the Parent Company by the weighted average number of ordinary shares outstanding during the period, excluding the average number of shares of the Parent Company held by other subsidiaries within the Group, if any.

Basic earnings per share for continuing and discontinued operations are calculated by dividing net income from continuing and discontinued operations attributable to shareholders of the Parent Company (the numerator) by the weighted average number of ordinary shares outstanding (the denominator) during the year, excluding the average number of shares of the Parent Company held by other subsidiaries within the Group, if any.

During the years ended December 31, 2016, 2015 and 2014, the Group did not engage in any transaction of any kind with potential dilutive effects leading to diluted earnings per share that could differ from basic earnings per share.

r) Dividends

Article 79 of the Chilean Companies Act establishes that, unless unanimously agreed otherwise by the shareholders of all issued shares, listed corporations must distribute a cash dividend to shareholders on an annual basis, pro rata to the shares owned or the proportion established in the Company’s by-laws if there are preferred shares, of at least 30% of net income for each period, except when accumulated losses from prior years must be absorbed.

As it is practically impossible to achieve a unanimous agreement given the Company’s highly fragmented share ownership, at the end of each reporting period the amount of the minimum statutory dividend obligation to its shareholders is determined, net of interim dividends approved during the fiscal year, and then accounted for in “Trade and other current payables” and “Accounts payable to related companies”, as appropriate, and recognized in equity.

Interim and final dividends are deducted from equity as soon as they are approved by the competent body, which in the first case is normally the Company’s Board of Directors and in the second case is the Ordinary Shareholders’ Meeting.

The accompanying notes are an integral part of these consolidated financial statements.

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s) Share issuance costs

Share issuance costs, only when they represent incremental expenses directly attributable to the transaction, are recognized directly in net equity as a deduction from “Share premiums,” net of any applicable taxes. If the share premium account has a zero balance or if the costs described exceed the balance, they are recognized in “Other reserves.”

t) Statement of cash flows

The statement of cash flows reflects changes in cash and cash equivalents that took place during the period, determined with the direct method. It uses the following expressions and corresponding meanings:

- Cash flows: inflows and outflows of cash or cash equivalents, which are defined as highly liquid investments maturing in less than three months with a low risk of changes in value.

- Operating activities: the principal revenue-producing activities of the Group and other activities that cannot be considered investing or financing activities.

- Investing activities: the acquisition and disposal of long-term assets and other investments not included in cash and cash equivalents.

- Financing activities: activities that result in changes in the size and composition of the total equity and borrowings of the Group.

During the years ended December 31, 2016, 2015 and 2014, there were no significant non-cash transactions.

The accompanying notes are an integral part of these consolidated financial statements.

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4. SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS

a) Regulatory framework

Argentina

Argentina has shown signs of intervention in the electricity market since the crisis of 2002. Under the previous regulations, generators sold to distributors at prices obtained from centralized calculations of the average spot market price. The distributers’ purchase price was the average price forecast for the next six months, called the Seasonal Price (Precio Estacional). Any differences between the Seasonal Price (the purchase price) and the actual spot price (the selling price) was charged to the Seasonal Fund (Fondo Estacional) managed by the Wholesale Electricity Market Administration Company (CAMMESA - Compañía Administradora del Mercado Mayorista Eléctrico).

However, after the 2002 crisis, the authorities changed the price-setting criteria, bringing the marginal pricing system to an end. First, marginal prices were calculated without taking into consideration the natural gas shortages. In effect, despite the fact that generation is dispatched on the basis of the fuels actually used, SE Resolution No. 240/2003 establishes that the marginal price is to be calculated taking into consideration all of the generation units as if there were no restrictions in effect on natural gas supplies. In addition, the expense of water is not included in the calculations if its opportunity cost is higher than the cost of generating power with natural gas. Second, it established a spot price ceiling of Ar$120 per MWh. However, CAMMESA pays the actual variable costs of the thermal plants that run on liquid fuels through the Temporary Dispatch Cost Overruns program.

In addition, as the dollarized economy was devalued and went back to the Argentine peso, payment for capacity fell from US$10 to Ar$10 per MWh. Capacity payments have subsequently risen slightly to Ar$12 per MWh.

Additionally, the freezing of prices paid by distributors caused a gap in relation to actual generation costs, resulting in various types of special agreements for recovering costs, in accordance with regulations in force.

It was in this context that the government announced in 2012 its plan to change the current regulatory framework for one based on an average cost scheme.

Resolution No. 95/2013 was published in March of 2013, significantly changing the system for generators’ remunerations and setting new prices for capacity depending on the type of technology used and availability. It also set new values for paying for non-fuel variable costs, as well as additional remuneration for energy generated.

In May 2013, the Group’s generating companies (Enel Generación Costanera (formerly named Central Costanera), Enel Generación El Chocón (formerly named Hidroeléctrica El Chocón) and Dock Sud) accepted the terms of SE Resolution No. 95/2013.

This resolution marked the end of marginal pricing as a payment system in the Argentine power generation market and established, instead, a payment system by type of technology and size of plant. For each case, it recognizes fixed costs (determined on the basis of fulfillment of availability) and variable costs, plus an additional remuneration (the two parts are determined based on energy generated). Part of the additional remuneration is placed in a trust for future investments.

Commercial management and fuel dispatch are handled by of CAMMESA; Terminal Market agreements cannot be extended or renewed, and large users, once their respective contracts are up, must purchase their supply from CAMMESA. However, the Secretary of Energy (“SE”), in Note SE 1807/13, gave generators the opportunity to express their intention to continue handling collections for their entire contract portfolio, thus ensuring a certain amount of cash flow and a continuing relationship with the customer.

It is also important to mention that Enel Generación Costanera has availability contracts signed in 2012 that are still in effect, as well as combined cycle contracts (until 2016) and turbosteam generation contracts (until 2019) that will enable the company to implement an investment plan for the Costanera plant generation units in order to optimize the reliability and

The accompanying notes are an integral part of these consolidated financial statements.

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availability of that plant. The contracts also include payment of the commitments under the Long-Term Service Agreement (LTSA) for the plant’s combined cycles.

The SE through Resolution No. 529/2014, updated generators’ remuneration, which had been in effect since they were set in February 2013 under Resolution No. 95/2013. The new resolution increased recognition of fixed costs for combined cycle and large hydroelectric plants by 25% and adjusted variable costs by 41% for thermal plants and 25% for hydroelectric plants. A new variable remuneration was set for biodiesel-fired plants. The additional remuneration increased 25% for thermal plants, and a new charge of Ar$21 (approximately Ch$ 883) per MWh was set for one-time maintenance for combined cycle and Ar$24 (approximately Ch$ 1,010) per MWh for other thermal generation plants. The resolution was retroactively applied in February 2014.

The SE through Resolution No. 482/2015, updated generators’ remuneration, which had been in effect since they were set in February 2014 under Resolution No. 529/2014. The new resolution increased recognition of fixed costs for combined cycle and large hydroelectric plants by 28%, and 64% for mid-size hydroelectric plants. The variable costs were adjusted by 23%, hydroelectric plants are exempted of variable electric transmission payments and has been implemented a new incentive scheme for generation and operative effectiveness for thermal plants. The additional remuneration increased by 26% for thermal plants and 10% for mid-size hydroelectric plants. The cost for non-recurrent maintenance was increased by 17% and the same concept was created for hydro electrical plants for Ar$8 (approximately Ch$ 337) per MWh. Finally, a new charge of Ar$15.8 (approximately Ch$ 665) per MWh for thermal plants and Ar$6.3 (approximately Ch$ 265) per MWh for hydro electrical plants was set for investments funding, which will be effective from February 2015 to December 2018 only for those generators participating in the projects. The new generation will have an additional remuneration equivalent to 50% of the direct additional remuneration based on technology for a 10-year period. The resolution was retroactively applied in February 2015.

On March 30, 2016, the SE through Resolution No. 22/2016 updated the generators’ remuneration in effect under Resolution No. 482/2015. The increases were applied to all remuneration concepts that are collected by the generators. The new resolution increased recognition of fixed costs for thermal plants by 70% and for hydroelectrical plants by 120%.  The variable costs were adjusted by 40% for thermal and hydroelectrical plants. The cost for non-recurrent maintenance was increased by 60% for thermal plants and 25% for hydroelectrical plants, respectively. The additional remuneration was not updated. This new resolution was retroactively applied in February 2016.

On March 22, 2016, the SE through Resolution No. 21/16, requested bids to offer new capacity for thermal generation for the summer 2016/17, winter 2017 and summer 2017/18 periods. The resolution stated that the offer cannot include, as of the date the resolution was published, pre-existing generation units already interconnected to the Argentine Interconnection System (“SADI” in its Spanish acronym) or capacity that was already offered in other agreements.

The five (5) – ten (10) year contract will be entered into with CAMMESA as a representative of MEM’s agents and monthly remuneration for capacity will be in US$ per MW, while energy generated with each fuel will be in US$  per MWh, as the payment priority equivalent to that of payment for liquid fuel. The supply and recognition of fuel costs will be based on current regulations, as appropriate. The minimum capacity at each interconnection node must not be less than 40MW and preferably must be of dual capacity for fuel consumption, with specific maximum consumption of up to 2,500 kcal/kWh. CAMMESA will make known the expected locations for generation between 50MW to 150MW.

The order of priority for the offers was based on increasing costs, therefore, the assessment formulas must be made available to the bidders.

On September 14, 2016, the results of the New Thermal Generation Bid were published in the Official Bulletin, granting a total of 1,915 MW (out of 6,000 MW total offers). Four offers propose to deliver new energy (545 MW of capacity) to the SADI in December 2016; ten offers propose to deliver new energy (685 MW) in the first quarter of 2017 and four more offers are expecting to deliver new energy (229 MW) in the second quarter of 2018. In addition, 26 offers are committed to start their service in the second half of 2017, and five other offers in 2018. Likewise, through Note No. 355, the SE instructed CAMMESA to encourage pricing improvements to those entities whose offers were considered acceptable but no bid was granted. As a result of new pricing offers, an additional 956 MW were granted to seven offers proposing to deliver new energy within the period from January 30 to December 1, 2017. Lastly, on October 28, 2016, the SE, through Resolution No. 387/E/2016, instructed CAMMESA to add two additional projects for a total of 234 MW. None of the Group’s entities participated in the bidding process.

The accompanying notes are an integral part of these consolidated financial statements.

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On November 16, 2016, the SE, through Secretary of Electrical Energy (“SEE”) Resolution Nos. 420-16 and 455-16, called for those entities interested in developing infrastructure projects to present projects until January 13, 2017 that (i) reduced costs in the Wholesale Electrical Market (“MEM”) and (ii) increased the reliability of the Argentine Electrical System.

On February 2, 2017, the SEE issued Resolution No. 19/2017 replacing SEE Resolution No. 22/2016, which set the remuneration guidelines for existent power generating plants. Resolution No. 19/2017 defines the minimum remuneration for the energy capacity of technology and scale, and allows thermal units to offer equal remuneration for availability energy contracts for all technologies. Thermal generators may declare the price of firm capacity to be committed for a three-year period per unit each summer period, and may also provide the information by summer and winter periods (adjustments could be made during the period). As an exception applicable to 2017, Resolution No. 97/2017 authorized the declaration of the Guaranteed Availability Commitments (Compromisos de Disponibilidad Garantizada, in Spanish) in conjunction with the information required for the Winter Seasonal Programming, effective from May 1, 2017 to October 31, 2017. Generators will sign a Guaranteed Availability Commitment contract with CAMMESA, which may be transferred to demand as defined by SEE. The remuneration will be received by each generation unit with a committed capacity and will be in proportion to its compliance, with the minimum remuneration calculated based on the minimum price. On the other hand, the thermal generation could offer additional capacity availability for bi-annual periods, which will be auctioned at a maximum price.

In relation to hydroelectric power plants, a new scheme is defined to assess energy capacity, which is based on actual energy capacity available (that will result in a higher value for capacity than under prior regulations). Likewise, a base is defined for the price of energy capacity, a second for the period from May 2017 to October 2017, and a third from November 2017.

The remuneration values under Resolution No. 19/2017 are denominated in U.S. dollars and will be translated to Argentine pesos using the last business day exchange rate published by the Argentine Central Bank, and will be effective for the term established in CAMMESA’s procedures.

Brazil

Legislation in Brazil allows the participation of private capital in the electricity sector, upholds free competition among companies in electricity generation, and defines criteria to avoid certain levels of economic concentration and/or market practices that may cause a decline in free competition.

Based on the contract requirements as stated by distribution companies, the Ministry of Energy has been involved in planning the expansion of the electricity system, setting capacity quotas by technology on the one hand and, on the other, promoting separate tender processes for thermal, hydraulic or renewable energies, or directly holding tender processes for specific projects. The operation is being coordinated in a centralized fashion in which one National System Operator (“ONS” in its Portuguese acronym) coordinates centralized load dispatch based on variable production costs and seeks to guarantee to meet demand at the minimum cost for the system. The price at which transactions take place on the spot market is called the Difference Liquidation Price (Precio de Liquidación de las Diferencias, PLD).

Generation companies sell their energy on the regulated or unregulated market through contracts, and trade their surpluses or deficits on the spot market. The free market is aimed at large users, with a limit of 3,000 kW or 500 kW if they purchase Non-Conventional Renewable Energy (“NCRE”).

In the unregulated market, suppliers and their clients directly negotiate energy purchase conditions. In the regulated market, in contrast, where distribution companies operate, energy purchases must go through a bidding process coordinated by the National Electricity Agency (“ANEEL” in its Portuguese acronym). In this way, the regulated purchase price used in the determination of tariffs to end users is based on average prices of open bids, and there are separate bidding processes for existing and new energy. Bidding processes for new energy contemplate long-term generation contracts in which new generation projects must cover the growth of demand foreseen by distributors. The open bids for existing energy consider shorter contractual terms and seek to cover the distributors’ contractual needs arising from the expiry of prior contracts. Each bidding process is coordinated centrally. The ANEEL sets maximum prices and, as a result, contracts are signed where all distributors participating in the process buy pro rata from each offering generator.

On November 25, 2014, the ANEEL approved the new PLD limits for 2015. The maximum limits (decreased from R$823 to R$388 per MWh) and the minimum (increased from R$16 to R$30 per MWh).

The accompanying notes are an integral part of these consolidated financial statements.

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The main effect of the new limits is to reduce the financial impact for distributors of potential future risks when contracting energy on the spot market, as in 2014 when the spot price was at its maximum for most of the year. The new maximum price also mitigates the risk of unrecoverable economic and financial losses for generators, when production is below contract values. However, the possibility of selling excess energy at higher prices decreases. Currently generators can divide their excess energy throughout the months of the year, to increase their revenues by allocating more energy to those months where higher prices are expected, as the ceiling is lower.

Annually, the ANEEL confirms through resolutions the minimum and maximum values for the PLD limits. In 2016, the maximum and minimum PLD limits were R$422.56 (approximately Ch$ 86,833) per MWH and R$30.25 (approximately 6,216) per MWh, respectively. Such PLD limits reflect the estimated costs of the Itaipú mega hydro power plant, which had a tariff of US$ 25.78 (approximately Ch$ 17,241) per kW in 2016.

These regulatory mechanisms ensure the creation of regulatory assets/liabilities, whose rate adjustment for deficits in 2014 will take place in the tariff adjustments starting in 2015 (March for Ampla and April for Coelce). This mechanism has existed since 2001, and is called the Compensation Clearing Account - Part A (Cuenta de Compensación de Valores – Parte A, “CVA”). They aimed to maintain consistent operating margins for the dealer by allowing tariff revenue due to the costs of Parcel A.

Compensation Clearing Account (“CVA” for its acronym in Portuguese) helps maintain stability in the market and enables the creation of deferred costs, which is compensated through tariff adjustments based on the fees necessary to compensate for deficits the previous year.

On December 10, 2014, an addendum was signed to the concession contract for distributors in Brazil (Ampla and Coelce), which allows these regulatory assets (CVA’s and others) to be included in indemnitee assets at the end of the concession, and if this is not possible over time, it allows compensation through tariffs. Therefore, the recognition for these regulatory assets/liabilities is allowed under IFRS.

Brazil experienced drought conditions throughout 2014. In November 2014, the system reached the maximum risk of energy rationing. The average reservoir levels were 1% lower than at the last rationing. However, the government stated that there was no risk to supply.

The government created the ACR account to cover the additional energy costs through bank loans to be paid within two years through the tariff. Distributors had used approximately R$ 18 billion (approximately Ch$ 3.7 billion) from the ACR account by December 31, 2014. However, this was not sufficient to cover the shortfall. In March 2015, a new loan was approved against the ACR account to cover the shortfall of November and December 2014. In addition, an extension in the payment period was approved for all loans, which currently will have to be paid in 54 months from November 2015.

In January 2015, based on the mismatches between the costs recognized in tariffs and actual costs other than those related to operations of the distribution entities, and increased inherent drought conditions costs, ANEEL began the application of a system (known as Tariffs Flags) of monthly charges over the tariff to the customers, provided that the marginal cost of the system is higher than the regulatory standard. The purpose of the regulator is to indicate the customers the generating cost of the following month, and paying in advance to the distribution companies an amount that would only be available in the next tariff review process.

The Tariff Flags system initially consisted of three levels of colored flags: Green, Yellow and Red as follows:

	Description	To be applied when CMO (R$/MWh)	Additional Tariff (R$/MWh)
Green	Favorable generation of energy conditions	<200	None
Yellow	Less favorable generation of energy conditions	>200<388.48	+ 0.025
Red	Higher costs generation conditions	>388.48	+ 0.045

From January 2015 until the reporting date of these financial statements, the values have been changing based on new expectations of future generation costs.

In summary, with this mechanism the generation cost that is currently transferred to the customer only once a year (when the annual tariff adjustment is performed) will generate a monthly variation and the customer can improve control over his/her

The accompanying notes are an integral part of these consolidated financial statements.

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electricity consumption. That is, the consumers will notice a lower tariff adjustment as they are paying a higher amount during the month. The flags system implemented by the ANEEL, is an accurate indicator of the actual cost of energy generated, allowing consumers a rational use of electrical energy.

As of February 1, 2016, the Red flag was separated into two levels – R$3.00 and R$4.50 – applicable to a consumption of 100kWh. Also, the Yellow flag value was reduced from R$2.5 to R$1.5 applicable to a consumption of 100kWh (or portions).

The following table summarizes the updated levels of colors flags applied in 2016:

	Description	To be applied when CMO (R$/MWh)	Additional Tariff (R$/MWh)
Green	Favorable generation of energy conditions	<211.28	None
Yellow	Less favorable generation of energy conditions	>211.28<422.56	+ 0.015
Red 1	Higher costs generation conditions	>422.56<610.00	+ 0.030
Red 2	Higher costs generation conditions	>610.00	+ 0.045

The improved conditions of the rainy season in 2016 increased hydroelectrical reserves to their normal levels and the combined effect of a decrease in demand together with the addition of new power plants in the Brazilian electricity system, led to a change in the Tariff Flags in the last months, such that the flag was Yellow in March 2016 and Green in April 2016.

In 2015, six electric power tenders were carried out for purposes of reestablishing the energy supply:

• One A-1 tender: 1,954 MWavg, allocated to Hydro (94%), Biomass (4%) and Gas (2%); from 1 to 3 years of energy supply;

• Four A-3 tenders and reserve:

•   97 MWavg, allocated to Wind (30%) and Biomass (70%), at an average price of R$200/MWh;

•   233 MWavg, allocated to Solar (100%), at an average price of R$301.8/MWh;

•   314.3 MWavg, allocated to Wind (72%), Hydro (15%), Gas (7%), and Biomass (6%), at an average price of R$189/MWh; and

•   508 MWavg, allocated to Wind (52%) and Solar (48%), at an average price of R$249/MWh.

• One A-5 tender: 1,147 MWavg, allocated to Gas (76%), Hydro (18%) and Biomass (7%), at an average price of R$259.2 MWh.

Also, a Tender for Contracting Hydroelectrical Plants Concessions was carried out through the quota regime, in which the seller is granted energy (3,223 MWavg) and capacity (6,061 MW) for an Annual Operational Revenue from Generation.

In 2016, two electric power tenders were carried out as follows:

• One A-5 tender for 200 MWavg allocated to Gas (2%), Hydro (58%) and Biomass (40%), at an average price of R$198.59MWh.

• One A-1 tender for 21 MWavg at an average price of R$118.15 MWh.

Energy Development Account (CDE)

The CDE, created under Law 10,438/2002, is a state-owned fund that provides energy development from alternative sources, promotes energy service globalization, and subsidizes the low income residential sub-class. The fund is financed through a charge in the tariff of customers and generators.

The accompanying notes are an integral part of these consolidated financial statements.

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Pro rata allocation due to judicial matters

At the end of September 2015, ANEEL, based on certain judicial outcomes referring to the suspended collection of CDE charges of certain industrial participants (members of the Associação Brasileira de Grandes Consumidores Industriais de Energia e de Consumidores Livres - ABRACE), had to recalculate the CDE pro rata allocation to the rest of the applicable participants, despite having transferred Parcel A costs. Subsequently, specific tariffs applicable to the members of Abrace will be published and the distribution companies will have to promote the new invoicing to those customers. The distribution companies will must maintain the payments of the CDE parts under actual amounts (published in the resolutions); and, finally the deficit originated for the revenue losses will be included in the tariff adjustments of the distribution companies.

CDE’s Monthly Rate: Indemnification for discounts granted to consumers under judicial orders

Resolution No. 1,576 authorized electric energy distributors to recover the lower amounts billed due to judicial orders against the Energy Development Account, through the CDE’s monthly installments.

The difference between the regular tariff and the judicial order tariffs will be deducted from the CDE’s monthly installment. This adjustment will not be implemented through the tariffs and no regulatory assets will be included in the tariffs. The discount applied to the CDE’s monthly installment of consumers with judicial orders will be compensated, that is, the monthly payment of the installments will be lower than the installments defined in the resolution.

 Distributed Generation

In May 2015, the regulator in a public hearing began the process to modify the regulations related to the distributed micro- and mini-generation aimed to making it more viable. The most important modification is to allow the installation of generation systems (of any renewable source, up to 3MW for hydro and 5MW for other sources) in locations other than where the load is located.

On November 24, 2015, ANEEL through Resolution No. 687/15 approved the regulation on distributed micro- and mini-generation by using an energy compensation mechanism.

Under the new regulations, effective on March 1, 2016, the use of any source of renewable energy as well as qualified co-generation is allowed. Distributed micro-generation is defined as a generating power plant with installed capacity of up to 75 kW. Distributed mini-generation is defined as a generating power plant with installed capacity of more than 75kW and less than 5 MW (3 MW for water supply) connected to the distribution network through consumption unit facilities.

If the volume of energy generated in a particular month is higher than the energy consumed in that particular month, the consumer has a credit that can be used to reduce the next month’s invoice. In accordance with the new regulation, the effective period for energy credits was increased from 36 to 60 months and the credits may be applied to the consumption of units by the same owner located in other places, as long as the service area is from the same distributor. This type of use for credits is referred to as “distance auto-consumption.”

Another new feature available under the regulation is the ability to install distributed generation in condominiums (companies with multiples consumption units). Under this feature, the energy generated can be distributed in specific percentages defined by the consumers.

ANEEL also created the “shared generation” scheme which allows parties interested in being part of a consortium or cooperative to install distributed mini/micro generation and use the energy generated to reduce the invoices of all members of the consortium or cooperative.

In terms of the procedures necessary to connect the micro/mini generator to the distribution network, ANEEL set up rules that simplify the process for access requests by creating specific forms to be completed by the consumers and reducing the period, from 82 days to 34 days, which distributors have to connect the 75kW plants. In addition, from January 2017, customers will be able to make access requests and monitor their progress online.

The accompanying notes are an integral part of these consolidated financial statements.

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Resolution No. 237

On September 6, 2016, the Ministry of Mining and Energy (“MME”) issued Resolution No. 237 allowing energy distribution companies to request to the MME that their investments in high voltage distribution systems and in substations be categorized as priority. Such classification allows the distributors to issue “infrastructure debentures”, which are financing bonds with maturities longer than those of normal bonds, and that also have tax benefits for creditors. The grant of this benefit to energy distribution companies was as a result of an initiative carried out between the Brazilian Electric Energy Distributors Association (“ABRADEE” in its Portuguese acronym) and the Ministry of Mining and Energy.

Provisional Measure No. 735

On June 22, 2016, ANEEL issued Provisional Measure No. 735, establishing the following changes:

1)   Sectorial Commissions:

• Beginning on January 1, 2017, the Chamber of Electric Energy Commercialization (“CCEE” in its Portuguese acronym) will replace Eletrobás in performing the collection activities for the Global Reserve of Reversal (“RGR” in its Portuguese acronym), Energy Development Account (“CDE”) and the Fuel Consumption Account (“CCC”), as well as, in managing the financing for the payment of the administration and operational expenditures incurred in this sectorial funds.

• Beginning on January 1, 2030, the CDE’s annual installments allocation will be made in proportion to the electric energy consumer market in MWh served by the distribution companies and the distribution and transmission concessionaires.  The geographical location will no longer be taken into account. From January 1, 2017 to December 31, 2029, a gradual and uniform reduction will be applied in order to eliminate the actual proportion (4.53 for the CDE installments in the South, South East, North and North East regions).

• Beginning on January 1, 2030, the cost per MWh of the CDE’s annual installments paid by the consumers will be pro rata allocated to their voltage levels, as follows:

-  High Voltage = 1/3 x Low Voltage cost

-  Medium Voltage = 2/3 x Low Voltage cost

• From January 1, 2017 to December 31, 2029, a gradual and uniform reduction will be applied in order to reach the above proportions.

2)   Itaipú Binacional’s Tariff

Itaipú Binacional (“Itaipú”) is a hydroelectrical power plant constructed as part of the International Agreement signed between Brazil and Paraguay on April 26, 1973, for the development of the hydroelectric resources of the Parana River located at the Brazilian-Paraguayan border (from the Seven Falls to the Iguazú’s River mouth).

The transfer tariff of Itaipu’s energy is fixed in US$/kW for monthly contracted capacity. Brazilian energy distribution companies must pay Eletrobas monthly through Itaipu’s Electric Energy Commercialization account an amount equal to the product of the monthly contracted capacity quota multiplied by the transfer tariff of Itaipu’s energy, both as approved by ANEEL.

Beginning on January 1, 2016, in accordance with Article 6 of Provisional Measure No. 735, a new transfer tariff of Itaipu’s energy was established, which will be included in the total cost of the 15.3 multiplier factor over the energy transfer cost referred to in Appendix C of the Brazilian-Paraguayan Itaipu Agreement.

3)   Tenders

For the electric energy generation, transmission and distribution concessions that will not be renewed, the Brazilian government may propose a sale/tender of the new 30-year concession period.

The accompanying notes are an integral part of these consolidated financial statements.

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Law No. 13, 2013: Beneficiaries to the discount in the Tariffs for Using Distribution System (“TUSD”) and Tariffs for Using Transmission System (“TUST”)

Law No. 13,203, published on December 8, 2015, broadened the scope of beneficiaries able to use the discount under TUSD/TUST, as well as, the volume and use of the energy when it is considered and used for self-generation:

• ANEEL will establish a discount of up to 50% to the TUSD/TUST tariffs for those hydroelectrical energy projects with total capacity less than or equal to 3,000 kW and those energy projects based on solar, wind, biomass and qualified co-generation whose total capacity connected to the distribution and transmission systems is less than or equal to 30,000 kW. The discount will be applicable to energy production and consumption that is (i) purchased/sold for this type of projects and (ii) used as own production for those entities beginning operations on January 1, 2016.

• ANEEL will establish a discount of up to 50% to the TUSD/TUST tariffs for those solar, wind, biomass and qualified co-generation energy projects whose total capacity connected to the distribution and transmission systems is more than 30,000 kW and less than 300,000 kW and that comply with the following criteria: (i) the project was originated as a result of the energy auction carried out on January 1, 2016; or (ii) the project was authorized to begin operations on January 1, 2016.

In implementing Law No. 13,203, ANEEL established Public Audience No. 38 that will replace Resolution No. 77/2004. The discounts will result in a significant increase in the amounts that are subsidized by the CDE, thus, increasing the tariffs for consumers of our subsidiaries Ampla and Coelce. The fixed percentage discount of 50% proposed by ANEEL for these type of energy projects is the minimum that may be applied based on current regulations.

White Tariff

On September 12, 2016, ANEEL Resolution No. 733/2016 approved the conditions for applying a low voltage time-of-use tariff, the “White Tariff”.

The “White Tariff” is a new time-of-use tariff option that indicates to consumers the fluctuation in the value of energy at a particular date and time of consumption. It will be offered to consumers supplied low voltages (127V, 220V, 380V and 440V, Group B) and those consumers from Group A (high voltage) that comply with certain criteria under the White Tariff.

Resolution No. 733/2016 states the following with regard to the White Tariff:

• The application will begin in January 2018 for consumers already connected with monthly consumption greater than 500 kWh (12 cycles average) and for new connections;

• The application will begin in January 2019 for consumers already connected with monthly consumption greater than 250 kWh (12 cycles average);

• After January 2020, it will be applied to all consumers;

• The value of energy, under this tariff option, will be obtained from peak, intermediate and off-peak periods and are approved by ANEEL during its periodic review of the distribution companies.

• The “low income” (under specific regulation of ANEEL) and public lighting consumers cannot opt for the White Tariff.

• The energy meter equipment cost will be charged to the distributor, except for meter equipment with additional features;

• Any potential customization of the consumption unit will be charged to the owner.

Colombia

In 1994, the Public Utility Law (Ley de Servicios Públicos Domiciliarios, Law 142) and the Electricity Law (Ley Eléctrica, Law 143) were passed. These laws set out the general criteria and policies ruling the public utility service provision in Colombia, as well as the procedures and mechanisms for regulating, monitoring and overseeing them.

The Electricity Law puts the constitutional focus into practice, regulating the generation, transmission, distribution and sale of electricity, creating the market and competitive environment, strengthening the industry and setting the boundaries for government intervention. Taking into account the nature of each activity or business, general guidelines were established for developing the regulatory framework, creating and implementing the rules that would allow for free competition in the power

The accompanying notes are an integral part of these consolidated financial statements.

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generation and sales industries, while the directives for the transmission and distribution industries were geared toward treating these activities as monopolies while seeking out competitive conditions wherever possible.

The main institution in the electricity sector is the Mining and Energy Ministry, who’s Mining Energy Planning Unit, (Unidad de Planeación Minero Energética, UPME) draws up the national Energy Plan and the Generation and Transmission Expansion Plan. The Energy and Gas Regulatory Commission (Comisión de Regulación de Energía y Gas, CREG) and the Public Service Superintendence (Superintendencia de Servicios Públicos, SSPD) regulate and oversee, respectively, the companies in the industry, and the Superintendence of Industry and Commerce is the national authority for free trade protection issues.

The electricity industry operates on the basis of electricity-selling companies and the large consumers being able to buy and sell energy through bilateral contracts or on a short-term energy exchange market, called the “energy exchange” that operates freely according to supply and demand conditions. In addition, long-term auctions of Firm Energy within a Reliable Charge scheme are carried out to promote the expansion of the system. The market is operated and administered by XM, which is in charge of the National Dispatch Center (Centro Nacional de Despacho, CND), and the Commercial Interchange System Manager (Administrador del Sistema de Intercambios Comerciales, ASIC).

Peru

The main legislations in the regulatory framework for doing business in the power industry in Peru are the Electricity Concessions Law and its regulations; the Law to Ensure Efficient Development of Electricity Generation (Law No. 28,832); the Electricity Industry Antimonopoly and Oligopoly Law; the Technical Standard for Electricity Service Quality; the Environmental Protection Regulations for Electricity Activities; the Law Creating the Energy and Mining Investment Supervisory Agency (OSINERGMIN) and its regulations; and the Regulations for Unregulated Electricity Users and Decree Law No. 1221, which improves the regulation of distribution of electricity to promote access to electricity in Peru.

Law No. 28,832, whose purpose is to ensure enough efficient power generation to reduce the risk of price volatility and rationing, promotes the establishment of market prices based on competition, planning and ensuring a mechanism that guarantees expansion of the transmission grid, and also allows Large Unregulated Users and Distributors to participate in the short-term market. Accordingly, the law promotes tender processes for long-term power supply contracts at firm prices in order to encourage investment in efficient generation and contracts with distribution companies. Distribution companies must begin the tender processes at least three years ahead of time in order to keep Regulated Users’ demand covered.

Expansion in transmission must be planned through a binding Transmission Plan drawn up by the Committee for Operation of the National Interconnected System (Comité de Operaciones del Sistema Interconectado Nacional, COES SINAC), and approved first by the OSINERGMIN and then by the Energy and Mining Ministry. There are two types of system: a) the Guaranteed Transmission System, which is paid for by the demand; and b) the Complementary Transmission System, which is financed jointly by the generation companies and by the demand.

The purpose of the COES SINAC is to coordinate operations at the lowest possible cost while ensuring a reliable system and the best use of energy resources, to plan transmission and to manage the short-term market. It is made up of generation, transmission and distribution companies and Large Unregulated Users (those with demand of 10 MW or higher) who belong to the National Interconnected Grid (Sistema Eléctrico Interconectado Nacional).

Generation companies may sell their power to: (i) Distribution companies through tender contracts or regulated bilateral contracts; (ii) Unregulated clients; and (iii) the spot market, where surplus energy is traded among generation companies. Generation companies are also paid for the firm capacity they contribute to the system, which covers the maximum demand plus a margin regardless of their dispatch.

Peru’s spot price, given the definition of its ideal marginal cost, does not necessarily reflect the costs in the system, as it does not consider the current shortages in the natural gas and electricity transport system. Furthermore, it sets a ceiling price for the market. This was established in an emergency regulation in 2008 (Emergency Decree 049 of 2008) that will remain in effect at least until October 2017 (Law No. 30513).

Decree Law No. 1221, published on September 24, 2015 amended certain aspects of the regulatory framework, among others:

• In tariff distribution, VAD (Value Added Distribution) and Internal Rate of Return (IRR) calculation will be made individually for each distribution company with more than 50,000 customers.

• The Energy and Mining Ministry (“MINEM” in its Spanish acronym) will define a Technical Responsibility Zone (ZRT) for each distributor, taking into consideration the environment of the Regions where they operate (near to concession zones). The works conducted at the ZRT shall be approved by the Distributor, and it will have priority to

The accompanying notes are an integral part of these consolidated financial statements.

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conduct them or might be subsequently transferred to them. A VAD will be recognized for investment and audited actual costs (with an upper threshold).

• Add to the VAD a charge for Technological Innovation and/or Energy Efficiency in Distribution.

• Add an adjustment factor to the VAD that encourages service quality in Distribution.

• Establish an obligation to the Distributors to assure their regulated demand for 24 months.

• Establish an obligation to the Distributor of making urban electrification or return the contribution once 40% of habitability is reached.

• Regarding the concessions, it limits to 30 years those granted through bidding processes, it establishes a requirement for a favorable report of basin management for hydro electrical generation, and the granting and expiration of concessions shall be ruled through Ministry Resolution.

• Establish general conditions for distributed generation of non-conventional renewable energy and co-generation that allows them to inject the surpluses to the distribution system without affecting the operational assurance.

Amendments to current regulations and the new regulations derived from Decree Law No. 1221 have been published throughout 2016 for future implementation.

On July 24, 2016, MINEM published Supreme Decree No. 018-2016-EM, which modified the regulations of the Electricity Concessions Law, the regulations of Electricity Transmission and the regulations for Unregulated Users of Electricity.

On July 28, 2016, MINEM published Supreme Decree No. 026-2016-EM, which approved the Regulation for the Wholesale Electricity Market (“Regulation for MME”). The main provisions of Regulation for MME include the approval of the Regulation for the Short-Term Electricity Market, the incorporation of a definition for MME, which consists of the short-term market (“MCP” in its Spanish acronym), and the mechanisms for allocating supplementary services, operational inflexibilities and peak period tariffs.

The consumers authorized to make purchases under the MCP are: (i) generators to supply their energy contracts; (ii) distributors to supply their unregulated customers up to 10% of the maximum demand; and (iii) large users to supply up to 10% of their maximum demand.

The Committee for Economic Operation of the National Interconnected System (Comité de Operación Económica del Sistema Interconectado Nacional, COES) will calculate the marginal costs of energy and the marginal costs for peak periods, and will publish daily prices on a provisional basis for transactions in the MME on its website.  Peak period tariffs will be allocated to participants based on established mechanisms. Participants will provide guarantees of their payment obligations in the MME and COES will incorporate measures for non-compliance of payments by participants.

Non-Conventional Renewable Energy

- In Brazil, ANEEL holds auctions by technology considering the expansion plan set by the Empresa de Pesquisa Energética (“EPE”), the planning agency; so that the target amount set for non-conventional renewable energy capacity is met.

- In Colombia, Law No. 1.715 was enacted in 2014, which created a legal framework for the development of non-conventional renewable energy, in which guidelines for declarations of public interest, as well as tax, tariff and accounting incentives were established. As part of the implementation, the Ministry of Mines and Energy enacted Decree No. 2.469 in 2014, establishing guidelines for energy policy on supply of self-generation surpluses. Likewise, the Energy and Gas Regulatory Commission (“CREG”) issued Resolution No. 24/2015, regulating high-scale self-generation activity, and the Mining Energy Planning Unit (“UPME”) issued Resolution No. 281/2015, establishing the limit for low-scale (equal to 1MW) self-generation. In addition, the CREG issued Resolution Nos. 11 and 212 in 2015, encouraging mechanisms to act in response of the demand.

The Ministry of Mines and Energy issued Law Decree No. 1.623 in 2015 that established guidelines on zone expansion policies, and Law Decree No. 2.143 that outlined the application of fiscal and tax incentives established in Law No. 1715. In 2016, the UPME issued Resolution No. 45/2016, establishing procedures for the request of certificates to support Sources of Non-Conventional Energy’s (FNCE in its Spanish acronym) projects and to obtain the list of goods and services exempted from duties or value added tax (“VAT”).

In 2016, the Ministry of Environment and Sustainable Development (Ministerio de Ambiente y Desarrollo Sostenible, MADS) issued Resolution No. 1.283, which establishes the procedures and requirements for obtaining environmental

The accompanying notes are an integral part of these consolidated financial statements.

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certifications for new investments in projects for sources of non-conventional energy and the efficient management of energy, in order to obtain the tax benefits specified in Articles 11, 12, 13 and 14 of Law No. 1.715. Likewise, MADS issued Resolution No. 1.312/2016 that establishes referral terms for preparing Environmental Impact Study’s required for environmental licenses for sources of wind energy projects.

- In Peru, a target of 5% has been set as the Non-Conventional Renewable Energy (“NCRE”) share in the country’s energy system. It is a nonbinding target and the regulatory agency, OSINERGMIN, holds differential quota tenders by technology and limited prices to help reach the goal.

On February 12, 2016, the Fourth Tender of Energy Supply with Renewable Energy Resources (“RER” in its Spanish acronym) for the National Interconnected Electricity System (“SEIN” in its Spanish acronym) was carried out. The tender was awarded to thirteen projects consisting of two biomass plants, two solar plants, three wind plants and six hydroelectrical plants, and will add 430.1 MW to the SEIN. The projects must be operational in 2020. The tariffs per MWh awarded were: US$ 77 for biomass; US$ 37 for wind; US$ 48 for solar; and US$ 46 for hydro.

- In Argentina, on October 21, 2015, Law No. 27,191 for Renewable Energy was published, replacing current Law No. 26,190. The new regulation postpones reaching a 8% share in the national demand of energy with renewable sources for generation to December 2017 and establishes a second stage goal of reaching a 20% share in 2025 by establishing mid-objectives of 12%, 16% and 18% for the years ended 2019, 2021, and 2023. The enacted law creates a Fiduciary Fund (“FODER”) to finance works, grant tax benefits for renewable energy projects and establish exemptions for specific taxes and national, provincial and municipality royalties until December 31, 2025. The customers categorized as Large Users (>300 Kw) will comply on an individual basis with the renewable share goals, establishing that the price of contracts will not exceed US$ 113 per MWh, and setting sanctions for those not fulfilling the goals.

On March 30, 2016, Decree No. 531/16 was published and established the following formalities for the implementation of Law No. 27,191:

• The Ministry of Energy and Mining (“MEyM” in its Spanish acronym) is the regulator authority.

• Generators/traders are allowed to enter into contracts requesting a demand equal to or more than 300 KW or with distribution companies acting on their behalf.

• CAMMESA will call public tenders to supply consumers with a demand of less than 300 KW.

• All CAMMESA’s purchases are guaranteed by the Fiduciary Fund (“FODER”).

• The FODER will be financed with funds from the Treasury and a specific fee will be applied to the demand supplied by CAMMESA.

• The energy goals must be fulfilled with renewable energy generated from power plants within the country.

• To use the tax benefits, it is necessary to have an authorized certificate of inclusion within the renewable energy regime.

The MEyM, CAMMESA and the Executive Committee will be responsible for establishing the methodology for determining fines for the non-compliance of goals, the use of the Fiduciary Fund (FODER) and tender specifications.

Resolution Nos. 71/2016 and 72/2016, both issued on May 17, 2016, as part of the implementation of Law No. 27,191 and Decree No531/16, began the process of public tenders for contracts within the Wholesale Electricity Market of renewable energy under the so called “Programa RenovAr – Ronda 1” with a total requirement of 1,000 MW distributed as: Wind: 600 MW; Solar: 300 MW; Biomass: 65 MW; Mini-hydro: 20 MW; and Biogas: 15 MW.  

The tender is structured with a maximum price for technology as established by the government. CAMMESA is the buyer of the energy with prices in US$ per MW (without indexation) and contracts for a 20-year term.

A total of 123 offers with an aggregate 6,366 MW participated in the tender, of which 105 complied with the specifications (42 wind energy offers, totaling 2,870 MW; 50 solar energy offers, totaling 2,305 MW; 8 biomass and biogas energy offers, totaling 23 MW and 5 micro-hydro offers, totaling 11 MW. On September 30, 2016, after reviewing the economic offers, the results indicated that most of the offers were below the Maximum Tender Price established by the MEyM. The minimum price for wind energy was US$ 49 per MWh and US$ 59 per MWh for solar energy.

Subsequently, a new tender (“Ronda 1.5”) was carried out for Programa RenovAr, which awarded 30 projects with a total of 1,281.5 MW at an average price of US$ 54 per MWh (765.4 MW wind and 516.2 MW solar). Finally, Programa RenovAr (Ronda 1 and 1.5) awarded 59 projects with a total of 2,423.5 MW at a weighted average price of US$ 57.44 per MWh.

The accompanying notes are an integral part of these consolidated financial statements.

F-55

Limits on integration and concentration

In general, all of the countries have legislation in effect that defends free competition and, together with specific regulations that apply to the electricity market, defines criteria to avoid certain levels of economic concentration and/or abusive market practices.

In principle, the regulators allow the participation of companies in different activities (e.g. generation, distribution, and commercialization) as long as there is an adequate separation of each activity, for both accounting and company purposes. Nevertheless, most of the restrictions imposed involve the transmission sector mainly due to its nature and to the need to guarantee adequate access to all agents. In Argentina and Colombia, there are specific restrictions if generation or distribution companies want to become majority shareholders in transmission companies.

Regarding concentration in a specific sector, in Argentina, there are no specific limits that affect the vertical or horizontal integration of a company. In Peru, integration is subject to the authorization of the Instituto Nacional de Defensa de la Competencia y Protección de la Propiedad Intelectual (“INDECOPI”), an antitrust authority that is able to establish commercial conduct. In Colombia, no company may have a direct or indirect market share of over 25% in electricity sale activities, although two criteria have been established for generating activity. One of these relates to participation limits depending on market concentration (HHI) and the size of the players according to their Firm Energy, and the other relates to pivotally conditions in the market depending on the availability of resources to meet system demand. In addition, Colombian companies created after the Public Service Law was enacted in 1994, can only engage in activities that complement generation/sales and distribution/sales. Finally, in Brazil, with the changes taking place in the power industry under Law 10,848/2004 and Decree 5,163/2004, the ANEEL gradually perfected regulations, eliminating concentration limits as no longer compatible with the prevailing regulatory environment. However, regulatory approval is required for consolidations or mergers to take place between players operating within the same business segment.

Market for unregulated customers

In all of the countries where the Group operates, distributing companies can supply their customers under regulated or freely-agreed conditions. The supply limitations imposed on the unregulated market are as follows:

Country	kW threshold
Argentina	> 30 kW
Brazil	> 3,000 kW or > 500 kW (1)
Colombia	> 100 kW or 55 MWh-month
Peru	> 200 kW (2)

(1) The >500 kW limit applies if energy is purchased from renewable sources, for which the government provides incentives through a discount on tolls.

(2) On July 24, 2016, Supreme Decree No. 018-016-EM established that: (i) the demand of customers that can choose between regulated and unregulated markets (those clients with a demand between 200 kW and 2,500 kW) is measured by each point of supply; (ii) regulated customers whose demand is over 2,500 kW, will remain as regulated customers for one year; and (iii) customers whose demand at each point of supply is more than 2,500 kW are classified as unregulated customers.

b) Tariff Revisions:

General Aspects

In the countries where the Group operates, selling prices charged to clients are based on the purchase price paid to generators plus a component associated with the value added in distribution. Regulators set this value periodically through reviews of distribution tariffs. As a result, distribution is essentially a regulated activity.

Argentina

In Argentina, the first review of Edesur’s tariffs scheduled for 2001 was cancelled by the authorities due to the country’s economic and financial crisis, and tariffs were frozen starting with that year. Edesur’s tariff restructuring started in 2007 with the enforcement of the “Acta Acuerdo,” or Agreement Act. The last tariff adjustment made to date went into effect in 2008 (with a positive effect on the added value distribution, or VAD), when tariffs were adjusted for inflation (applying the cost monitoring mechanism, or MMC, provided for in the Agreement Act).

The accompanying notes are an integral part of these consolidated financial statements.

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In November 2012, ENRE passed Resolution No. 347 authorizing a fixed charge to be added on invoices which differs for various categories of customers. This charge will finance infrastructure works and corrective maintenance through a trust (FOCEDE). Additionally, in July 2012, the ENRE appointed an observer in Edesur; the appointment is still in effect, although this does not imply loss of control of the company.

SE Resolution No. 250/13 was published in May 2013 authorizing compensation for Edesur’s debt corresponding to revenues originating from the application of the Program for the Rational Use of Electricity (PUREE) until February 2013, with a credit in its favor from recognition of the MMC for the six-month periods between May 2007 and February 2013. In addition, the SE Resolution No. 250/13 instructed CAMMESA to issue in Edesur’s favor what are termed as Sales Settlements with Unspecified Due Dates for values exceeding the compensation mentioned above, and authorized CAMMESA to receive these settlements as partial payment of Edesur’s debt.

Subsequently, SE Resolution No. 250/13 was supplemented and extended to December 2014 by SE Nos. 6852, 4012, 486 and 1136. The financial effects of this compensation positively affected net income for the company. The Integral Tariff Review (“RTI” in its Spanish acronym) to adjust Edesur’s revenues to its costs and obligations was provided for in the Renegotiation Agreement Act.

On March 11, 2015, the Secretary of Energy issued Resolution No. 32/2015, which among other things: (i) approved a transitory revenue increase for Edesur as of February 1, 2015 to pay for the energy acquired from the electricity market, salaries and assets and services supply; such increase, on account of the Integral Tariff Review (RTI), arose from the difference between a theoretical tariff framework and the tariff framework in force for each category of user, according to the calculations of the Ente Nacional Regulador de la Electricidad (“ENRE”), and will not be converted into a tariff, but instead will be satisfied with transfers from CAMMESA to Edesur with Argentine National Government funds; (ii) provided that as of February 1, 2015, the funds from the Program for Rational Use of Electric Energy (“PUREE”) will be considered part of Edesur revenues, also on account of the RTI; (iii) confirmed the procedure for the Cost Monitoring Mechanism (“MMC”) through January 31, 2015; and (iv) instructed CAMMESA to issue LVFVD in amounts determined by ENRE as a result of higher salary costs for Edesur due to the application of Resolution No. 836/2014 of the Secretary of Labor. In addition, Resolution No. 32/2015 allowed payment plans to be defined for the payment of remaining balances with the Wholesale Electricity Market (“MEM”) and instructed ENRE to initiate actions prior to the RTI process. As a consequence of the above, during the year ended December 31, 2015, revenues of Ch$ 352,108 million were recognized, which are presented in the statement of comprehensive income as follows: for point (i), Ch$ 264,987 million under “Other operating income” and Ch$ 644 million under “Financial income”; for point (ii), Ch$ 33,972 million under “Revenues” (Energy Sales); for point (iii) Ch$ 11,551 million  under “Other operating income”; and for point (iv), Ch$ 40,953 million under “Other operating income”.

Although SE Resolution No. 32/2015 represented the first step towards an improvement in the economic situation of Edesur, it anticipates that investments will still be financed with mutual loans with CAMMESA. Mechanisms for the payment of remaining balances with MEM are still pending, as well as, revenue updates from increases in operational costs. On the other hand, tariffs have remained frozen since 2008.

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

In following with those instructions, on January 27, 2016, MEyM Resolution No. 6 was published, which approved the Summer Quarterly Re-Scheduling (February 2016 – April 2017) tariffs for the Wholesale Electricity Market that are determined based on the “Procedures to Schedule the Operations, Dispatch of Generation Units and Pricing”. The tariffs consider a reduction in tariff subsidies and differentiate pricing schemes for those residential customers saving energy, and a new social tariff. This resolution is a significant step in the process of reconstructing the payment chain in the electric market.

In addition, on January 28, 2016, MEyM Resolution No. 7 applicable specifically to Edesur S.A. and Edenor S.A. was published, instructing the ENRE to adjust, through the Integral Tariff Review (“RTI”), the value added from distribution (“VAD”) in the tariff tables for energy distribution companies, by using the Transition Tariff Regime. MEyM Resolution No. 7 further instructed that a social tariff be applied instead of PUREE to the population of consumers falling under the criteria defined by the resolution. Finally, the resolution instructed that all necessary procedures be carried out to apply the RTI to energy distribution companies before December 31, 2016.

The accompanying notes are an integral part of these consolidated financial statements.

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On January 29, 2016, ENRE issued Resolution Nos. 1 and 2 to return to Law No. 24,065 and normalize the electricity sector that was claimed by Edesur’s representatives multiple times. Resolution No. 1 established the new tariff table to be applied to each type of customer as of February 1, 2016 and in accordance with the guidelines of MEyM Resolution No. 7/2016, as well as, the new rules on supplying for streamlining with monthly invoicing. Resolution No. 2 terminated FOCEDE, which was created on January 31, 2012, and created a new mechanism for funds collected through Resolution No. 347/12 that are now deposited to a bank account authorized by the Argentine Central Bank instead of a fiduciary fund.

On April 5, 2016, the Secretary of Energy issued Resolution Nos. 54 and 55. Resolution No. 54 approved the tender specifications expected to be granted on May 27, 2016, for contracting an advisor for the RTI of Edesur and Edenor. Resolution No. 55 approved the RTI program for 2016, which defined the criteria and methodology that Edesur must follow to perform its tariff studies. To prepare tariff proposals, the ENRE defined target quality parameters and the managing criteria to be used by Edesur, as well as the internal rate of return to be used in the calculation of their distribution cost.

On August 8, 2016, as part of the tariff renegotiation process, ENRE issued Resolution No. 463/2016, establishing the quality parameters for technical services and the value of costs for non-supplied energy required to complete the RTI.

Likewise, on August 29, 2016, ENRE issued Resolution No. 492/2016, establishing the quality parameters for commercial services and technical products. This resolution contains economic parameters for compliance with terms and time reductions for re-establishing energy supplies.

On August 30, 2016, ENRE stated that the Internal Rate of Return would be 12.46% pre-tax and 8.10% after tax.

Edesur submitted reports requested under ENRE Resolution No. 55/2016. On September 1, 2016, it submitted the reports “Red Ideal” and “Plan de Inversiones Plurianuales”, and on September 6, 2016, it submitted reports related to the basis and criteria for (i) operating costs; (ii) requirements for revenues and tariff calculations; (iii) tariff structure and transferring of costs to wholesale consumers; (iv) the mechanism for updating its own distribution costs; and (v) results and its economic-financial model.

On September 28, 2016, ENRE through Resolution No. 522/2016, summoned a public audience for a hearing on October 28, 2016, to notify and allow comments on tariff proposals presented by distribution companies for the next five-year period.

On December 30, 2016, ENRE issued Resolution No. 626, which approved the document titled “Final Resolution Public Audience” (Resolución Final Audiencia Pública, in Spanish) prior to defining the tariffs to be applied. Likewise, it transferred to the MINEM’s Undersecretary for Coordination of Tariff Policy (Subsecretaría de Coordinación de Política Tarifaria in Spanish) the topics discussed at the hearing that fall within the purview of that regulatory body.

On February 1, 2017, ENRE issued Resolution No. 64/2017, which finalized the RTI process.

In connection with the new tariff structure and charges, MEyM instructed ENRE to limit the VAD increase as a result of the RTI process to be applied as of February 1, 2017 to 42% as compared to the VAD currently in effect. The application of the remaining VAD increase would be made in two stages: the first stage in November 2017 and the second stage in February 2018.  In addition, it instructed ENRE to compensate Edesur S.A. and Edenor S.A. for the difference in VAD as a result of the gradual application of the tariff increases in the RTI, in 48 installments beginning on February 1, 2018, which will be incorporated to the VAD determined on that date.

The new regulation also sets the method for updating the revenues of distribution companies based on fluctuations in economic prices, and all other matters related to service quality and supply requirements.

Upon setting the distribution tariff tables, including the instruction of the MEyM, and the provisions of SEE Resolution No. 20/2017 on seasonal prices from invoicing effective February 1, 2017, the temporary tariff stage of Edesur and the Agreement Act were finalized. Consequently, Edesur will be ruled by the terms stated in its concession contract.

Brazil

In Brazil, there are three types of tariff adjustments: i) Ordinary Tariff Reviews (“RTO”) which are conducted periodically in accordance with the provisions in the concession contracts (in Coelce every 4 years and in Ampla every 5 years); (ii) Annual Adjustments (“IRT”) since Brazil, unlike other countries, does not automatically index its tariffs to inflation; and (iii) Extraordinary Reviews (“RTE”) when important events have occurred that may affect the financial situation of the distributors.

The accompanying notes are an integral part of these consolidated financial statements.

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In September 2012, the government approved Temporary Measure 579, one purpose of which was to reduce certain electricity tariff taxes and special charges paid by the final user, which will be paid in the future with the state budget. In January 2013, the Temporary Measure became Law 12,783, giving rise to Extraordinary Tariff Reviews that resulted in tariffs dropping an average of 18% throughout the country. This reduction affected Ampla and Coelce from the end of January 2012 to April 2013 (when the respective annual readjustments went into effect).

In April 2014, ANEEL finalized its periodic tariff review of Ampla for the 2014-2019 period with retrospective effect on March 15, 2014.

On March 1, 2015, through Resolution No. 1858/2015, Coelce had an extraordinary review when its rate increased by 10.28% for purposes of face the increases in charges (Energy Development Account - CDE) and the costs of energy purchase.

The last periodic tariff review of Coelce was made in 2015 (the first of our distribution companies using the new fourth tariff cycle technology) for the 2015 – 2019 period, effective beginning on April 22, 2015. Such review was provisional as the methodologies of tariff review were not approved in time. The additional average increase in tariffs was 11.69% as approved under Resolution No. 1882/2015.

Ampla will begin to use the fourth tariff cycle methodology in its tariff review in March 2019; however, in March 2015 it has a final average increase of 37.3% (Resolution No. 1869/2015) essentially due to increases in Section A.

Finally, still in the scope of the fourth tariff cycle, on November 17, 2015, Chapter 2.3 of the Tariff Review Procedures related to the determination of the Basis for Remuneration was approved, under which a Database of Referential Prices was created to value certain variables of the basis for remuneration in the upcoming tariff reviews.

ANEEL approved the results of the first periodic review of Enel Cien S.A. (formerly named CIEN S.A.). Beginning on July 1, 2015, the tariffs were adjusted to negative 7.49%, as approved by Resolution No. 1902/2015.

On March 8, 2016, ANEEL approved the tariff adjustment of Ampla. Beginning on March 15, 2016, the tariffs were adjusted to positive 7.38% for all of Ampla’s customers (7.15% for low voltage consumers and 7.89% for high voltage consumers).

ANEEL, through Resolution No. 2.061 dated April 12, 2016, approved the final results of the fourth periodic tariff review (“RTP”) of Coelce, which were included in the 2016 adjustments.

ANEEL, through Resolution No. 2.065 dated April 19, 2016, approved the energy tariffs of Coelce as a result of the 2016 tariff adjustments. The average increase in tariffs to consumers was 12.97%.

Colombia

The Energy and Gas Regulatory Commission (Comisión de Regulación de Energía y Gas - CREG) is the entity that defines the method by which distribution networks are paid. Distribution charges are reviewed every five years and updated monthly according to the Producer Price Index (“PPI”). Currently, these charges include the new replacement value of all operational assets, the Administration, Operation and Maintenance (“AOM”) and non-electrical assets used in the distribution business.

In Colombia, the current distribution charges for Codensa were published by CREG in October 2009.

The current review of regulated distribution charges began in 2013 with the publication of the assumptions for the remuneration methodology proposed by CREG Resolution No. 43 dated 2013. These assumptions were complemented by the development of the Purposes and Guidelines for Compensation of the Distribution Activity for the period 2015-2019 in CREG Resolution No. 79 dated 2014.

In February 2015, CREG issued a proposal for Resolution No. 179 of 2014, which proposed a methodology for remunerating distribution activity. The methodology is based on a regulated revenue scheme. Annual revenues are determined using a Regulated Net Assets Basis (“BRA”) and a rate of return (to be defined in separate resolution). Also, it included an annual revenue for incentives to investments and expenditures efficiency and quality improvements.

Additionally, the Regulatory Commission issued CREG Resolution No. 95 dated 2015, which defined a method for calculating the regulated remuneration tariff (“WACC”) for electricity transmission and distribution, as well as for natural gas transportation and distribution.

The accompanying notes are an integral part of these consolidated financial statements.

F-59

In March and November 2016, CREG through Resolution No. 24, proposed a new method for calculating the regulated remuneration tariff. The proposal retained the application of the depreciated value of the assets, and proposed a new factor for residual value based on the date the assets were placed in operations and historical inventories, and also proposed a factor based on monthly revenues.

In connection with the regulated selling charge, in January 2015, CREG issued Resolution No. 180 of 2014, which defined the methodology for calculating regulated selling charges. The approval of a new basis for selling cost for Codensa was made in December 2015 through CREG Resolution Nos. 120 and 191.

In February 2016, CREG issued Resolution No. 240B project, which proposed a new tariff pricing formula. The methodology (i) stated a pricing formula that incorporated time-of-use, bi-lateral contracts and future contracts, (ii) defined rules for unregulated consumers supplied by the specific agent, and (iii) introduced a new component called “AJ” as a mitigating factor for non-recurrent fluctuations in the unit cost of rendering services. Finally, in accordance with CREG Resolution No. 98/2016, the Commission released the 2017 agenda, which noted that the final resolution and tariff pricing formula applicable to all users would be published in the first quarter of 2017.

Peru

In Peru, a process takes place every four years to determine the value added from distribution (“VAD”), using a “model company” methodology for a typical area. In October 2013, OSINERGMIN issued Resolution No. 203/2013 setting distribution tariffs from November 2013 to October 2017 for Enel Distribución Peru S.A. (formerly named Edelnor), which were subsequently extended  until October 31, 2018 through Resolution No. 530-2016-MEM/DM of the Ministry of Energy and Mining.

The accompanying notes are an integral part of these consolidated financial statements.

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5. NON-CURRENT ASSETS OR DISPOSAL GROUPS HELD FOR SALE OR HELD FOR DISTRIBUTION TO OWNERS AND DISCONTINUED OPERATIONS

5.1 Corporate Reorganization

I. Background

On April 28, 2015, the Company informed the superintendence of Securities and Insurance (hereinafter “SVS”) through a significant event notice, that its Board of Directors decided by unanimous vote to initiate an analysis of a corporate reorganization (the “reorganization”) aimed at separating the activities of generation and distribution of electricity in Chile from activities outside of Chile. The objective was to resolve certain duplications and redundancies arising from Enersis S.A.’s complex corporate structure and generate value for all its shareholders, while maintaining its inclusion in the Enel S.p.A. group.

The Spin-Off stage of the Reorganization process was carried out as follows:

The Reorganization began with the spin-offs of Enersis S.A. (“Enersis”) and its subsidiaries, Empresa Nacional de Electricidad S.A. (“Endesa Chile”) and Chilectra S.A. (“Chilectra”).

Each of Endesa Chile and Chilectra effected spin-offs of their non-Chilean businesses and related assets and liabilities, resulting in the formation of Chilectra Américas S.A. (“Chilectra Américas”) as a separate new company from Chilectra and the formation of Endesa Américas S.A. (“Endesa Américas”) as a separate new company from Endesa Chile, which were allocated the equity interests and related assets and liabilities of Chilectra’s and Endesa Chile’s businesses outside of Chile, respectively. After the spin-offs, the continuing companies, Chilectra and Endesa Chile, retained the equity interests and related assets and liabilities of Chilectra’s and Endesa Chile’s businesses in Chile, respectively.

Following the Endesa Chile and Chilectra spin-offs, Enersis effected a spin-off of its Chilean businesses and related assets and liabilities, resulting in the formation of Enersis Chile S.A. (“Enersis Chile”) as a separate new company from Enersis, which was allocated the equity interests and related assets and liabilities of Enersis’ businesses in Chile, including the equity interests in each of Chilectra and Endesa Chile (after the spin-offs of these entities as discussed above). After the spin-off, the continuing company, Enersis, was renamed “Enersis Américas S.A.” and retained the equity interests and related assets and liabilities of Enersis’ businesses outside of Chile, including the businesses, assets and liabilities held by each of the new companies, Chilectra Américas and Endesa Américas that were created as a result of the spin-offs by Chilectra and Endesa Chile.

On March 1, 2016, upon having satisfied all conditions precedent, including a capital decrease and modifications to the by-laws, the separation of the Chilean and non-Chilean businesses of Enersis, Endesa Chile and Chilectra became effective. Consequently, the new company Enersis Chile became the holding entity of the businesses carried out by Endesa Chile and Chilectra, and the surviving company Enersis Américas S.A. (“Enersis Américas”) became the holding entity of the non-Chilean businesses carried out by Endesa Américas and Chilectra Américas.

On October 4, 2016, the corporate name changes of Enersis Chile, Endesa Chile and Chilectra to Enel Chile S.A., Enel Generación Chile S.A., and Enel Distribución Chile S.A., respectively, were approved at the respective Extraordinary Shareholders’ Meetings. The corporate name changes became effective on October 18, 2016 through modifications to the by-laws of each of these entities.

The Merger stage of the Reorganization process was carried out as follows:

On September 28, 2016, the respective shareholders of Enersis Américas, Endesa Américas and Chilectra Américas met, voted and approved by more than two-thirds of the outstanding voting shares of each company, the merger of Endesa Américas and Chilectra Américas with and into Enersis Américas, with Enersis Américas continuing as the surviving company under the new name “Enel Américas S.A.” (the “Merger”). On December 1, 2016, the Merger was completed, and Enersis Américas (the “Surviving Company”) absorbed Endesa Américas and Chilectra Américas by incorporation, each of which was then dissolved without liquidation, and the Surviving Company assumed all their rights and obligations.

Enel Américas S.A. will continue to have its shares publicly traded and listed in Chile on the Chilean Stock Exchanges and its ADSs traded on the NYSE. In the Merger, the shares and ADSs of Endesa Américas and the shares of Chilectra Américas were converted into shares and ADSs of Enel Américas, as applicable, and Endesa Américas and Chilectra Américas shares ceased trading on the Chilean Stock Exchanges, and Endesa Américas ADSs ceased trading on the NYSE.

For more detailed information on the merger stage of the corporate restructuring process and its effects on the issued capital and other equity items, refer to Note 24.1.1.

The accompanying notes are an integral part of these consolidated financial statements.

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II. Accounting Aspects

As of December 31, 2015, upon compliance with the criteria in IFRS 5 Non-Current Assets Held for Sale and Discontinued Operations, the following accounting treatment was applied:

i. Assets and liabilities

All assets and liabilities related to the generation and distribution businesses in Chile were classified as non-current assets or disposal groups held for distribution to owners and as liabilities associated with disposal groups held for distribution to owners, in accordance with the criteria described in Note 3.j.

The accompanying notes are an integral part of these consolidated financial statements.

F-62

The following table sets forth the assets and liabilities related to the operations in Chile that have been classified as held for distribution to owners as of March 1, 2016, effective date of the Company’s spin-off, and December 31, 2015:

	03-01-2016	12-31-2015
	ThCh$	ThCh$
ASSETS
CURRENT ASSETS
Cash and cash equivalents	161,018,932	144,261,845
Other current financial assets	568,475	16,313,194
Other current non-financial assets	5,815,999	3,984,943
Trade and other current receivables	583,273,636	596,364,468
Current accounts receivable from related companies	32,782,254	23,611,569
Inventories	42,865,038	42,616,615
Current tax assets	27,567,612	20,306,212
TOTAL CURRENT ASSETS	853,891,946	847,458,846
NON-CURRENT ASSETS
Other non-current financial assets	25,145,235	21,750,452
Other non-current non-financial assets	5,631,227	4,769,885
Trade and other non-current receivables	14,550,780	14,392,223
Investments accounted for using the equity method	32,780,878	45,716,371
Intangible assets other than goodwill	42,372,945	42,879,326
Goodwill	887,257,655	887,257,655
Property, plant and equipment	3,444,874,361	3,429,167,797
Investment property	8,152,496	8,150,987
Deferred tax assets	21,513,079	22,392,339
TOTAL NON-CURRENT ASSETS	4,482,278,656	4,476,477,035
TOTAL ASSETS	5,336,170,602	5,323,935,881
CURRENT LIABILITIES
Other current financial liabilities	27,396,476	27,921,725
Trade and other current payables	512,636,625	554,915,972
Current accounts payable to related companies	59,888,535	55,238,930
Other current provisions	9,265,833	16,329,195
Current tax liabilities	20,652,997	15,119,789
Other current non-financial liabilities	9,168,651	6,120,658
TOTAL CURRENT LIABILITIES	639,009,117	675,646,269
NON-CURRENT LIABILITIES
Other non-current financial liabilities	905,387,924	917,197,790
Other non-current payables	4,883,177	6,034,216
Non-current accounts payable to related companies	251,527	97,186
Other non-current provisions	56,116,139	56,116,140
Deferred tax liabilities	238,227,605	235,101,356
Non-current provisions for employee benefits	55,697,489	55,023,456
Other non-current non-financial liabilities	435,673	435,689
TOTAL NON-CURRENT LIABILITIES	1,260,999,534	1,270,005,833
TOTAL LIABILITIES	1,900,008,651	1,945,652,102

The accompanying notes are an integral part of these consolidated financial statements.

F-63

ii. Accumulated Other Comprehensive Income in Net Equity

The accumulated other comprehensive income balance related to assets and liabilities held for distribution to owners were the following:

Reserves originated from	03-01-2016	12-31-2015
	ThCh$	ThCh$
Exchange differences on translation	10,192,702	11,328,513
Cash flow hedges	(112,912,093)	(120,517,197)
Gains on remeasuring available-for-sale financial instruments	14,841	14,835
Other miscellaneous reserves	(553,646)	7,736,853
Total	(103,258,196)	(101,436,996)

iii. Revenue and expenses

All revenues and expenses related to the generation and distribution businesses in Chile recognized until the effective date of the spin-off of the Company were classified as discontinued operations and presented under the caption “Income after tax from discontinued operations” in the consolidated statement of comprehensive income.

The following table sets forth the breakdown by nature of the line item “Income after tax from discontinued operations” for the two month period ended February 29, 2016 and the years ended December 31, 2015 and 2014:

Statement of Income	02-29-2016	12-31-2015	12-31-2014
	ThCh$	ThCh$	ThCh$
		13
Revenues	402,810,199	2,382,671,016	2,013,305,145
Other operating income	2,561,433	14,735,951	34,201,387
Total Revenue and Other Operating Income	405,371,632	2,397,406,967	2,047,506,532
Raw materials and consumables used	(236,672,086)	(1,481,985,559)	(1,309,402,283)
Contribution Margin	168,699,546	915,421,408	738,104,249
Other work performed by the entity and capitalized	3,367,108	21,004,053	21,505,568
Employee benefits expense	(16,099,065)	(136,554,721)	(126,341,363)
Depreciation and amortization expense	-	(153,201,662)	(128,437,154)
Reversal of impairment loss (impairment losses) recognized in profit or loss	(968,888)	3,054,903	(13,185,420)
Other expenses	(16,591,065)	(125,849,781)	(110,321,349)
Operating income	138,407,636	523,874,200	381,324,531
Other gains	-	20,055,745	70,893,263
Financial income	2,563,118	15,270,169	14,762,515
Financial costs	(8,616,990)	(61,616,349)	(59,543,956)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	1,293,725	8,905,045	(54,352,582)
Foreign currency exchange differences	(21,263)	(13,394,762)	(20,328,278)
Gains from indexed assets and liabilities	267,856	4,839,077	15,263,623
Income before taxes	133,894,082	497,933,125	348,019,116
Income tax expense, discontinued operations	(18,763,695)	(109,612,599)	(132,687,135)
NET INCOME FROM DISCONTINUED OPERATIONS	115,130,387	388,320,526	215,331,981

Due to classification of generation and distribution of energy activities in Chile as discontinued operations, those lines of business are not included in Note 32 “Information by segment.”

The accompanying notes are an integral part of these consolidated financial statements.

F-64

The following table sets forth the breakdown by nature of total comprehensive income from discontinued operations for the two month period ended February 29, 2016 and the years ended December 31, 2015 and 2014, which are part of the Consolidated Comprehensive Income by Nature for the years ended December 31, 2016, 2015 and 2014:

Statement of Comprehensive Income	02-29-2016	12-31-2015	12-31-2014
	ThCh$	ThCh$	ThCh$
Net income from discontinued operations	115,130,387	388,320,526	215,331,981
Components of other comprehensive that will not be reclassified subsequently to profit or loss, net of taxes
Actuarial gains (losses) from defined benefit plans	-	(4,320,290)	(8,165,647)
Components of other comprehensive that will be reclassified subsequently to profit or loss, net of taxes
Foreign currency translation gains (losses), net of tax	(1,875,159)	162,373	12,473,950
Gains (losses) from available-for-sale financial assets, net of tax	10	-	-
Share of other comprehensive income from associates and joint venture accounted for using the equity method, net of taxes	(13,822,107)	(577,862)	13,476,871
Gains (losses) from cash flow hedge, net of taxes	12,652,797	(90,724,491)	(99,770,340)
Total Other Comprehensive Income from Discontinued Operations	(3,044,459)	(95,460,270)	(81,985,166)
TOTAL COMPREHENSIVE INCOME FROM DISCONTINUED OPERATIONS	112,085,928	292,860,256	133,346,815
Comprehensive income attributable to:
Shareholders of Enel Américas	76,058,307	235,061,432	126,239,319
Non-controlling interests	36,027,621	57,798,822	7,107,496
TOTAL COMPREHENSIVE INCOME FROM DISCONTINUED OPERATIONS	112,085,928	292,860,254	133,346,815

iv. Cash flows

The following table sets for the net cash flows from operating, investing and financing activities attributable to discontinued operations for the two month period ended February 29, 2016 and the years ended December 31, 2015 and 2014:

Statement of cash flows	02-29-2016	12-31-2015	12-31-2014
	ThCh$	ThCh$	ThCh$
Net cash flows from (used in) operating activities	151,998,467	576,531,527	264,946,881
Net cash flows from (used in) investing activities	(46,141,505)	(296,741,342)	(188,738,471)
Net cash flows from (used in) financing activities	(88,197,076)	(273,442,450)	(159,144,481)
Net increase (decrease) in cash and cash equivalents before effect of Exchange rate changes	17,659,886	6,347,735	(82,936,071)
Effect of exchange rate changes on cash and cash equivalents	(902,799)	4,898,483	1,044,602
Net increase (decrease) in cash and cash equivalents	16,757,087	11,246,218	(81,891,469)
Cash and cash equivalents at beginning of period	144,261,845	133,015,627	214,907,097
Cash and cash equivalents at end of period	161,018,932	144,261,845	133,015,628

The accompanying notes are an integral part of these consolidated financial statements.

F-65

6. BUSINESS COMBINATION – MERGER BETWEEN CODENSA S.A. AND DISTRIBUIDORA ELECTRICA DE CUNDINAMARCA S.A. (DECSA) AND EMPRESA ELECTRICA DE CUNDINAMARCA S.A. (EEC)

On October 1, 2016, the merger between our Colombian subsidiary Codensa S.A. (“Codensa”) and Distribuidora Eléctrica de Cundinamarca S.A. (“DECSA”) and Empresa de Energía de Cundinamarca S.A. (“EEC”) was completed.

DECSA was incorporated in 2009 as a joint venture between Codensa (with a 49% ownership interest) and Empresa Eléctrica de Bogotá (with a 51% ownership interest), which in turn was the parent company of EEC (with a 82.34%  ownership interest), the energy distribution company of the Cundinamarca region.

Pursuant to the merger, Codensa absorbed by incorporation DECSA and EEC through a non-cash exchange of shares, which were then dissolved without liquidation.   The total number of shares issued by Codensa was 1,668,377 shares for a total amount of ThCh$ 23,390,629 (ThCP 105,532,468).

Consequently, the Group through its subsidiary Codensa, obtained control of DECSA and EEC. Prior to the merger, DECSA was a joint venture accounted for using the equity method.

The merger of DECSA and EEC in Codensa was accounted for using the criteria for business combination achieved in stages as described in Note 2.7.1.

From an operational view, this transaction will provide synergies and higher scale economies as a merged company, which will lead to improved operations with increased reliability and better quality of service. It will also allow for a more coordinated expansion of the distribution network within the region, ensuring a more effective and competitive structure to face the challenges of the industry.

If the acquisition had taken place on January 1, 2016, it is estimated that consolidated revenues would have increased by ThCh$ 65,341,964 and the consolidated net income would have increased by ThCh$ 2,423,521.  Prior to the merger, Codensa and EEC were considered two independent CGUs, however, during the merger process, the regulator “integrated the markets” by request, therefore, both businesses became a single market served by a merged Codensa under the same tariff.

The functional currency of the acquired entities was the Colombian Peso (CP). The Group has translated the initial effects of the business combination to its presentation currency using the exchange rate at the acquisition date. At the end of each reporting period, the financial statements of Codensa are translated using the accounting principles described in Note 2.7.3.

a) Consideration transferred

The consideration transferred corresponds to the equity instruments issued by Codensa that were exchanged with the other shareholders of DECSA and EEC, considering the following share exchange ratio:

Number of shares prior to the merger	132,093,274
Number of new shares issued	1,668,377
Number of shares after the merger	133,761,651
Increase in ownership interest	1.247%
	ThCh$
Fair value of Codensa (1)	1,875,423,238
Fair value of consideration transferred	23,390,629

(1) The fair value of Codensa was determined through a “fairness opinion” prepared by Banco BBVA of Colombia. The fair value was adjusted for the dividends distributed from September 1 to December 31, 2014 whose payment was made in 2016.

b) Acquisition-related costs

Codensa incurred costs of ThCh$238,400 for financial advisory fees related to the merger process. These cost were recognized under “Other expenses” in the consolidated statement of comprehensive income for the year ended December 31, 2016.

The accompanying notes are an integral part of these consolidated financial statements.

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c) Identifiable assets acquired and identifiable liabilities assumed

The following table summarizes the recognized assets acquired and liabilities assumed in connection to the acquisition:

Identifiable net assets acquired	Fair Value
	ThCh$
Cash and cash equivalents	6,127,946
Trade and other receivables (1)	12,751,001
Accounts receivable to related parties	1,502,225
Inventories	1,608,438
Property, plant and equipment	93,511,064
Intangible assets other than goodwill	411,784
Other non-financial assets	663,441
Current tax assets	3,507,502
Deferred tax assets	17,662,826
Other financial liabilities	(28,483,692)
Trade and other payables	(12,939,218)
Accounts payable to related parties	(1,062,825)
Provisions for employee benefits	(20,554,698)
Other provisions (2)	(8,124,519)
Current tax liabilities	(2,989,013)
Deferred tax liabilities	(16,368,227)
Total	47,224,035

(1) The gross amount of trade and other receivables was ThCh$ 13,252,618, of which ThCh$ 290,777 is expected to be uncollectible.

(2) A contingent liability has been recognized at the acquisition date for expected tax and legal contingencies for a total fair value amount of ThCh$ 4,397,771.

Given the nature of DECSA and EEC’s business and assets, the fair value of assets acquired and liabilities assumed was measured using the following valuation approaches:

(i) The market approach using the comparison method, based on quoted market prices for identical or comparable items when available.

(ii) The cost approach or depreciated replacement cost, which reflects adjustments for physical deterioration and functional and operational obsolescence.

(iii) The income approach, which uses valuation techniques that convert future amounts (such as cash flows or income and expenses) into a single present value amount (that is, discounted). The fair value measurement reflects current market expectations for those future amounts.

Reconciliation of value

Finally, the fair values were determined from an assessment and reconciliation of the results obtained from the methods selected, based on the nature of each asset acquired and liability assumed.

The accompanying notes are an integral part of these consolidated financial statements.

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d) Bargain purchase

The business combination resulted in the recognition of a bargain purchase due to the fair value of the assets acquired and liabilities assumed exceeding the total fair value of the consideration transferred and the fair value of the pre-existing interest in the acquiree, as follows:

	ThCh$
Consideration transferred	23,390,629
Fair value of pre-existing interest in the acquiree	19,124,743
Fair value of identifiable net assets acquired	(47,224,035)
Bargain purchase	(4,708,663)

The bargain purchase was recognized in the “Other gains (losses)” line item in the consolidated statement of comprehensive income for the year ended December 31, 2016 (see Note 30).

e) Remeasurement of pre-existing interest and currency translation differences

The remeasurement of the fair value of Codensa’s pre-existing interest in DECSA and EEC resulted in a loss of ThCh$ 11,556,684. The loss recognized was the negative difference between the acquisition-date fair value of the pre-existing interest in DECSA and EEC and its carrying amount.

In addition, the exchange differences on translation of the pre-existing interest accumulated in the equity of the Group until the date of obtaining control, were reclassified to profit or loss, resulting in a loss of ThCh$ 2,456,619.

Both amounts were recognized in the “Other gains (losses)” line item in the consolidated statement of comprehensive income for the year ended December 31, 2016 (see Note 30).

The accompanying notes are an integral part of these consolidated financial statements.

F-68

7. CASH AND CASH EQUIVALENTS

a) The detail of cash and cash equivalents as of December 31, 2016 and 2015, is as follows:

Cash and Cash Equivalents	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Cash balances	1,375,922	7,718,308
Bank balances	413,804,373	194,453,214
Time deposits	1,166,207,164	573,985,007
Other fixed-income instruments	219,122,838	409,006,815
Total	1,800,510,297	1,185,163,344

Time deposits have a maturity of three months or less from their date of acquisition and accrue the market interest for this type of short-term investment. Other fixed-income investments are mainly comprised of resale agreements maturing in 90 days or less from the date of investment. There are no restrictions for significant amounts of cash availability.

b) The detail of cash and cash equivalents by currency is as follows:

Currency	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Chilean peso	633,810,173	835,468,993
Argentine peso	143,806,314	44,883,600
Colombian peso	274,980,582	156,731,922
Brazilian real	199,097,354	91,204,686
Peruvian soles	101,652,919	34,749,661
U.S. dollar	447,162,955	22,124,482
Total	1,800,510,297	1,185,163,344

c) The following table shows a reconciliation of cash and cash equivalents presented in the statement of financial position with cash and cash equivalents in the cash flow statement as of December 31, 2016 and 2015:

	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Cash and cash equivalents (statement of financial position)	1,800,510,297	1,185,163,344
Cash and cash equivalents attributable to assets held for distribution to owners (*)	-	144,261,845
Cash and cash equivalents (statement of cash flows)	1,800,510,297	1,329,425,189

(*)  See Note 5.1.II.i).

d) The following amounts have been received from the sale of shares in subsidiaries:

Loss of Control at Subsidiaries	12-31-2016	12-31-2015
	ThCh$	ThCh$
Amounts received for the sale of subsidiaries(*)	-	25,000,000
Amounts in cash and cash equivalents in entities sold	-	(18,360,347)
Total, net	-	6,639,653

e) Other outflows of cash classified as financing activities:

	For the years ended December 31,
Other Payments from Financing Activities	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Cash and cash equivalents allocated to Enel Chile (1)	(161,018,932)	-	-
Payment for swap derivative transactions	(83,595,247)	(3,060,551)	(122,137,140)
Other miscellaneous itemized payments for financing activities	(73,130,619)	(16,861,164)	(23,303,192)
Total other payments from financing activities	(317,744,798)	(19,921,715)	(145,440,332)

(1) On March 1, 2016, as a result of the completion of the Company’s spin-off (see Note 5.1), cash and cash equivalent balances were transferred to the Enel Chile Group. This amount corresponds to a portion of the balance, which at that date, was held by the Company plus all of the cash and cash equivalent balances of the Chilean subsidiaries. This item has been classified as financing cash outflows since it is akin to the payment of dividends to shareholders.

The accompanying notes are an integral part of these consolidated financial statements.

F-69

e) The following table sets forth the components of “Other payments for operating activities” line item in the Statement of Cash Flows:

	For the years ended December 31,
Other Payments from Operating Activities	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Payment for other taxes (VAT, ICMS, PIS/COFINS, Sales taxes, Custom taxes, taxes on bank transfers) (1)	(830,568,886)	(809,173,431)	(739,417,209)
Payments for collections made under Codensa Hogar contract  (2)	(306,234,566)	(353,788,383)	(398,758,158)
Payments for the Energy Development Account (CDE) (3)	(168,950,353)	(112,994,353)	(12,365,211)
Other miscellaneous itemized payments for operating activities (4)	(259,004,269)	(296,851,010)	(267,556,444)
Total other payments from operating activities	(1,564,758,074)	(1,572,807,177)	(1,418,097,022)

1. The main elements of payments for other taxes are related to:

• ICMS is a Brazilian state value added tax (VAT) on the circulation of goods, telecommunication and transportation services. The ICMS payments were ThCh$ 579,888,468, ThCh$ 515,723,919 and ThCh$ 463,311,271 for the years ended December 31, 2016, 2015 and 2014, respectively.

• PIS/COFINS taxes. In Brazil, the “Programa de Integração Social” (PIS) is a social contribution tax, payable by corporations, targeted to finance the payment of unemployment insurance and allowance for low paid workers, while the “Contribuição para o Financiamento da Seguridade Social” (COFINS) is a federal contribution tax, based on gross revenues of business sales. The total amounts paid for PIS/COFINS were ThCh$ 137,330,605, ThCh$ 137,511,696, and ThCh$ 91,073,163 for the years ended December 31, 2016, 2015 and 2014.

• Municipality property taxes in Brazil mainly related to the Company’s public lighting network. The payments were ThCh$ 0, ThCh$ 34,164,970, and ThCh$ 75,758,644 for the years ended December 31, 2016, 2015 and 2014, respectively.

• Payment for taxes on sales in Peru for ThCh$ 59,561,466, ThCh$50,560,335 and ThCh$49,818,650 for the years ended December 31, 2016, 2015 and 2014, respectively.

2. Our Colombian subsidiary Codensa entered into an arrangement with a third party that develops a business with Codensa’s customers. By virtue of this arrangement, Codensa manages the collection of that third party’s receivables, since they are billed as part of the Codensa’s invoices issued monthly. The payments are related to the monthly collected amounts under the collection management contract, whereas the collections are presented in the line item “Other collections from operating activities”.

3. In Brazil, Law No. 10,438/2002 created the “Conta de Desenvolvimento Energético” (“CDE”). The CDE is a government fund that aims to promote the development of alternative energy sources, promote globalization of energy services and subsidizes low-income residential customers. The fund is financed through charges included in consumers and generators tariffs and government contributions.

4. Other miscellaneous aggregate payments for operating activities includes several types of individually non-significant payments related to operating activities.

The accompanying notes are an integral part of these consolidated financial statements.

F-70

8. OTHER FINANCIAL ASSETS

The detail of other financial assets as of December 31, 2016 and 2015, is as follows:

Other Financial Assets (*)	Balance as of
	Currrent		Non-Current
	12-31-2016	12-31-2015	12-31-2016	12-31-2015
	ThCh$	ThCh$	ThCh$	ThCh$
Available-for-sale financial investments — unquoted equity securities or with limited liquidity	-	-	1,277,058	616,296
Available-for-sale financial investments IFRIC 12 (2)	-	-	687,458,647	487,893,679
Financial assets held to maturity (1)	25,201,114	27,195,496	36,272	39,673
Hedging derivatives	173,106	1,172,125	-	978,556
Financial assets at fair value through profit or loss (1)	44,019,453	35,467,539	320,461	-
Non-hedging derivatives	21,825,932	4,427,286	-	-
Total	91,219,605	68,262,446	689,092,438	489,528,204

(*) See Note 20.1.a

(1) The amounts included in “financial assets held to maturity” and “financial assets at fair value through profit or loss” correspond mainly to time deposits and other highly liquid investments that are readily convertible to cash and subject to a low risk of changes in value, but that do not fulfill the definition of cash equivalent as defined in Note 3.f.2 (e.g. with maturity over 90 days from time of investment).

(2) On September 11, 2012, the Brazilian government issued Temporary Law No. 579, which became permanent on January 13, 2013 and directly affects companies holding electric power generation, transmission, and distribution concessions, including Ampla and Coelce. Among its provisions, this legislation establishes that the government, as concession grantor, will use the Valor Nuevo de Reemplazo (VNR, New Replacement Value) to make the corresponding indemnity payments to the concessionaires for those assets that have not been amortized at the end of the concession period. Every month the distributors adjust the book value of the financial asset, by calculating the present value of estimated cash flows, using the effective interest rate on the corresponding payment at the end of the concession.

As a result of this new development, the subsidiaries have changed how they measure and classify the amounts they expect to recover in compensation at the end of the concession term. The previous approach was based on the historic cost of the investments, and the rights to compensation were recorded as an account receivable. Currently, they are measured on the basis of the VNR, and the compensation rights are classified as financial assets available for sale (see Note 3.f).

The accompanying notes are an integral part of these consolidated financial statements.

F-71

9. TRADE AND OTHER RECEIVABLES

a) The detail of trade and other receivables as of December 31, 2016 and 2015, is as follows:

Trade and Other Receivables, Gross	Balance as of
	Current		Non-Current
	12-31-2016	12-31-2015	12-31-2016	12-31-2015
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, gross	1,209,432,144	1,194,381,502	373,496,513	398,695,864
Trade receivables, gross	999,426,442	859,695,602	77,366,903	82,274,666
Other receivables, gross (1)	210,005,702	334,685,900	296,129,610	316,421,198
Trade and Other Receivables, Net	Balance as of
	Current		Non-Current
	12-31-2016	12-31-2015	12-31-2016	12-31-2015
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, net	1,030,219,227	1,088,131,567	359,647,596	398,695,864
Trade receivables, net	823,076,565	754,571,268	63,517,986	82,274,666
Other receivables, net (1)	207,142,662	333,560,299	296,129,610	316,421,198

(1) Includes as of December 31, 2016, mainly accounts receivable related to loans and advances to employees for ThCh$14,134,595 (ThCh$14,081,204 as of December 31, 2015); SE Resolution No. 32/2015 (applicable in Argentina) for ThCh$0 (ThCh$ ThCh$28,174,339 as of December 31, 2015) (see Note 4); Recoverable taxes (VAT) of ThCh$45,773,288 (ThCh$62,451,442 as of December 31, 2015); and Accounts receivable at our Brazilian subsidiaries Ampla and Coelce, following the signing in 2014 of the addendum to the concession contracts where the outstanding assets are recoverable and/or can be offset in subsequent tariff periods for ThCh$18,566,742 (ThCh$150,798,761 as of December 31, 2015), which are guaranteed by the Brazilian government; a receivable to “low income” consumers for ThCh$123,304,720 (ThCh$83,800,187 as of December 31, 2015) to which a social discount is applied determining a “low income” final tariff, where the Brazilian government replenish such discount to our subsidiaries Ampla and Coelce through a state subsidy; and receivables related to the VOSA project in Argentina for ThCh232,754,724 (ThCh$237,424,900 as of December 31, 2015) (see Note 33.5).

There are no significant trade and other receivables balances held by the Group that are not available for its use.

The Group does not have customers to which it has sales representing 10% or more of its operating revenue for the years ended December 31, 2016, 2015 and 2014.

Refer to Note 10.1 for detailed information on amounts, terms and conditions associated with accounts receivable from related companies.

b) As of December 31, 2016 and 2015, the balance of past due but not impaired trade receivables is as follows:

Trade Receivables Past Due But Not Impaired	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Less than three months	160,365,020	117,895,535
Between three and six months	19,087,106	25,783,187
Between six and twelve months	17,366,632	28,220,570
More than twelve months	15,993,840	7,034,592
Total	212,812,598	178,933,884

The accompanying notes are an integral part of these consolidated financial statements.

F-72

c) The reconciliation of changes in the allowance for impairment of trade receivables is as follows:

Trade Receivables Past Due and Impaired	Current and Non-Current
	ThCh$
Balance as of January 1, 2014	156,868,268
Increases (decreases) for the year (*)	22,848,140
Amounts written off	(19,013,041)
Foreign currency translation differences	1,637,619
Balance as of December 31, 2014	162,340,986
Increases (decreases) for the year (*)	46,890,017
Amounts written off	(23,480,578)
Foreign currency translation differences	(43,623,000)
Transfer to assets held for distribution to owners	(35,877,490)
Balance as of December 31, 2015	106,249,935
Increases (decreases) for the year (*)	88,751,534
Amounts written off	(51,706,932)
Foreign currency translation differences	44,094,918
Other movements	5,672,379
Balance as of December 31, 2016	193,061,834

(*) The increase in the allowance for impairment of trade receivables, related to continuing operations of the Group, was ThCh$88,751,534, ThCh$46,890,017 and ThCh$ 22,848,140 for the years ended December 31, 2016, 2015 and 2014, respectively (see Note 28).

Write-offs for bad debt

Past-due debt is written off once all collection measures and legal proceedings have been exhausted and the debtors’ insolvency has been demonstrated. In our power generation business, this process normally takes at least one year of procedures for the few cases that arise in each country. In our distribution business, considering the differences in each country, the process takes at least six months in Argentina and Brazil, 12 months in Colombia and Peru, and 24 months in Chile. Overall, the risk of bad debt, and therefore the risk of writing off our trade receivables, is limited (see Notes 3.f.3 and 19.5).

d) Additional information:

- Additional statistical information required under Official Bulletin 715 of the Superintendencia de Valores y Seguros de Chile (Chilean superintendence of Securities and Insurance), of February 3, 2012 (XBRL Taxonomy). See
Appendix 6.

- Supplementary information on Trade Receivables, see Appendix 6.1.

The accompanying notes are an integral part of these consolidated financial statements.

F-73

10. BALANCES AND TRANSACTIONS WITH RELATED PARTIES

Related party transactions are performed at current market conditions.

Transactions between the Company and its subsidiaries, associates and joint ventures have been eliminated on consolidation and are not itemized in this note.

As of the date of these financial statements, no guarantees have been given or received nor has any allowance for bad or doubtful accounts been recorded with respect to receivable balances for related party transactions. The controlling shareholder of the Company is the Italian corporation Enel S.p.A.

10.1 Balances and transactions with related parties

The balances of accounts receivable and payable between the Company and its non-consolidated related companies are as follows:

a) Receivables from related companies

							Balance as of
							Current		Non-Current
Taxpayer ID N° (RUT)	Company	Country	Relationship	Currency	Description of Transaction	Term of Transaction	12-31-2016	12-31-2015	12-31-2016	12-31-2015
							ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Endesa Spain	Spain	Common Immediate Parent	CH$	Other services	More than 90 days	12,748	13,077	-	-
Foreign	Endesa Spain	Spain	Common Immediate Parent	CP	Other services	More than 90 days	-	28,628	-	-
Foreign	Endesa Spain	Spain	Common Immediate Parent	Euros	Other services	More than 90 days	-	5,833	-	-
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	CP	Other services	Less than 90 days	13,546	30,373	-	-
Foreign	Endesa Operaciones y Servicios Comerciales	Spain	Common Immediate Parent	CP	Other services	Less than 90 days	62,372	114,758	-	-
Foreign	SACME	Argentina	Associate	Ar$	Other services	Less than 90 days	32,253	42,003	240,677	355,485
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	CH$	Other services	Less than 90 days	27,765,732	-	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	CP	Other services	Less than 90 days	14,595	3,276	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Euros	Other services	Less than 90 days	888,311	931,267	-	-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	CP	Energy sales	Less than 90 days	-	553,472	-	-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	CP	Other services	Less than 90 days	-	216,682	-	-
Foreign	Endesa Generación	Spain	Common Immediate Parent	CH$	Other services	Less than 90 days	-	36,067	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	3,826	-	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named Endesa S.A.)	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	14,457	-	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named  Endesa S.A.)	Chile	Common Immediate Parent	Ar$	Other services	Less than 90 days	14,953	-	-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	360	-	-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Ar$	Other services	Less than 90 days	64,454	-	-	-
76.014-570-K	GasAtacama Chile S.A.	Chile	Common Immediate Parent	CH$	Current mercantile account	Less than 90 days	85,896	-	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile S.A.)	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	86,035	-	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile S.A.)	Chile	Common Immediate Parent	CP	Other services	Less than 90 days	874,980	-	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile S.A.)	Chile	Common Immediate Parent	Soles	Other services	Less than 90 days	2,266	-	-	-
Foreign	Enel S.p.A.	Italy	Parent	CH$	Other services	Less than 90 days	-	99,972	-	-
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	36,279	145,858	-	-
Foreign	Enel S.p.A.	Italy	Parent	CP	Other services	Less than 90 days	220,142	116,940	-	-
96.806.130-5	Empresa Eléctrica de Colina Ltda.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	29	-	-	-
Foreign	Enel Green Power Cristal Eólica	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	405	343	-	-
Foreign	Enel Green Power Emiliana Eolica Sa	Brazil	Common Immediate Parent	Real	Energy sales	Less than 90 days	37,129	460	-	-
Foreign	Enel Green Power Emiliana Eolica Sa	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	552	-	-	-
Foreign	Enel Green Power Joana Eolica Sa	Brazil	Common Immediate Parent	Real	Energy sales	Less than 90 days	26,905	460	-	-
Foreign	Enel Green Power Joana Eolica Sa	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	552	-	-	-
Foreign	Enel Green Power Modelo I Eolica SA	Brazil	Common Immediate Parent	Real	Energy sales	Less than 90 days	57,039	538	-	-
Foreign	Enel Green Power Modelo I Eolica SA	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	642	-	-	-
Foreign	Enel Green Power Modelo II Eolica SA	Brazil	Common Immediate Parent	Real	Energy sales	Less than 90 days	38,205	469	-	-
Foreign	Enel Green Power Modelo II Eolica SA	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	561	-	-	-
Foreign	Enel Green Power Primavera Eolica	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	407	344	-	-
Foreign	Enel Green Power SAO Judas Eolica	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	406	341	-	-
Foreign	Enel Green Power Tacaicó Eólica Sa	Brazil	Common Immediate Parent	Real	Energy sales	Less than 90 days	17,757	263	-	-
Foreign	Enel Green Power Tacaicó Eólica Sa	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	321	-	-	-
Foreign	Enel Green Power Pedra Do Gerônimo Eólic	Brazil	Common Immediate Parent	Real	Energy sales	Less than 90 days	44,662	429	-	-
Foreign	Enel Green Power Pedra Do Gerônimo Eólic	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	507	-	-	-
Foreign	Enel Green Power Pau Ferro Eólica Sa	Brazil	Common Immediate Parent	Real	Energy sales	Less than 90 days	47,353	429	-	-
Foreign	Enel Green Power Pau Ferro Eólica Sa	Brazil	Common Immediate Parent	Real	Tolls	Less than 90 days	512	-	-	-
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	CH$	Other services	Less than 90 days	-	15,306	-	-
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	CP	Other services	Less than 90 days	22,609		-
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	Soles	Other services	Less than 90 days	6,490		-
Foreign	Enel Green Power Colombia	Colombia	Common Immediate Parent	CP	Other services	Less than 90 days	17,986	978,185	-	-
Foreign	Enel Green Power Participações Ltda	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	24,600	21,454	-	-
Foreign	Enel Soluções Energéticas	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	67	54	-	-
Foreign	Enel Green Power Maniçoba	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	783	626	-	-
Foreign	Enel Green Power Esperança	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	732	585	-	-
Foreign	Enel Green Power Damascena	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	783	624	-	-
Foreign	Enel Italy Servizi SRL	Italy	Common Immediate Parent	CP	Other services	Less than 90 days	-	207,814	-	-
		Total					30,541,199	3,566,930	240,677	355,485

The accompanying notes are an integral part of these consolidated financial statements.

F-74

b) Accounts payable to related companies

							Balance as of
							Current		Non-Current
Taxpayer ID N° (RUT)	Company	Country	Relationship	Currency	Description of Transaction	Term of Transaction	12-31-2016	12-31-2015	12-31-2016	12-31-2015
							ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Enel Iboeroamérica S.R.L.	Spain	Parent	Ar$	Other services	Less than 90 days	-	59,416	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	CH$	Dividends	Less than 90 days	59,528,900	29,658,243	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	CP	Other services	Less than 90 days	267,888	302,025	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Euros	Other services	Less than 90 days	1,217,413	414,397	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Real	Other services	Less than 90 days	14,432	384,082	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Ar$	Dividends	Less than 90 days	45,624	-	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Ar$	Other services	Less than 90 days	20,646	173,687	-	-
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Ar$	Current mercantile account	Less than 90 days	155,524	-	-	-
Foreign	Enel Iboeroamérica S.R.L.	Spain	Parent	CH$	Dividends	Less than 90 days	-	58,897,984	-	-
Foreign	Enel Iboeroamérica S.R.L.	Spain	Parent	CP	Other services	Less than 90 days	92,518	40,920	-	-
Foreign	SACME	Argentina	Associate	Ar$	Other services	Less than 90 days	176,952	161,015	-	-
78.932.860-9	Gas Atacama Chile	Chile	Common Immediate Parent	CH$	Dividends	Less than 90 days	193	-	-	-
78.932.860-9	Gas Atacama Chile	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	32,563	-	-	-
Foreign	Endesa Generación	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	24,636	-	-	-
Foreign	Endesa Generación	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	-	28,617	-	-
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	CP	Other services	Less than 90 days	790,375	-	-	-
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	1,824,919	194,151	-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	Ar$	Current mercantile account	Less than 90 days	883,536		-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	396,278	-	-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	CP	Other services	Less than 90 days	395,889	184,373	-	-
Foreign	Enel Ingegneria e Ricerca	Italy	Common Immediate Parent	US$	Other services	Less than 90 days	248,497	-	-	-
Foreign	Enel Ingegneria e Ricerca	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	3,573,219	1,513,001	-	-
Foreign	Enel Ingegneria e Ricerca	Italy	Common Immediate Parent	CP	Other services	Less than 90 days	36,941	192,920	-	-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	CP	Energy purchases	Less than 90 days	-	1,121,851	-	-
Foreign	Endesa Spain	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	71,467	74,089	-	-
Foreign	Endesa Spain	Spain	Common Immediate Parent	CH$	Other services	Less than 90 days	441,971	-	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	1,294,233	-	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	CP	Other services	Less than 90 days	27,561	-	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	Real	Other services	Less than 90 days	24,295		-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named  Endesa S.A.)	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	3,837,156	-	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named  Endesa S.A.)	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	639,233	-	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named  Endesa S.A.)	Chile	Common Immediate Parent	CP	Other services	Less than 90 days	29,878	-	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named  Endesa S.A.)	Chile	Common Immediate Parent	Soles	Other services	Less than 90 days	341,948	-	-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	1,662,003	-	-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Euros	Other services	Less than 90 days	177,416		-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	399,859	-	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile S.A.)	Chile	Common Immediate Parent	CH$	Current mercantile account	Less than 90 days	519,570	-	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile S.A.)	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	486,745	-	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile S.A.)	Chile	Common Immediate Parent	Real	Other services	Less than 90 days	36,276	-	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile S.A.)	Chile	Common Immediate Parent	CP	Other services	Less than 90 days	13,278	-	-	-
Foreign	Yacylec S.A.	Argentina	Common Immediate Parent	Ar$	Other services	Less than 90 days	10,044	-	-	-
Foreign	Enel Trade S.p.A.	Italy	Common Immediate Parent	CP	Other services	Less than 90 days	101,701	-	-	-
Foreign	Enel Trade S.p.A.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	348,870	-	-	-
Foreign	Enel S.p.A.	Italy	Parent	Real	Other services	Less than 90 days	-	12,027,207	-	-
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	17,051,494	2,841,305	-	-
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	2,715,692	9,039	-	-
Foreign	Enel S.p.A.	Italy	Parent	CP	Other services	Less than 90 days	560,413	59,242	-	-
Foreign	Enel Green Power Emiliana Eolica Sa	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	266,092	152,859	-	-
Foreign	Enel Green Power Joana Eolica Sa	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	277,658	110,781	-	-
Foreign	Enel Green Power Modelo I Eolica SA	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	360,933	234,876	-	-
Foreign	Enel Green Power Modelo II Eolica SA	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	254,258	157,329	-	-
Foreign	Enel Green Power Dois Riachos SA	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	304,695	-	-	-
Foreign	Enel Green Power Tacaicó	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	189,400	72,411	-	-
Foreign	Enel Green Power Pedra Do Gerônimo Eólic	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	268,163	183,859	-	-
Foreign	Enel Green Power Pau Ferro Eólica Sa	Brazil	Common Immediate Parent	Real	Energy purchases	Less than 90 days	338,448	195,699	-	-
Foreign	ENEL Green Power Fazenda S.A.	Brazil	Common Immediate Parent	Real	Compra de Energía	Less than 90 days	152,987	-	-	-
Foreign	Cabeça de Boi	Brazil	Common Immediate Parent	Real	Compra de Energía	Less than 90 days	208,043	-	-	-
Foreign	Enel Italy Servizi SRL	Italy	Common Immediate Parent	CP	Other services	Less than 90 days	4,064,776	-	-	-
Foreign	Enel Italy Servizi SRL	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	3,780,903	82,220	-	-
Foreign	Enel Italy Servizi SRL	Italy	Common Immediate Parent	Real	Other services	Less than 90 days	42,196	-	-	-
Foreign	Enel Italy Servizi SRL	Italy	Common Immediate Parent	Soles	Other services	Less than 90 days	46,523	-	-	-
Foreign	Enel Italy Servizi SRL	Italy	Common Immediate Parent	US$	Other services	Less than 90 days	86,288	-	-	-
Foreign	Enel Green Power Desenvolvimiento Ltda.	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	328,197	286,224	-	-
Foreign	Enel Green Power Brazil	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	-	19,140	-	-
Foreign	Enel Green Power Brazil Participações Ltda	Brazil	Common Immediate Parent	Real	Other services	Less than 90 days	21,947	-	-	-
Foreign	Enel Green Power Italy	Italy	Common Immediate Parent	CP	Other services	Less than 90 days	194,486	64,546	-	-
		Total					111,704,039	109,897,508	-	-

The accompanying notes are an integral part of these consolidated financial statements.

F-75

c) Significant transactions and effects on income/expenses:

Transactions with related companies that are not consolidated and their effects on profit or loss are as follows:

Taxpayer ID N° (RUT)	Company	Country	Relatinoship	Description of Transaction	For the years ended,
					12-31-2016	12-31-2015	12-31-2014
					ThCh$	ThCh$	ThCh$
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	Other operating income	43,900	275,290	55,980
Foreign	Endesa Energía S.A.	Spain	Common Immediate Parent	Gas sales	-	14,604,841	-
Foreign	Enel Latinoamérica S.A	Spain	Common Immediate Parent	Other fixed operating expenses	(86,031)	(107,759)	(35,921)
Foreign	Endesa Generación	Spain	Common Immediate Parent	Fuel consumption	(11,478,600)	(15,030,911)	(30,318,202)
Foreign	Endesa Generación	Spain	Common Immediate Parent	Other fixed operating expenses	(26,158)	(120,896)	-
Foreign	Endesa Generación	Spain	Common Immediate Parent	Other operating income	-	-	17,157
Foreign	Endesa Generación	Spain	Common Immediate Parent	Commodity derivatives	-	(2,144,063)	(2,521,138)
76.418.940-k	GNL Chile S.A. (*)	Chile	Associate	Gas consumption	(13,704,410)	(123,964,573)	(114,115,041)
76.418.940-k	GNL Chile S.A. (*)	Chile	Associate	Gas transportation	(8,923,783)	(52,195,582)	(39,638,398)
76.418.940-k	GNL Chile S.A. (*)	Chile	Associate	Other services rendered	-	54,377	56,042
76.418.940-k	GNL Chile S.A. (*)	Chile	Associate	Other financial income	1,103	81,749	58,169
76.788.080-4	GNL Quintero S.A. (*)	Chile	Associate	Energy sales	444,523	3,260,734	2,671,120
76.788.080-4	GNL Quintero S.A. (*)	Chile	Associate	Tolls	(150,802)	151,088	47,263
76.788.080-4	GNL Quintero S.A. (*)	Chile	Associate	Other services rendered	-	650,390	956,854
76.788.080-4	GNL Quintero S.A.	Chile	Associate	Other fixed operating expenses	(37,162)	-	-
Foreign	SACME	Argentina	Associate	Ousourced services	(1,648,727)	(1,969,563)	(1,407,349)
96.880.800-1	Empresa Eléctrica Puyehue S.A. (*)	Chile	Common Immediate Parent	Energy purchasess	-	-	(3,805)
96.880.800-1	Empresa Eléctrica Puyehue S.A. (*)	Chile	Common Immediate Parent	Tolls	-	-	(12,399)
96.880.800-1	Empresa Eléctrica Puyehue S.A. (*)	Chile	Common Immediate Parent	Energy sales	-	-	34,253
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Energy purchasess	(1,484,096)	(10,600,564)	(10,113,496)
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Tolls	(42,756)	(292,198)	(260,495)
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Other services rendered	59,824	392,312	197,812
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (*)	Chile	Common Immediate Parent	Energy sales	131,409	286,833	942,615
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Other fixed operating expenses	(820,620)	(1,175,297)	(2,860,930)
Foreign	Enel Iberoamérica S.R.L	Spain	Parent	Other operating income	2,745	3,491	-
96.806.130-5	Electrogas S.A. (*)	Chile	Associate	Tolls	(885,381)	(3,296,956)	(3,409,581)
96.806.130-5	Electrogas S.A. (*)	Chile	Associate	Fuel consumption	174,832	(952,044)	(434,289)
Foreign	Endesa Operaciones y Servicios	Spain	Common Immediate Parent	Other operating income	156,531	172,728	163,226
Foreign	PH Chucas Costa Rica	Costa Rica	Common Immediate Parent	Other services rendered	-	1,188,564	-
Foreign	Enel Ingegneria e Ricerca	Italy	Common Immediate Parent	Other services rendered	6,074	35,773	33,970
Foreign	Enel Ingegneria e Ricerca	Italy	Common Immediate Parent	Other fixed operating expenses	(1,681,705)	(2,241,294)	(708,903)
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Energy sales	6,153,924	4,263,174	3,250,149
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Other operating income	16,794	-	-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Other services rendered	2,217,663	2,951,317	3,142,758
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Other fixed operating expenses	(4,575)	-	-
Foreign	Empresa de Energía de Cundinamarca S.A.	Colombia	Joint Venture	Tolls	(1,302,137)	(1,725,582)	(1,731,368)
76.652.400-1	Centrales Hidroeléctricas De Aysén S.A. (*)	Chile	Joint Venture	Other financial income	-	-	23,891
76.652.400-1	Centrales Hidroeléctricas De Aysén S.A. (*)	Chile	Joint Venture	Other services rendered	-	(9,322)	-
76.014.570-K	Inversiones GasAtacama Holding Ltda. (1) (*)	Chile	Joint Venture	Energy purchasess	-	-	(3,322,616)
76.014.570-K	Inversiones GasAtacama Holding Ltda. (1) (*)	Chile	Joint Venture	Gas transportation	-	-	(7,764,442)
76.014.570-K	Inversiones GasAtacama Holding Ltda. (1) (*)	Chile	Joint Venture	Energy sales	-	-	1,858,318
76.014.570-K	Inversiones GasAtacama Holding Ltda. (1) (*)	Chile	Joint Venture	Other financial income	-	-	229,609
76.014.570-K	Inversiones GasAtacama Holding Ltda. (1) (*)	Chile	Joint Venture	Other fixed operating expenses	-	-	(5,487)
77.017.930-0	Transmisora Eléctrica de Quillota Ltda. (*)	Chile	Joint Venture	Tolls	(245,968)	(1,473,974)	(1,378,743)
Foreign	Endesa Spain	Spain	Common Immediate Parent	Other operating income	-	36,266	57,623
Foreign	Endesa Spain	Spain	Common Immediate Parent	Other fixed operating expenses	(114,835)	(174,638)	-
Foreign	Compañía Energetica Veracruz S.A.C.	Perú	Common Immediate Parent	Other services rendered	-	-	3,022
Foreign	Enel Trade S.p.A	Italy	Common Immediate Parent	Other operating income	48,233	-	3,222
Foreign	Enel Trade S.p.A	Italy	Common Immediate Parent	Other fixed operating expenses	(554,814)	(216,437)	-
Foreign	Enel Trade S.p.A	Italy	Common Immediate Parent	Commodity derivatives	-	(833,366)	-
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Energy purchasess	(817,159)	(3,264,764)	-
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Tolls	(40,520)	(153,929)	-
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Other services rendered	35,765	109,891	-
76.321.458-3	Sociedad Almeyda Solar Spa (*)	Chile	Common Immediate Parent	Energy sales	34,820	87,062	-
76.052.206-6	Parque Eolico Valle de los Vientos S.A. (*)	Chile	Common Immediate Parent	Energy purchasess	(2,809,400)	(14,929,463)	-
76.052.206-6	Parque Eolico Valle de los Vientos S.A. (*)	Chile	Common Immediate Parent	Energy sales	139,003	670,035	-
Foreign	Enel S.p.A.	Italy	Parent	Other fixed operating expenses	(12,363,147)	(13,567,378)	-
Foreign	Enel S.p.A.	Italy	Parent	Other fixed operating expenses	-	(72,057)	-
Foreign	Enel S.p.A.	Italy	Parent	Other operating income	103,453	124,626	-
Foreign	Enel Italy	Italy	Common Immediate Parent	Other fixed operating expenses	(4,138,401)	(168,463)	-
76.179.024-2	Parque Eolico Tal Tal S.A. (*)	Chile	Common Immediate Parent	Energy purchasess	(4,382,025)	(26,456,188)	-
76.179.024-2	Parque Eolico Tal Tal S.A. (*)	Chile	Common Immediate Parent	Energy sales	25,545	217,448	-
Foreign	Quatiara Energia S.A.	Brazil	Common Immediate Parent	Energy purchasess	-	(65,275)	-
Foreign	Quatiara Energia S.A.	Brazil	Common Immediate Parent	Energy sales	10	-	-
Foreign	Enel Green Power Cristal Eolica	Brazil	Common Immediate Parent	Other services rendered	4,502	5,404	-
Foreign	Enel Green Power SAO Judas Eolica	Brazil	Common Immediate Parent	Other services rendered	4,482	5,380	-
Foreign	Enel Green Power Primavera Eolica	Brazil	Common Immediate Parent	Other services rendered	4,524	5,430	-
Foreign	Enel Green Power Emiliana Eolica Sa	Brazil	Common Immediate Parent	Energy purchases	(2,724,697)	(1,982,654)	-
Foreign	Enel Green Power Emiliana Eolica Sa	Brazil	Common Immediate Parent	Other services rendered	24,565	7,802	-
Foreign	Enel Green Power Emiliana Eolica Sa	Brazil	Common Immediate Parent	Energy sales	404,251	-	-
Foreign	Enel Green Power Joana Eolica Sa	Brazil	Common Immediate Parent	Energy purchases	(2,469,660)	(1,463,855)	-
Foreign	Enel Green Power Joana Eolica Sa	Brazil	Common Immediate Parent	Other services rendered	19,122	7,208	-
Foreign	Enel Green Power Joana Eolica Sa	Brazil	Common Immediate Parent	Energy sales	292,935	-	-
Foreign	Enel Green Power Pau Ferro Eólica Sa	Brazil	Common Immediate Parent	Energy purchases	(3,479,754)	(2,397,927)	-
Foreign	Enel Green Power Pau Ferro Eólica Sa	Brazil	Common Immediate Parent	Other services rendered	23,085	3,523	-
Foreign	Enel Green Power Pau Ferro Eólica Sa	Brazil	Common Immediate Parent	Energy sales	515,566	-	-
Foreign	Enel Green Power Pedra Do Gerônimo Eólic	Brazil	Common Immediate Parent	Energy purchases	(3,007,765)	(2,313,314)	-
Foreign	Enel Green Power Pedra Do Gerônimo Eólic	Brazil	Common Immediate Parent	Other services rendered	12,728	3,461	-
Foreign	Enel Green Power Pedra Do Gerônimo Eólic	Brazil	Common Immediate Parent	Energy sales	486,273	-	-
Foreign	Enel Green Power Tacaicó Eólica Sa	Brazil	Common Immediate Parent	Energy purchases	(1,674,660)	(910,249)	-
Foreign	Enel Green Power Tacaicó Eólica Sa	Brazil	Common Immediate Parent	Other services rendered	7,892	2,124	-
Foreign	Enel Green Power Tacaicó Eólica Sa	Brazil	Common Immediate Parent	Energy sales	193,337	-	-
Foreign	Enel Green Power Modelo I Eolica SA	Brazil	Common Immediate Parent	Energy purchases	(3,582,111)	(2,978,980)	-
Foreign	Enel Green Power Modelo I Eolica SA	Brazil	Common Immediate Parent	Other services rendered	38,312	7,114	-
Foreign	Enel Green Power Modelo I Eolica SA	Brazil	Common Immediate Parent	Energy sales	621,023	-	-
Foreign	Enel Green Power Modelo II Eolica SA	Brazil	Common Immediate Parent	Energy purchases	(2,474,407)	(1,997,894)	-
Foreign	Enel Green Power Modelo II Eolica SA	Brazil	Common Immediate Parent	Other services rendered	24,698	6,218	-
Foreign	Enel Green Power Modelo II Eolica SA	Brazil	Common Immediate Parent	Energy sales	415,968	-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	Other fixed operating expenses	(329,251)	(403,404)	-
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	Mexico	Common Immediate Parent	Other services rendered	13,155	16,312	-
Foreign	Enel Green Power Italy	Italy	Common Immediate Parent	Other fixed operating expenses	(129,828)	(68,787)	-
Foreign	Enel Green Power Damascena S.A.	Brazil	Common Immediate Parent	Other services rendered	8,475	2,723	-
Foreign	Enel Green Power Esperança S.A.	Brazil	Common Immediate Parent	Other services rendered	7,922	2,545	-
Foreign	Enel Green Power Maniçoba S.A.	Brazil	Common Immediate Parent	Other services rendered	8,475	2,723	-
Foreign	Enel Solucoes Energeticas Ltda	Brazil	Common Immediate Parent	Other services rendered	726	298	-
Foreign	Enel Green Power Dois Riachos Eolica S.A.	Brazil	Common Immediate Parent	Energy purchases	(3,397,915)	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	Sales of spare parts	3,519,163	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	Other fixed operating expenses	(177,484)	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	Other financial income	33,090	-	-
96.800.570-7	Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	Chile	Common Immediate Parent	Other services rendered	(12,790)	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named Endesa S.A.)	Chile	Common Immediate Parent	Other financial income	1,043,354	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named Endesa S.A.)	Chile	Common Immediate Parent	Other services rendered	52,306	-	-
91.081.000-6	Enel Generación Chile S.A. (formerly named Endesa S.A.)	Chile	Common Immediate Parent	Other fixed operating expenses	(2,869,927)	-	-
76.003.204-3	Eolica Canela	Chile	Common Immediate Parent	Other services rendered	215	-	-
96.770.940-9	Celta	Chile	Common Immediate Parent	Other fixed operating expenses	(404,827)	-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Other operating income	53,146	-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Other services rendered	86,404	-	-
76.107.186-6	Servicios Informáticos e Inmobiliarios Ltda.	Chile	Common Immediate Parent	Other fixed operating expenses	(2,285,984)	-	-
76.788.080-4	Gas Atacama Chile	Chile	Common Immediate Parent	Other services rendered	141	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile)	Chile	Common Immediate Parent	Other financial expenses	(331,579)	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile)	Chile	Common Immediate Parent	Other services rendered	2,869,931	-	-
76.536.353-5	Enel Chile S.A. (formerly named Enersis Chile)	Chile	Common Immediate Parent	Other fixed operating expenses	(5,446,579)	-	-
Foreign	Yacylec	Argentina	Associate	Other services rendered	10,113	12,886	-
Foreign	Yacylec	Argentina	Associate	Other services rendered	(101,652)	(122,237)	-
Foreign	Enel Green Power Paranapanema S.A	Brazil	Common Immediate Parent	Energy purchases	(376,972)	-	-
Foreign	Enel Distribuzione	Italy	Common Immediate Parent	Other fixed operating expenses	(63,353)	-	-
Foreign	Enel Green Power Mourao S.A.	Brazil	Common Immediate Parent	Energy purchases	(120,014)	-	-
76.126.507-5	Parque Eolico Talinay Oriente SA (*)	Chile	Common Immediate Parent	Energy sales	39,708	153,158	-
76.126.507-5	Parque Eolico Talinay Oriente SA (*)	Chile	Common Immediate Parent	Energy purchases	(101,565)	(505,404)	(5,141,912)
Foreign	Enel Green Power Cabeca de Boi SA	Brazil	Common Immediate Parent	Energy purchases	(712,595)	-	-
Foreign	Enel Green Power Cabeca de Boi SA	Brazil	Common Immediate Parent	Energy sales	502,687	-	-
Foreign	Enel Green Power Fazenda SA	Brazil	Common Immediate Parent	Energy purchases	(651,000)	-	-
Foreign	Enel Green Power Fazenda SA	Brazil	Common Immediate Parent	Energy sales	226,342	-	-
				Total	(83,304,814)	(262,484,943)	(211,381,462)

(*) For the years ended December 31, 2016, 2015 and 2014, the effects on profit or loss of the transactions with related companies in Chile have been classified as discontinued operations in the consolidated statement of comprehensive income. See Note 5.1.

The accompanying notes are an integral part of these consolidated financial statements.

F-76

Transfers of short-term funds between related companies are treated as current accounts changes, with variable interest rates based on market conditions used for the monthly balance. The resulting amounts receivable or payable are usually at 30 days term, with automatic rollover for the same periods and amortization in line with cash flows.

10.2 Board of directors and key management personnel

The Company is managed by a Board of Directors which consists of seven members. Each director serves for a three-year term after which they can be reelected.

The Board of Directors as of December 31, 2016, was elected at the Ordinary Shareholders Meeting held on April 28, 2016, which is composed of the following members:

Mr. Francisco de Borja Acha Besga

Mr. José Antonio Vargas Lleras

Mr. Livio Gallo

Mr. Enrico Viale

Mr. Hernán Somerville Senn

Mr. Patricio Gómez Sabaini

Mr. Domingo Cruzat Amunátegui

At the Board of Directors’ meeting held on April 29, 2016, Mr. Francisco de Borja Acha Besga was appointed as Chairman of the Board, Mr. José Antonio Vargas Lleras was appointed as Vice Chairman of the Board and Mr. Domingo Cruzat Amunátegui was appointed as Secretary of the Board.

Likewise, at the same Board of Directors Meeting, the Directors’ Committee was elected under the requirements of Law No. 18,046 on Corporations and the Sarbanes Oxley Act. The Directors’ Committee is composed of the following independent directors: Mr. Hernán Sommerville Senn (as Chairman), Mr. Patricio Gómez Sabaini and Mr. Domingo Cruzat Amunátegui (as Secretary).

The Board of Directors appointed Mr. Hernan Sommerville Senn as financial expert for the Directors’ Committee of the Company.

a) Accounts receivable and payable and other transactions

• Accounts receivable and payable

There are no outstanding amounts receivable or payable between the Company and the members of the Board of Directors and key management personnel.

• Other transactions

No transactions other than the payment of compensations have taken place between the Company and the members of the Board of Directors and key management personnel and other than transactions in the normal course of business-electricity supply.

b) Compensation for directors

In accordance with Article 33 of Law No. 18,046 governing stock corporations, the compensation of Directors is established each year at the Ordinary Shareholders Meeting of the Company.

The compensation consists of paying a variable annual compensation equal to one one-thousandth of the profit for the year (attributable to shareholders of Enel Américas). Also, each member of the Board of Directors will be paid a monthly compensation, one part a fixed monthly fee and another part dependent on meetings attended. The breakdown of this compensation is as follows:

- 180 UF as a fixed monthly fee, and

- 66 UF as per diem for each Board meeting attended.

The amounts paid for the monthly fee will be treated as payment in advance of the variable annual compensation described above. As stated in the by-laws, the compensation for the Chairman of the Board will be twice that of a Director, and the compensation of the Vice Chairman will be 50% higher than that of a Director.

The accompanying notes are an integral part of these consolidated financial statements.

F-77

Any advance payments received will be deducted from the annual variable compensation, with no reimbursement if the annual variable compensation is lower than the total amount paid in advances. The variable compensation will be paid, when appropriate, after the Ordinary Shareholders’ Meeting approves the Annual Report, Balance Sheet and Financial Statements, and the Independent Auditors’ Reports and Account Inspectors’ Reports for the year ended December 31, 2016.

If any Director of the Company is a member of more than one Board in any Chilean or foreign subsidiaries and/or associates, or holds the position of Director or advisor in other Chilean or foreign companies or legal entities in which the Company has a direct or indirect ownership interest, that Director can be compensated for his/her participation in only one of those Boards or Management Committees.

The Executive Officers of the Company and/or any of its Chilean or foreign subsidiaries or associates will not receive any compensation or per diem if they hold the position of Director in any of the Chilean or foreign subsidiaries or associates of the Company. Nevertheless, the executives may receive such compensation or per diem, provided there is prior express authorization, as a payment in advance of the variable portion of their compensation received from the respective companies through which they are employed.

Directors’ Committee:

Each member of the Directors’ Committee will receive a variable compensation equal to 0.11765 thousandth of the profit for the year (attributable to shareholders of Enel Américas). Also each member will be paid a monthly compensation, one part in a fixed monthly fee and another part dependent on meetings attended.

This compensation is broken down as follows:

- 60.00 UF as a fixed monthly fee, and

- 22.00 UF as per diem for each Board meeting attended.

The amounts paid for the monthly fee will be treated as payment in advance of the variable annual compensation described above.

Any advance payments received will be deducted from the annual variable compensation, with no reimbursement if the annual variable compensation is lower than the total amount paid in advances. The variable compensation will be paid, when appropriate, after the Ordinary Shareholders’ Meeting approves the Annual Report, Balance Sheet and Financial Statements, and the Independent Auditors’ Reports and Account Inspectors’ Reports for the year ended December 31, 2016.

The following tables show details of the compensation paid to the members of the Board of Directors of the Company for the years ended December 31, 2016, 2015 and 2014:

Taxpayer ID No. (RUT)	Name	Position	December 31, 2016
			Period in position	Enel Américas Board ThCh$	Board of Subsidiaries ThCh$	Directors' Committee ThCh$
Foreigner	Francisco de Borja Acha Besga (1)	Chairman	January - December 2016	-	-	-
Foreigner	José Antonio Vargas Lleras (2)	Vice Chairman	May - December 2016	-	-	-
Foreigner	Francesco Starace	Vice Chairman	January - April 2016	-	-	-
4.975.992-4	Herman Chadwick Piñera	Director	January - April 2016	25,349	-	8,445
Foreigner	Enrico Viale (4)	Director	May - December 2016	-	-	-
Foreigner	Livio Gallo (3)	Director	May - December 2016	-	-	-
6.429.250-1	Rafael Fernández Morandé	Director	January - April 2016	25,349	-	8,445
4.132.185-7	Hernán Somerville Senn	Director	January - December 2016	92,362	-	30,783
Foreigner	Patricio Gómez Sabaini (5)	Director	May - December 2016	71,676	-	23,892
6.989.304-K	Domingo Cruzat Amunátegui (6)	Director	May - December 2016	71,676	-	23,892
Foreigner	Alberto de Paoli	Director	January - April 2016	-	-	-
Foreigner	Francesca Di Carlo	Director	January - April 2016	-	-	-
	TOTAL			286,412	-	95,457

The accompanying notes are an integral part of these consolidated financial statements.

F-78

Taxpayer ID No. (RUT)	Name	Position	December 31, 2015
			Period in position	Enel Américas Board ThCh$	Board of Subsidiaries ThCh$	Directors' Committee ThCh$
Foreigner	Francisco de Borja Acha Besga	Chairman	June - December 2015	-	-	-
5.710.967-K	Pablo Yrarrázaval Valdés	Chairman	Year 2014	20,184	-	-
6.243.657-3	Jorge Rosenblut Ratinoff	Chairman	January - June 2015	77,861	-	-
Foreigner	Francesco Starace	ViceChairman	June - December 2015	-	-	-
Foreigner	Borja Prado Eulate	ViceChairman	January - April 2015	45,292	-	-
7.052.890-8	Carolina Schmidt Zaldivar	Director	January - June 2015	33,532	-	8,745
4.975.992-4	Herman Chadwick Piñera	Director	June - December 2015	53,679	-	21,428
6.429.250-1	Rafael Fernández Morandé	Director	January - December 2015	97,303	-	36,914
4.132.185-7	Hernán Somerville Senn	Director	January - December 2015	95,613	-	36,914
Foreigner	Andrea Brentan	Director	January - April 2015	22,743	-	-
5.719.922-9	Leonidas Vial Echeverría	Director	Year 2014	14,785	-	-
Foreigner	Alberto de Paoli	Director	January - December 2015	-	-	-
Foreigner	Francesco Di Carlo	Director	April - December 2015	-	-	-
	TOTAL			460,992	-	104,001

Taxpayer ID No. (RUT)	Name	Position	December 31, 2014
			Period in position	Enel Américas Board ThCh$	Board of Subsidiaries ThCh$	Directors' Committee ThCh$
5.710.967-K	Pablo Yrarrázaval Valdés	Chairman	January - October 2014	98,698	-	-
6.243.657-3	Jorge Rosenblut Ratinoff	Chairman	November - December 2014	25,414	-	-
Foreigner	Borja Prado Eulate	ViceChairman	January - December 2014	86,425	-	-
7.052.890-8	Carolina Schmidt Zaldivar	Director	November - December 2014	13,038	-	3,192
5.719.922-9	Leonidas Vial Echeverría	Director	January - October 2014	47,758	-	14,236
6.429.250-1	Rafael Fernández Morandé	Director	January - December 2014	60,779	-	18,731
4.132.185-7	Hernán Somerville Senn	Director	January - December 2014	62,387	-	18,731
Foreigner	Andrea Brentan	Director	January - December 2014	19,738	-	-
	TOTAL			414,237	-	54,890

(1) On June 30, 2015, Mr. Francisco Borja Ascha Besga was appointed as Chairman, and he was again appointed as Chairman on April 29, 2016. He is not compensated.

(2) Mr. José Antonio Vargas Lleras was appointed as Vice Chairman on April 29, 2016. He is not compensated.

(3) Mr. Livio Gallo was designated as Director of the Board on April 28, 2016. He is not compensated.

(4) Mr. Enrico Viale was appointed as Director of the Board on April 28, 2016. He is not compensated.

(5) Mr. Patricio Gómez Sabaini was appointed as Director of the Board on April 28, 2016.

(6) Mr. Domingo Cruzat Amunátegui was appointed as Director of the Board on April 28, 2016.

c) Guarantees given by the Company in favor of the directors

No guarantees have been given to the directors.

The accompanying notes are an integral part of these consolidated financial statements.

F-79

10.3 Compensation for key management personnel

a) Remunerations received by key management personnel

Key Management Personnel
Taxpayer ID No. (RUT)	Name	Position
Foreigner	Luca D'Agnese (1)	Chief Executive Officer
7.750.368-4	Daniel Fernandez Koprich (2)	Deputy Chief Executive Officer
24.852.381-6	Francisco Galán Allué (5)	Administration, Finance and Control Officer
Foreigner	Marco Fadda	Planning and Control Officer
Foreigner	Raffaele Cutrignelli (8)	Internal Audit Officer
24.852.388-3	Francesco Giorgianni (6)	Institutional Relations Officer
15.307.846-7	José Miranda Montecinos (3)	Communications Officer
24.166.243-8	Alain Rosolino (4)	Human Resources and Organization Officer
7.625.745-0	Antonio Barreda Toledo (7)	Procurement Officer
6.973.465-0	Domingo Valdés Prieto	General Counsel and Secretary to the Board

(1) On January 29, 2015, Mr. Luca D’Agnese became CEO replacing Mr. Luigi Ferraris who submitted his voluntarily resignation from the Company, and served until that date.

(2) On November 12, 2014, Mr. Daniel Fernandez Koprich became Deputy CEO replacing Mr. Massimo Tambosco. He served until April 29, 2016.

(3) On December 1, 2014, Mr. José Miranda Montecinos became Communications Officer replacing Mr. Daniel Horacio Martini, who submitted his voluntarily resignation from the Company, and served until December 1, 2014.

(4) On October 1, 2016, Mr. Alain Rosolino became of Human Resources and Organizational Officer replacing Ms. Paola Visintini Vaccarezza, who submitted his voluntarily resignation from the Company, and served until September 30, 2016.

(5) On December 15, 2014, Mr. Francisco Galán Allue became Administration, Finance and Control Officer replacing Mr. Eduardo Escaffi.

(6) On December 15, 2014, Mr. Francesco Giogianni became Institutional Relations Officer.

(7) On January 29, 2015, Mr. Antonio Barreda Toledo became Procurement Officer replacing Mr. Eduardo López Miller.

(8) On October 1, 2016, Mr. Raffaele Cutrignelli became Internal Audit Officer replacing Mr. Alain Rosolino, who became Human Resources and Organizational Officer on that date.

Mr. Alain Rosolino, Mr. José Miranda Montecinos, Ms. Paola Visintini Vaccarezza and Mr. Domingo Valdés Prieto are exclusively compensated by Enel Chile S.A., but render executive services to the Company pursuant to an intercompany agreement between both entities.

Incentive plans for key management personnel

The Group has implemented an annual bonus plan for its executives based on meeting company-wide objectives and on the level of their individual contribution in achieving the overall goals of the Group. The plan provides for a range of bonus amounts according to seniority level. The bonuses paid to the executives consist of a certain number of monthly gross remunerations.

Compensation received by key management personnel is the following:

	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Cash compensation	3,324,508	3,308,345	3,028,193
Short-term benefits for employees	165,972	352,329	830,052
Other long-term benefits	58,150	449,243	562,074
Total	3,548,630	4,109,917	4,420,319

b) Guarantees established by the Company in favor of key management personnel

No guarantees have been given to key management personnel.

10.4 Compensation plans linked to share price

There are no payment plans granted to the Directors or key management personnel based on the share price of the Company.

The accompanying notes are an integral part of these consolidated financial statements.

F-80

11. INVENTORIES

The detail of inventories as of December 31, 2016 and 2015, is as follows:

Classes of Inventories	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Goods	396,362	872,084
Supplies for Production	15,509,565	16,060,887
Oil	10,375,375	13,602,708
Coal	5,134,190	2,458,179
Other inventories (*)	50,504,122	78,124,926
Total	66,410,049	95,057,897
Detail of other inventories
(*) Total other inventories	50,504,122	78,124,926
Supplies for projects and spare parts	21,997,471	22,871,137
Electrical materials	28,506,651	55,253,789

There are no inventories pledged as security for liabilities.

For the year ended December 31, 2016, raw materials and consumables used recognized as fuel expenses were ThCh$244,886,033 (ThCh$258,113,922 and ThCh$205,534,394 for the years ended December 31, 2015 and 2014, respectively) (see Note 26).

As of December 31, 2016 and 2015, no inventories have been written down.

The accompanying notes are an integral part of these consolidated financial statements.

F-81

12. CURRENT TAX ASSETS AND LIABILITIES

The detail of current tax receivables as of December 31, 2016 and 2015, is as follows:

Tax Receivables	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Monthly provisional tax payments (*)	49,240,711	45,274,710
Tax credit for absorbed profits	30,316,819	47,244
Tax credit for training expenses	9,000	80,000
Other	2,758,729	2,052,634
Total	82,325,259	47,454,588

(*) Monthly provisional tax payments made by the holding company.

The detail of current tax payables as of December 31, 2016 and 2015, is as follows:

Tax Payables	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Income tax	134,876,333	142,607,960
Total	134,876,333	142,607,960

The accompanying notes are an integral part of these consolidated financial statements.

F-82

13. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD

13.1. Investments accounted for using the equity method

a. The following tables present the changes in shareholders’ equity of the Group’s equity method investments during the years ended December 31, 2016 and 2015:

Taxpayer ID No.	Changes in Investment in Associates	Relationship	Country	Functional Currency	Ownership Interest	Balance as of January 1, 2016	Additions	Share of Profit (Loss)	Dividends declared	Foreign Currency Translation	Other Comprehensive Income	Other Increases (Decreases)	Balance as of 12/31/2016	Negative equity provision	Balance as of December 31, 2016
						ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Yacylec S.A.	Associate	Argentina	Argentine peso	22.22%	243,409	-	(354,928)	-	(27,741)	-	-	(139,260)	139,260	-
Foreign	Sacme S.A.	Associate	Argentina	Argentine peso	50.00%	15,027	-	92	-	(3,496)	-	-	11,623	-	11,623
Foreign	Central Termica Manuel Belgrano	Associate	Argentina	Argentine peso	25.60%	623,075	-	674,251	(487,702)	(159,752)	-	-	649,872	-	649,872
Foreign	Central Termica San Martin	Associate	Argentina	Argentine peso	25.60%	573,257	-	534,888	(453,631)	(139,654)	-	-	514,860	-	514,860
Foreign	Central Vuelta Obligado S.A.	Associate	Argentina	Argentine peso	40.90%	11,209	-	-	-	(2,603)	-	-	8,606	-	8,606
Foreign	Distribuidora Eléctrica de Cundinamarca S.A. (3)	Joint Venture	Colombia	Colombian peso	49.00%	29,494,468	-	975,844	(269,231)	185,451	(264,257)	(30,122,275)	-	-	-
					TOTAL	30,960,445	-	1,830,147	(1,210,564)	(147,795)	(264,257)	(30,122,275)	1,045,701	139,260	1,184,961
Taxpayer ID No.	Changes in Investment in Associates	Relationship	Country	Functional Currency	Ownership Interest	Balance as of January 1, 2015	Additions	Share of Profit (Loss) (1)	Dividends declared	Foreign Currency Translation	Other Comprehensive Income	Other Increases (Decreases)	Balance as of 12/31/2015	Transfer to assets held for distribution to owners	Balance as of December 31, 2015
						ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Yacylec S.A.	Associate	Argentina	Argentine peso	22.22%	453,015	-	(132,598)	-	(77,008)	-	-	243,409	-	243,409
Foreign	Sacme S.A.	Associate	Argentina	Argentine peso	50.00%	19,657	-	34,434	-	(39,064)	-	-	15,027	-	15,027
Foreign	Distribuidora Eléctrica de Cundinamarca S.A.	Joint Venture	Colombia	Colombian peso	49.00%	32,795,615	-	752,621	-	(4,079,210)	25,442	-	29,494,468	-	29,494,468
Foreign	Central Termica Manuel Belgrano	Associate	Argentina	Argentine peso	25.60%	-	9,127	1,415,471	(619,792)	(181,731)	-	-	623,075	-	623,075
Foreign	Central Termica San Martin	Associate	Argentina	Argentine peso	25.60%	-	9,127	1,263,043	(531,712)	(167,201)	-	-	573,257	-	573,257
Foreign	Central Vuelta Obligado S.A.	Associate	Argentina	Argentine peso	40.90%	-	14,509	-	-	(3,300)	-	-	11,209	-	11,209
96.806.130-5	Electrogas S.A. (2)	Associate	Chile	U.S. dollar	42.50%	10,777,659	-	5,121,427	(4,398,423)	1,120,075	(577,862)	-	12,042,876	(12,042,876)	-
76.788.080-4	GNL Quintero S.A. (2)	Associate	Chile	U.S. dollar	20.00%	15,198,935	-	4,534,344	(4,449,179)	1,852,923	-	-	17,137,023	(17,137,023)	-
76.418.940-K	GNL Chile S.A. (2)	Associate	Chile	U.S. dollar	33.33%	1,818,168	-	495,389	-	348,472	-	-	2,662,029	(2,662,029)	-
76.652.400-1	Centrales Hidroeléctricas De Aysén S.A. (2)	Joint Venture	Chile	Chilean peso	51.00%	6,144,557	2,550,000	(2,414,264)	-	-	-	-	6,280,293	(6,280,293)	-
77.017.930-0	Transmisora Eléctrica de Quillota Ltda. (2)	Joint Venture	Chile	Chilean peso	50.00%	6,426,004	-	1,168,149	-	-	-	-	7,594,153	(7,594,153)	-
					TOTAL	73,633,610	2,582,763	12,238,016	(9,999,106)	(1,226,044)	(552,420)	-	76,676,819	(45,716,374)	30,960,445

(1) The share of profit (loss) from continuing operations was ThCh$3,332,971 for the year ended December 31, 2015.

(2) As of December 31, 2015, these equity method investments were classified as non-current assets held for distribution to owners. Beginning on March 1, 2016, these equity method investments are no longer part of the Group (see Note 5.1).

(3) On October 1, 2016, Distribuidora Eléctrica de Cundinamarca S.A. was merged with our Colombian subsidiary Codensa S.A. (see Note 6).

The accompanying notes are an integral part of these consolidated financial statements.

F-83

b. Additional financial information on investments in associates and joint ventures

- Investments with significant influence

The following tables set forth financial information as of December 31, 2016 and 2015, from the Financial Statements of the investments in associates where the Group has significant influence:

Investments with Significant Influence					December 31, 2016
	Ownership Interst Direct / Indirect	Current Assets	Non-Current Assets	Current Liabilities	Non-Current Liabilities	Revenue	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
	%	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Yacylec S.A.	22.22%	950,194	129,695	1,649,980	56,638	946,240	(2,543,576)	(1,597,336)	(124,847)	(943,317)
Investments with Significant Influence					December 31, 2015
	Ownership Interst Direct / Indirect	Current Assets	Non-Current Assets	Current Liabilities	Non-Current Liabilities	Revenue	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
	%	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GNL Chile S.A (*)	33.33%	73,289,529	19,843,392	59,207,958	25,938,077	655,759,390	(654,273,074)	1,486,316	1,045,519	2,531,835
GNL Quintero S.A. (*)	20.00%	154,169,202	679,246,875	22,104,679	725,626,283	130,540,774	(107,869,054)	22,671,720	9,264,617	31,936,337
Electrogas S.A. (*)	42.50%	9,800,478	46,815,192	12,191,561	16,087,931	23,546,048	(10,624,229)	12,921,819	1,275,795	14,197,614
Yacylec S.A.	22.22%	1,810,275	193,569	868,193	40,198	1,377,810	(1,974,559)	(596,749)	(346,568)	(943,317)

(*) As of December 31, 2015, these investments in associates have been classified as non-current assets held for distribution to owners. Beginning on March 1, 2016, these equity method investments are no longer part of the Group (see Note 5.1).

None of our associates have published price quotations.

- Joint ventures

The following tables present information from the financial statements as of December 31, 2016 and 2015, on the main joint ventures:

	Centrales Hidroeléctricas de Aysén S.A. (*)		Transmisora Eléctrica de Quillota Ltda. (*)		Distribuidora Eléctrica de Cundinamarca S.A. (**)
% Ownership Interest	51.0%	51.0%	50.0%	50.0%	48.997%	48.997%
	12-31-2016 ThCh$	12-31-2015 ThCh$	12-31-2016 ThCh$	12-31-2015 ThCh$	12-31-2016 ThCh$	12-31-2015 ThCh$
Total current assets	-	502,938	-	5,336,516	-	14,988,328
Total non-current assets	-	15,159,321	-	12,148,544	-	127,123,136
Total current liabilities	-	3,290,947	-	466,485	-	16,616,178
Total non-current liabilities	-	56,685	-	1,830,272	-	55,374,521
Cash and cash equivalents	-	428,440	-	4,884,645	-	2,789,518
Other current financial liabilities	-	-	-	-	-	1,081,545
Other non-current financial liabilities	-	-	-	-	-	23,230,972
Revenues	-	-	-	2,852,803	65,341,964	86,666,633
Depreciation and amortization expense	-	-	-	(748,171)	(5,910,434)	(8,773,063)
Impariment losses	-	-	-	-	-	-
Interest income	-	20,009	-	1,678,801	642,606	633,204
Interest expense	-	-	-	-	(2,711,098)	(3,100,381)
Income tax expense	-	(8,586)	-	(679,715)	(2,315,193)	(5,237,742)
Profit (loss)	-	(4,733,482)	-	2,336,297	2,423,521	1,926,420
Other comprehensive income	-	-	-	-	(160,838)	(8,273,502)
Comprehensive income	-	(4,733,482)	-	2,336,297	2,262,683	(6,347,082)

(*) As of December 31, 2015, these investments in joint ventures have been classified as non-current assets held for distribution to owners. Beginning on March 1, 2016, these joint ventures are no longer part of the Group (see Note 5.1).

(**) On October 1, 2016, Distribuidora Eléctrica de Cundinamarca S.A. was merged with our Colombian subsidiary Codensa S.A. (see Note 6).

Appendix 3 to these consolidated financial statements provides information on the main activities of our associates and joint ventures and the ownership interest the Group holds in them.

c. There are no significant commitments and contingencies, or restrictions on funds transfers to its owners in our associates and joint ventures.

The accompanying notes are an integral part of these consolidated financial statements.

F-84

14. INTANGIBLE ASSETS OTHER THAN GOODWILL

The following table presents intangible assets as of December 31, 2016 and 2015:

Intangible Assets, Gross	12-31-2016	12-31-2015
	ThCh$	ThCh$
Intangible Assets, Gross	2,360,145,384	1,943,902,048
Easements and water rights	37,178,049	36,770,284
Concessions	2,187,615,243	1,788,421,395
Development costs	16,120,833	26,126,552
Patents, registered trademarks and other rights	22,935,523	11,285,432
Computer software	90,900,392	79,169,384
Other identifiable intangible assets	5,395,344	2,129,001
Intangible Assets, Amortization and Impairment	12-31-2016	12-31-2015
	ThCh$	ThCh$
Accumulated Amortization and Impairment, Total	(1,148,298,640)	(962,502,776)
Identifiable Intangible Assets	(1,148,298,640)	(962,502,776)
Easements and water rights	(9,758,932)	(9,197,486)
Concessions	(1,060,242,303)	(883,047,307)
Development costs	(8,381,924)	(8,320,904)
Patents, registered trademarks and other rights	(10,316,968)	(8,853,916)
Computer software	(57,872,658)	(51,063,968)
Other identifiable intangible assets	(1,725,855)	(2,019,195)
Intangible Assets, Net	12-31-2016	12-31-2015
	ThCh$	ThCh$
Intangible Assets, Net	1,211,846,744	981,399,272
Easements and water rights	27,419,117	27,572,798
Concessions, Net(1) (*)	1,127,372,940	905,374,088
Development costs	7,738,909	17,805,648
Patents, registered trademarks and other rights	12,618,555	2,431,516
Computer software	33,027,734	28,105,416
Other identifiable intangible assets	3,669,489	109,806

(1) The detail of concessions is the following:

Concession Holder	12-31-2016	12-31-2015
	ThCh$	ThCh$
Ampla Energia e Servicios S.A. (Distribution)	683,280,917	543,414,668
Compañía Energetica do Ceara S.A. (Distribution)	444,092,023	361,959,420
TOTAL	1,127,372,940	905,374,088

(*) See Note 3c.1.

The accompanying notes are an integral part of these consolidated financial statements.

F-85

The reconciliations of the carrying amounts of intangible assets during the years ended December 31, 2016 and 2015, are as follows:

Changes in Intangible Assets	Development Costs	Easements	Concessions	Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangible Assets, Net
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2016	17,805,648	27,572,798	905,374,088	2,431,516	28,105,416	109,806	981,399,272
Changes in identifiable intangible assets:
Increases other than from business combinations	1,458,688	1,740,428	270,075,694	10,422,017	-	14,358,189	298,055,016
Increase (decrease) from foreign currency translation differences, net	(490,119)	(522,013)	137,714,733	20,568	(848,889)	294,056	136,168,336
Amortization (1)	(106,350)	(940,233)	(77,188,493)	(796,971)	(5,392,265)	-	(84,424,312)
Increases (decreases) from transfers and other changes	(70,179)	(375,683)	(81,845,901)	541,425	11,163,472	(10,747,739)	(81,334,605)
Increases (decreases) from transfers	(70,179)	-	-	(112,492)	14,382,623	(14,199,952)	-
Increases (decreases) from other changes (3)	-	(375,683)	(81,845,901)	653,917	(3,219,151)	3,452,213	(81,334,605)
Disposals and removal from service	(10,858,779)	(56,180)	(26,757,181)	-	-	(344,823)	(38,016,963)
Disposals	(10,858,779)	(56,180)	(26,757,181)	-	-	(344,823)	(38,016,963)
Removals from service	-	-	-	-	-	-	-
Other increases (decreases)	-	-	-	-	-	-	-
Total changes in identifiable intangible assets	(10,066,739)	(153,681)	221,998,852	10,187,039	4,922,318	3,559,683	230,447,472
Closing balance as of December 31, 2016	7,738,909	27,419,117	1,127,372,940	12,618,555	33,027,734	3,669,489	1,211,846,744
Changes in Intangible Assets	Development Costs	Easements	Concessions	Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangible Assets, Net
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2015	14,833,312	44,841,692	1,055,986,162	2,206,341	49,549,321	795,228	1,168,212,056
Changes in identifiable intangible assets:
Increases other than from business combinations	5,588,626	317,865	230,687,290	1,208,396	19,091,097	-	256,893,274
Increase (decrease) from foreign currency translation differences, net	(540,471)	(2,335,864)	(236,814,024)	(303,835)	(3,107,703)	15,908	(243,085,989)
Amortization (1)	(36,351)	(1,152,144)	(74,777,866)	(780,678)	(9,285,111)	(20,145)	(86,052,295)
Increases (decreases) from transfers and other changes	(1,090,419)	556,721	(62,920,004)	101,292	(264,122)	(201,424)	(63,817,956)
Increases (decreses) from transfers	38,538	556,721	-	101,292	(139,831)	(556,720)	-
Increases (decreases) from other changes	(1,128,957)	-	(62,920,004)	-	(124,291)	355,296	(63,817,956)
Disposals and removal from service	(949,049)	(80,001)	(6,787,470)	-	(53,972)	-	(7,870,492)
Disposals	-	-	-	-	-	-	-
Removal from service	(949,049)	(80,001)	(6,787,470)	-	(53,972)	-	(7,870,492)
Decreases classified as held for distribution to owners (2)	-	(14,575,471)	-	-	(27,824,094)	(479,761)	(42,879,326)
Total changes in identifiable intangible assets	2,972,336	(17,268,894)	(150,612,074)	225,175	(21,443,905)	(685,422)	(186,812,784)
Closing balance as of December 31, 2015	17,805,648	27,572,798	905,374,088	2,431,516	28,105,416	109,806	981,399,272

(1) See Note 28.

(2) See Note 5.1.II.i.

(3) Correspond mainly to the transfer to financial assets in 2016 from our subsidiaries Ampla and Coelce in accordance with IFRIC 12.

The main additions to intangible assets recognized within item Concessions in accordance with IFRIC 12 (see Note 3.c.1) are from Ampla and Coelce and are related to investments in network and extensions to optimize functionality and to improve efficiency and quality levels of service. The additions to intangible assets for the year ended December 31, 2016 were ThCh$298,055,016. The additions for the year ended December 31, 2015 related to continuing operations were ThCh$246,286,301.

The amortization expense of intangible assets related to continuing operations were ThCh$84,424,312, ThCh$74,944,152, and ThCh$106,274,341 for the years ended December 31, 2016, 2015 and 2014 (see Note 28).

The employee expenses capitalized as part of projects under development were ThCh$ 16,503,934, ThCh$10,165,042 and ThCh$12,046,728 for the years ended December 31, 2016, 2015 and 2014, respectively. All employee expenses capitalized are related to continuing operations.

According to the Group management’s estimates and projections, the expected future cash flows attributable to intangible assets allow recovery of the carrying amount of these assets recognized as of December 31, 2016 and 2015 (see Note 3.d).

As of December 31, 2016 and 2015, the Company does not have significant intangible assets with an indefinite useful life.

The accompanying notes are an integral part of these consolidated financial statements.

F-86

15. GOODWILL

The following table sets forth goodwill by cash-generating unit or group of cash-generating units to which it belongs and changes for the years ended December 31, 2016 and 2015:

Company	Cash Generating Unit	Opening balance 1/1/2015	Foreign Currency Translation	Transfer to assets held for distribution to owners (1)	Closing balance 12/31/2015	Foreign Currency Translation	Closing balance 12/31/2016
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Ampla Energia e Serviços S.A.	Ampla Energia e Serviços S.A.	194,647,043	(42,267,975)	-	152,379,068	22,345,408	174,724,476
Empresa Eléctrica de Colina Ltda. (*)	Empresa Eléctrica de Colina Ltda.	2,240,478	-	(2,240,478)	-	-	-
Compañía Distribuidora y Comercializadora de Energía S.A.	Compañía Distribuidora y Comercializadora de Energía S.A.	11,045,731	(1,357,767)	-	9,687,964	(50,671)	9,637,293
Enel Generación El Chocón S.A.	Hidroeléctrica el Chocón S.A.	7,622,438	(1,799,525)	-	5,822,913	(1,351,678)	4,471,235
Compañía Eléctrica Tarapacá S.A. (*)	Generación Chile	4,656,105	-	(4,656,105)	-	-	-
Enel Distribución Perú S.A.	Enel Distribución Perú	46,881,632	1,249,194	-	48,130,826	(2,135,687)	45,995,139
EGP Cachoeira Dourada S.A.	EGP Cachoeira Dourada S.A.	71,372,291	(15,498,627)	-	55,873,664	8,193,511	64,067,175
Enel Generación Perú S.A.	Enel Generación Perú	88,241,039	2,351,245	-	90,592,284	(4,019,810)	86,572,474
Emgesa S.A. E.S.P.	Emgesa S.A. E.S.P.	4,886,065	(600,606)	-	4,285,459	(22,414)	4,263,045
Enel Distribución Chile S.A. (formerly named Chilectra S.A.) (*)	Distribución Chile	128,374,362	-	(128,374,362)	-	-	-
Enel Generación Chile S.A. (formerly named Endesa S.A.) (*)	Generación Chile	731,782,459	-	(731,782,459)	-	-	-
Inversiones Distrilima S.A.	Enel Distribución Perú	13,944	372	-	14,316	(635)	13,681
Enel Brasil S.A.	Enel Brasil S.A.	906,166	(196,776)	-	709,390	104,028	813,418
Compañía Energética Do Ceará S.A.	Compañía Energética Do Ceará S.A.	97,979,623	(21,276,460)	-	76,703,163	11,248,023	87,951,186
Inversiones GasAtacama Holding Ltda. (*)	Inversiones Gasatacama Holding	20,204,251	-	(20,204,251)	-	-	-
Total		1,410,853,627	(79,396,925)	(887,257,655)	444,199,047	34,310,075	478,509,122

(*) Discontinued operations. Beginning on March 1, 2016, these companies are no longer part of the Group (see Note 5.1.II.i)

According to the Group management’s estimates and projections, the expected future cash flows projections attributable to the cash-generating units or groups of cash-generating units, to which the acquired goodwill has been allocated, allow the recovery of its carrying amount as of December 31, 2016 (see Note 3.d).

The origin of the goodwill is detailed below:

1. Ampla Energia e Serviços S.A.

On November 20, 1996, the Company and Enel Distribución Chile S.A. (formerly named Chilectra S.A.), together with Endesa, S.A. and Electricidad de Portugal, acquired a controlling equity interest in Cerj S.A. (now Ampla Energía) of Rio de Janeiro in Brazil. The Company and Enel Distribución Chile S.A. together acquired 42% of the total shares in an international public bidding process held by the Brazilian government.

The Company and Enel Distribución Chile S.A. also acquired an additional 18.5% on December 31, 2000, as such, holding, directly and indirectly, a total 60.5% ownership interest.

2. Compañía Energética Do Ceará S.A. (Coelce)

Between 1998 and 1999, the Company and Enel Distribución Chile S.A., together with Endesa, S.A., acquired Compañía de Distribución Eléctrica del Estado de Ceará (Coelce) in northeast Brazil in an international public bidding process held by the Brazilian government.

3. Compañía Distribuidora y Comercializadora de Energía S.A. (Codensa S.A.)

On October 23, 1997, the Company and Enel Distribución Chile S.A., together with Endesa, S.A., acquired 48.5% equity interest of Colombiana Codensa S.A., a company that distributes electricity in Santa Fé de Bogotá in Colombia. The acquisition took place through an international public bidding process held by the Colombian government.

4. Enel Generación El Chocón S.A. (formerly named Hidroeléctrica el Chocón S.A.)

On August 31, 1993, Enel Generación Chile S.A. (formerly named Endesa Chile S.A.) acquired 59% equity interest of Enel Generación El Chocón S.A. in an international public bidding process held by the Argentine government.

The accompanying notes are an integral part of these consolidated financial statements.

F-87

5. Enel Distribución Perú S.A. (formerly named Empresa de Distribución Eléctrica de Lima Norte S.A.A.)

On October 15, 2009, in a transaction on the Lima Stock Exchange, the Company acquired an additional 24% interest in Enel Distribución Perú S.A.

6. EGP Cachoeira Dourada S.A. (formerly named Cachoeira Dourada S.A.)

On September 5, 1997, our former subsidiary Enel Generación Chile S.A. acquired 79% of EGP Cachoeira Dourada S.A. in the state of Goias in a public bidding process held by the Brazilian government.

7. Enel Generación Perú S.A. (formerly named Edegel S.A.A.)

On October 9, 2009, in a transaction on the Lima Stock Exchange in Peru, our former subsidiary Enel Generación Chile S.A. acquired an additional 29.3974% equity interest in Enel Generación Perú S.A.

8. Emgesa S.A. E.S.P.

On October 23, 1997, our former subsidiary Enel Generación Chile S.A., together with Endesa, S.A., acquired 48.5% equity interest of Emgesa S.A.E.S.P. in Colombia. The acquisition was made in an international public bidding process held by the Colombian government.

The accompanying notes are an integral part of these consolidated financial statements.

F-88

16. PROPERTY, PLANTS AND EQUIPMENT

The following table sets forth the property, plant and equipment as of December 31, 2016 and 2015:

Classes of Property, Plants and Equipment, Gross	12-31-2016	12-31-2015
	ThCh$	ThCh$
Property, Plants and Equipment, Gross	8,381,209,010	8,112,003,524
Construction in progress	568,136,637	607,250,238
Land	101,377,978	100,503,005
Buildings	129,025,523	124,231,301
Plant and equipment	7,292,956,649	6,986,028,809
Fixtures and fittings	171,204,357	174,119,689
Other property, plant and equipment under finance lease	118,507,866	119,870,482
Classes of Accumulated Depreciation and Impairment in Property, Plants and Equipment	12-31-2016	12-31-2015
	ThCh$	ThCh$
Total Accumulated Depreciation and Impairment in Property, Plants and Equipment	(3,230,871,951)	(3,108,436,891)
Buildings	(57,919,497)	(53,229,337)
Plant and equipment	(3,032,997,537)	(2,930,545,754)
Fixtures and fittings	(108,506,635)	(98,200,527)
Other property, plant and equipment under finance lease	(31,448,282)	(26,461,273)
Classes of Property, Plants and Equipment, Net	12-31-2016	12-31-2015
	ThCh$	ThCh$
Property, Plants and Equipment, Net	5,150,337,059	5,003,566,633
Construction in progress	568,136,637	607,250,238
Land	101,377,978	100,503,005
Buildings	71,106,026	71,001,964
Plant and equipment	4,259,959,112	4,055,483,055
Fixtures and fittings	62,697,722	75,919,162
Other property, plant and equipment under finance lease	87,059,584	93,409,209

The accompanying notes are an integral part of these consolidated financial statements.

F-89

The detail and changes in property, plant, and equipment during the years ended December 31, 2016 and 2015, are as follows:

Changes in 2016		Construction in Progress	Land	Buildings	Plant and Equiment	Fixtures and Fittings	Other Property, Plant and Equipment under Finance Lease	Property, Plant and Equipment, Net
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2016		607,250,238	100,503,005	71,001,964	4,055,483,055	75,919,162	93,409,209	5,003,566,633
Changes	Increases other than from business combinations	531,814,903	86,713	49,327	4,727,855	2,679,517	2,449,006	541,807,321
	Acquisitions through business combinations	3,475,285	2,855,202	5,383,670	81,064,535	1,404,862	222,718	94,406,272
	Increases (decreases) from foreign currency translation differences, net	(57,131,107)	(1,500,587)	(2,481,969)	(133,101,193)	1,689,546	(4,066,966)	(196,592,276)
	Depreciation (1)	-	-	(2,685,423)	(216,244,892)	(10,577,019)	(6,067,395)	(235,574,729)
	Impairment (losses) reversals recognized in profit or loss (1)	-	-	-	-	-	-	-
	Increases (decreases) from transfers and other changes	(500,820,959)	(468,710)	(142,435)	498,701,272	485,960	2,244,872	-
	Increases (decreases) from transfers	(500,820,959)	(468,710)	(142,435)	498,701,272	485,960	2,244,872	-
	Increases (decreases) from transfers from construction in progress	(500,820,959)	(468,710)	(142,435)	498,701,272	485,960	2,244,872	-
	Increases (decreases) from other changes	-	-	-	-	-	-	-
	Disposals and removal from service	(15,790,953)	(67,149)	(19,108)	(29,382,341)	(185,423)	(1,131,860)	(46,576,834)
	Disposals	-	(4,347)	(2,590)	(24,677,073)	(100,356)	(1,104,336)	(25,888,702)
	Removals	(15,790,953)	(62,802)	(16,518)	(4,705,268)	(85,067)	(27,524)	(20,688,132)
	Other increases (decreases)	(660,770)	(30,496)	-	(1,289,179)	(8,718,883)	-	(10,699,328)
	Total changes	(39,113,601)	874,973	104,062	204,476,057	(13,221,440)	(6,349,625)	146,770,426
Closing balance as of December 31, 2016		568,136,637	101,377,978	71,106,026	4,259,959,112	62,697,722	87,059,584	5,150,337,059
Changes in 2016		Construction in Progress	Land	Buildings	Plant and Equiment	Fixtures and Fittings	Other Property, Plant and Equipment under Finance Lease	Property, Plant and Equipment, Net
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2015		1,735,117,241	106,233,186	81,981,704	6,097,991,766	96,320,714	116,571,108	8,234,215,719
Changes	Increases other than from business combinations	1,068,754,499	48,234,359	(702,915)	3,400,169	11,053,860	1,108,095	1,131,848,067
	Increases (decreases) from foreign currency translation differences, net	(156,856,597)	(7,426,335)	(11,054,890)	(391,213,355)	(11,521,067)	2,429,439	(575,642,805)
	Depreciation (1)	-	-	(4,818,708)	(364,968,158)	(16,893,517)	(6,749,401)	(393,429,784)
	Impairment (losses) reversals recognized in profit or loss (1)	(2,522,445)	-	-	12,655,608	-	-	10,133,163
	Increases (decreases) from transfers and other changes	(1,412,625,340)	21,088,932	19,204,944	1,367,821,944	35,491,552	278,467	31,260,499
	Increases (decreases) from transfers	(1,412,281,354)	11,060,086	14,938,905	1,377,186,537	12,022,038	(2,926,212)	-
	Increases (decreases) from transfers from construction in progress	(1,412,281,354)	11,060,086	14,938,905	1,377,186,537	12,022,038	(2,926,212)	-
	Increases (decreases) from other changes	(343,986)	10,028,846	4,266,039	(9,364,593)	23,469,514	3,204,679	31,260,499
	Disposals and removals from service	(3,410,468)	(713,987)	(679)	(1,235,840)	(278,404)	(11,051)	(5,650,429)
	Disposals	-	-	-	-	-	-	-
	Removals	(3,410,468)	(713,987)	(679)	(1,235,840)	(278,404)	(11,051)	(5,650,429)
	Decreases classified as held for distribution to owners (2)	(621,206,652)	(66,913,150)	(13,607,492)	(2,668,969,079)	(38,253,976)	(20,217,448)	(3,429,167,797)
	Total changes	(1,127,867,003)	(5,730,181)	(10,979,740)	(2,042,508,711)	(20,401,552)	(23,161,899)	(3,230,649,086)
Closing balance as of December 31, 2015		607,250,238	100,503,005	71,001,964	4,055,483,055	75,919,162	93,409,209	5,003,566,633

                 (1) See Note 28.

                 (2) See Note 5.1.II.i.

Additional information on property, plants and equipment, net

a) Main investments

Major additions to property, plants and equipment are investments in operating plants and new projects amounting to ThCh$541,807,321 for the year ended December 31, 2016 (ThCh$1,131,848,067 for the year ended December 31, 2015, of which ThCh$864,703,125 corresponded to continuing operations). In the generation and transmission business, the main investments are the works performed in the combined cycle power plants in the subsidiaries Enel Generación Perú S.A. (formerly named Edegel), Emgesa and Enel Generación Costanera (formerly named Central Costanera), involving additions of ThCh$132,265,232 during the year ended December 31, 2016 (for the year ended December 31, 2015, the main investments included the construction in progress of El Quimbo hydraulic power plant in Colombia (400MW) of ThCh$287,285,701). In the distribution business, the major investments are in network and extensions to optimize their operation and to improve efficiency and quality levels of service, amounting to ThCh$342,353,592 for the year ended December 31, 2016 (ThCh$437,227,477 for the year ended December 31, 2015).

The depreciation expense of property, plants and equipment related to continuing operations was ThCh$235,574,729, ThCh$245,598,045 and ThCh$244,468,409 for the years ended December 31, 2016, 2015 and 2014 (see Note 28).

b) Capitalized expenses

b.1) Borrowing costs

Capitalized borrowing costs were ThCh$20,920,558, ThCh$75,229,894 and ThCh$56,918,667 for the years ended December 31, 2016, 2015 and 2014, respectively, of which ThCh$20,920,558, ThCh$73,008,564 and ThCh$55,101,384 corresponded to continuing operations, respectively (see Note 31). The weighted average borrowing rate depends mainly on the geographical location and was 18.06% as of December 31, 2016 (24.02% as of December 31, 2015).

The accompanying notes are an integral part of these consolidated financial statements.

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b.2) Employee expenses capitalized

Employee expenses capitalized that are directly attributable to constructions in progress were ThCh$50,742,451, ThCh$77,940,280 and ThCh$65,229,258 for the years ended December 31, 2016, 2015 and 2014, respectively, of which ThCh$50,742,451, ThCh$56,936,227 and ThCh$43,723,690 corresponded to continuing operations.

c) Finance leases

As of December 31, 2016, property, plants and equipment includes ThCh$87,059,584 in leased assets classified as finance leases (ThCh$113,626,656 as of December 31, 2015, of which ThCh$93,409,209 corresponded to continuing operations).

The present value of future lease payments derived from these finance leases is as follows:

	12-31-2016			12-31-2015
	Gross ThCh$	Interest ThCh$	Present Value ThCh$	Gross ThCh$	Interest ThCh$	Present Value ThCh$
Less than one year	28,837,637	389,447	28,448,190	23,011,723	3,343,287	19,668,436
From one to five years	58,838,707	4,637,721	54,200,986	44,954,548	5,582,380	39,372,168
More than five years	1,167,317	5,600	1,161,717	19,822,444	524,712	19,297,732
Total	88,843,661	5,032,768	83,810,893	87,788,715	9,450,379	78,338,336

Leased assets primarily relate to:

1. Enel Generación Perú S.A. (formerly named Edegel S.A.A): Lease agreements to finance the project of converting the Ventanilla thermoelectric plant to a combined cycle plant. The agreements were signed between Edegel S.A.A. and financial institutions BBVA - Banco Continental, Banco de Crédito del Peru, Citibank del Peru and Banco Internacional del Peru - Interbank. These agreements have an average term of 8 years and bear interest at an annual rate of Libor + 1.75% as of December 31, 2016. The company also has an agreement with Scotiabank, which financed the construction of a new open cycle plant at the Santa Rosa Plant. This agreement has a 9-year term and bears interest an annual rate of Libor + 1.75%.

d) Operating leases

The consolidated statements of income for the years ended December 31, 2016, 2015 and 2014, include ThCh$ 11,678,441, ThCh$15,872,516 and ThCh$21,087,207, respectively; related to the accrual during these periods of operating lease contracts for material assets in operation, of which, ThCh$11,678,441, ThCh$12,449,187 and ThCh$14,352,431 corresponded to continuing operations.

As of December 31, 2016 and 2015, the total future lease payments under those contracts are as follows:

	12-31-2016	12-31-2015
	ThCh$	ThCh$
Less than one year	15,038,165	15,050,043
From one to five years	16,619,442	21,988,822
More than five years	8,415,079	8,565,963
Total	40,072,686	45,604,828

e) Other information

i) As of December 31, 2016, the Group had contractual commitments for the acquisition of property, plants and equipment amounting to ThCh$372,885,724 (ThCh$462,845,826 as of December 31, 2015, of which ThCh$164,998,373 corresponded to continuing operations).

ii) As of December 31, 2016, the Group had property, plants and equipment pledged as security for liabilities for ThCh$7,187,284 (ThCh$13,903,028 as of December 31, 2015, of which the entire amount corresponded to continuing operations) (see Note 33.1).

The accompanying notes are an integral part of these consolidated financial statements.

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iii) The Company and its foreign subsidiaries have insurance policies for all risks, earthquake and machinery breakdown and damages for business interruption with a €1,000 million (ThCh$704,945,187) limit in the case of generating companies and a €50 million (ThCh$32,247,259) limit for distribution companies, including business interruption coverage. Additionally, the Company has Civil Liability insurance to meet claims from third parties with a €500 million (ThCh$352,472,594) limit. The premiums associated with these policies are presented proportionally for each company under the line item “Prepaid expenses”.

iv) Our Argentine subsidiary, Empresa Distribuidora Sur S.A., has its financial equilibrium seriously affected by the delay in the compliance with certain points of the Acta de Acuerdo agreement signed with the Argentine Government, particularly the twice-yearly rate adjustments recognized through the cost-monitoring mechanism (MMC) and the establishment of a Comprehensive Rate Review (RTI in its Spanish acronym) as provided for in this agreement.

At the end of 2011, the Group recognized an impairment loss in property, plants and equipment from Empresa Distribuidora Sur S.A. As of December 31, 2016, the amount recognized was ThCh$38,277,060 (see Note 3.d).

v) In November 2010, our subsidiary Emgesa signed the contract CEQ-21 (“the contract”) with Consortium Impregilo-Obrascon Huarte Lain (“OHL”) for construction of the principal public works of the hydroelectric project El Quimbo.

At the end of 2015, El Quimbo started operations, therefore the contract with the Consortium Impregilo was finalized, and during 2016 commenced a final settlement process.

On October 19, 2016, at the Board of Directors Meeting, a technical and legal analysis of the contract was made, and in order to avoid a future arbitration process, negotiations were settled with the Consortium Impregilo. The initial amount requested by the contractor was CP 204,351 million (ThCh$45,450,894) considering claims and notifications of changes of orders (“NOC” in its Spanish acronym). The final settlement agreed was for a total amount of CP 74,800 million (ThCh$16,636,703) to be paid in the first quarter of 2017.

The accompanying notes are an integral part of these consolidated financial statements.

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17. INCOME TAXES

a) Income taxes

The following table presents the components of the income tax expense/(benefit) recognized in the consolidated statement of comprehensive income for the years ended December 31, 2016, 2015 and 2014:

Current Income Tax and Adjustments to Current Income Tax for Previous Periods	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Current income tax	(360,437,376)	(469,517,752)	(450,655,418)
Tax benefit from tax losses, tax credits or temporary differences not previously recognized for the current period (current tax credits and/or benefits)	19,251,542	29,215,046	34,026,202
Adjustments to current tax from the previous period	(1,126,511)	(5,195,560)	2,871,018
Benefit / (expense) for current income tax due to changes in tax rates or the introduction of new taxes	-	-	-
Other current tax benefit / (expense)	(213,650)	(3,063,579)	(97,812)
Current tax expense, net	(342,525,995)	(448,561,845)	(413,856,010)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences	4,909,247	(72,465,637)	(45,506,055)
Benefit / (expense) from deferred taxes due to changes in tax rates or the introduction of new taxes	(22,202,616)	-	33,404,603
Other components of deferred tax (benefit) /expense	-	-	-
Adjustments to deferred taxes from the previous period	450,842	(2,635,730)	-
Total deferred tax benefit / (expense)	(16,842,527)	(75,101,367)	(12,101,452)
Income tax expense, continuing operations	(359,368,522)	(523,663,212)	(425,957,462)

The following table reconciles income taxes resulting from applying the local current tax rate to “Net income before taxes” and the actual income tax expense recognized in the consolidated statement of comprehensive income for the years ended December 31, 2016, 2015 and 2014:

Reconciliation of Tax Expense	Tax Rate	2016	Tax Rate	2015	Tax Rate	2014
		ThCh$		ThCh$		ThCh$
ACCOUNTING INCOME BEFORE TAX		930,483,597		1,279,812,171		1,178,120,689
Total tax income (expense) using statutory rate	(24.00%)	(223,316,061)	(22.50%)	(287,957,738)	(21.00%)	(247,405,345)
Tax effect of rates applied in other countries	(12.04%)	(112,059,810)	(12.88%)	(164,815,692)	(11.89%)	(140,032,350)
Tax effect of non-taxable revenues and benefits from tax losses and tax credits	5.54%	51,546,543	4.93%	63,075,794	8.36%	98,468,095
Tax effect of non-tax-deductible expenses	(18.01%)	(167,605,341)	(4.39%)	(56,128,320)	(13.63%)	(160,565,951)
Tax effect of changes in income tax rates	(2.39%)	(22,202,616)		-	2.84%	33,404,603
Tax effect of adjustments to taxes in previous periods	(0.12%)	(1,126,511)	(0.41%)	(5,195,560)	0.24%	2,871,018
Adjustments for prior periods deferred taxes	0.05%	450,842	(0.21%)	(2,635,730)		-
Price level restatement for tax purposes (investments in subsidiaries, associates and joint ventures and equity)	12.35%	114,944,432	(5.47%)	(70,005,966)	(1.08%)	(12,697,532)
Total adjustments to tax expense using statutory rate	(14.62%)	(136,052,461)	(18.43%)	(235,705,474)	(15.16%)	(178,552,117)
Income tax benefit (expense), continuing operations	(38.62%)	(359,368,522)	(40.93%)	(523,663,212)	(36.16%)	(425,957,462)

The main temporary differences are described below.

The accompanying notes are an integral part of these consolidated financial statements.

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b) Deferred taxes

The origin and changes in deferred tax assets and liabilities as of December 31, 2016 and 2015, are as follows:

Deferred Tax Assets		Deferred Tax Assets Relating To							Deferred Tax Assets
		Accumulated Depreciation	Accumulated Amortization	Provisions	Post-Employment Benefit Obligations	Revaluation of Financial Instruments	Tax Loss Carryforwards	Other
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2016		25,177,794	5,633,434	27,413,705	34,004,449	15,734,754	-	1,360,887	109,325,023
Changes	Increase (decrease) in profit or loss	(31,316,570)	(613,251)	35,436,109	(1,033,208)	(10,893,937)	-	6,587,581	(1,833,276)
	Increase (decrease) in other comprehensive income	-	-	-	7,344,956	(922,882)	-	(345)	6,421,729
	Acquisitions through business combinations	10,857,365	-	5,303,930	1,150,750	-	-	284,973	17,597,018
	Foreign currency translation	1,350,892	796,994	3,052,806	4,807,899	320,887	-	(104,537)	10,224,941
	Transfers to (from) non-current assets and disposal groups held for sale  (1)	-	-	(1,466,985)	(11,351)	1,093,066	(20,624)	19,849	(386,045)
	Other increases (decreases) (2)	14,449,118	117,291	(23,098,691)	(4,257,861)	-	20,624	(7,709,003)	(20,478,522)
Balance as of December 31, 2016		20,518,599	5,934,468	46,640,874	42,005,634	5,331,888	-	439,405	120,870,868
Deferred Tax Assets		Deferred Tax Assets Relating To							Deferred Tax Assets
		Accumulated Depreciation	Accumulated Amortization	Provisions	Post-Employment Benefit Obligations	Revaluation of Financial Instruments	Tax Loss Carryforwards	Other
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2015		63,763,279	1,506,979	86,266,322	3,103,317	21,132,561	4,851,839	13,013,577	193,637,874
Changes	Increase (decrease) in profit or loss	(1,969,882)	(620,212)	25,701,841	33,790,833	(4,316,990)	7,868,629	(42,100,049)	18,354,170
	Increase (decrease) in other comprehensive income	-	-	-	6,338,161	806,915	-	-	7,145,076
	Foreign currency translation	(7,116,721)	(1,860,738)	(5,404,662)	(9,206,928)	(339,940)	-	(863,778)	(24,792,767)
	Transfers to (from) non-current assets and disposal groups held for sale  (1)	(4,982,473)	-	(2,687,490)	(422,929)	-	(12,720,468)	(1,503,949)	(22,317,309)
	Other increases (decreases)(2)	(24,516,409)	6,607,405	(76,462,306)	401,995	(1,547,792)	-	32,815,086	(62,702,021)
Balance as of December 31, 2015		25,177,794	5,633,434	27,413,705	34,004,449	15,734,754	-	1,360,887	109,325,023

Deferred Tax Liabilities		Deferred Tax Liabilities Relating To						Deferred Tax Liabilities
		Accumulated Depreciation	Accumulated Amortization	Provisions	Post-Employment Benefit Obligations	Revaluation of Financial Instruments	Other
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2016		171,344,977	-	16,764	237	249,770	60,292,867	231,904,615
Changes	Increase (decrease) in profit or loss	(5,812,666)	(704,033)	12,778,397	-	-	8,747,555	15,009,253
	Increase (decrease) in other comprehensive income	-	-	-	(62,099)	(346,094)	419	(407,774)
	Acquisitions through business combinations	15,403,109	-	-	-	-	994,738	16,397,847
	Foreign currency translation	(7,736,281)	49,584	-	-	(11,468)	(9,166,836)	(16,865,001)
	Transfer to liabilities classified as held for distribution to owners (1)	-	-	-	-	-	-	-
	Other increases (decreases)(2)	3,086,780	1,548,728	(12,778,397)	62,099	408,510	(17,737,003)	(25,409,283)
Balance as of December 31, 2016		176,285,919	894,279	16,764	237	300,718	43,131,740	220,629,657
Deferred Tax Liabilities		Impuestos diferidos de Pasivos relativos a						Deferred Tax Liabilities
		Accumulated Depreciation	Accumulated Amortization	Provisions	Post-Employment Benefit Obligations	Revaluation of Financial Instruments	Other
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2015		427,881,352	-	41,553	16,499	163,063	50,259,017	478,361,484
Changes	Increase (decrease) in profit or loss	26,238,797	(712,025)	13,122,113	488,257	-	37,625,257	76,762,399
	Increase (decrease) in other comprehensive income	-	-	-	(64,398)	147,605	(200,133)	(116,926)
	Foreign currency translation	4,395,448	-	(1)	65,061	5,424	(18,128,150)	(13,662,218)
	Transfer to liabilities classified as held for distribution to owners (1)	(233,948,342)	-	(285,255)	(679)	-	(792,049)	(235,026,325)
	Other increases (decreases)(2)	(53,222,278)	712,025	(12,861,646)	(504,503)	(66,322)	(8,471,075)	(74,413,799)
Balance as of December 31, 2015		171,344,977	-	16,764	237	249,770	60,292,867	231,904,615

(1) See Note 5.1.II.i.

(2) Mainly corresponds to the offset of deferred tax assets and deferred tax liabilities.

Recovery of deferred tax assets will depend on whether sufficient taxable profits are obtained in the future. The Company’s management believes that the future profit projections for its subsidiaries will allow these assets to be recovered.

a. As of December 31, 2016, the Group has not recognized deferred tax assets related to tax losses carry forward for ThCh$8,842,093 (ThCh$20,342,024 as of December 31, 2015) (see Note 3.o).

The Group has not recognized deferred tax liabilities for taxable temporary differences relating to investment in subsidiaries and joint ventures, as it is able to control the timing of the reversal of the temporary differences and considers that it is probable that such temporary differences will not reverse in the foreseeable future. As of December 31, 2016, the aggregate amount of taxable temporary differences relating to investments in subsidiaries and joint ventures for which deferred tax

The accompanying notes are an integral part of these consolidated financial statements.

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liabilities have not been recognized were ThCh$1,099,576,517 (ThCh$1,835,600,705 as of December 31, 2015, of which ThCh$979,972,151 corresponded to continuing operations). On the other hand, the total amount of deductible temporary differences relating to investments in subsidiaries and joint ventures for which as of December 31, 2016, it is probable that will not reverse in the foreseeable future or there will be not sufficient taxable profits in the future to recover such temporary differences were, ThCh$2,440,577,190 (ThCh$3,162,552,465 as of December 31, 2015, of which ThCh$2,700,619,169 corresponded to continuing operations).

Additionally, the Group has not recognized deferred tax assets for deductible temporary differences which as of December 31, 2016, totaled ThCh$53,241,911 (ThCh$57,311,886 as of December 31, 2015), as it is not probable that sufficient future taxable profits will exist to recover such temporary differences.

The Group companies are potentially subject to income tax audits by the tax authorities of each country in which the Group operates. Such tax audits are limited to a number of annual tax periods and once these have expired, audits of these periods can no longer be performed. Tax audits by nature are often complex and can require several years to complete. The following table presents a summary of tax years potentially subject to examination:

Country	Period
Chile	2008-2015
Argentina	2008-2015
Brazil	2010-2015
Colombia	2012-2014
Peru	2010-2014

Given the range of possible interpretations of tax standards, the results of any future inspections carried out by tax authorities for the years subject to audit can give rise to tax liabilities that cannot currently be quantified objectively. Nevertheless, the Company’s Management estimates that the liabilities, if any, that may arise from such audits, would not significantly impact the Group companies’ future results.

The effects of deferred taxes on the components of other comprehensive income attributable to both controlling and non-controlling interests for the years ended December 31, 2016, 2015 and 2014, are as follows:

Effects of Deferred Tax on the Components of Other Comprehensive Income	December 31, 2016			December 31, 2015			December 31, 2014
	Amount before Tax	Income Tax Expense (Benefit)	Amount After Tax	Amount before Tax	Income Tax Expense (Benefit)	Amount After Tax	Amount before Tax	Income Tax Expense (Benefit)	Amount After Tax
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Available-for-sale financial assets	659,734	-	659,734	(442,864)	(291)	(443,155)	1,849	(1,462)	387
Cash flow hedges	19,427,546	(4,608,636)	14,818,910	(138,241,392)	36,399,000	(101,842,392)	(145,892,370)	35,887,996	(110,004,374)
Share of other comprehensive income in associates and joint ventures accounted for using the equity method	(14,086,364)	-	(14,086,364)	(552,420)	-	(552,420)	13,476,871	-	13,476,871
Foreign currency translation	145,304,104	-	145,304,104	(644,537,672)	-	(644,537,672)	4,370,648	-	4,370,648
Actuarial gains (losses) from defined benefit pension plans	(19,879,558)	6,486,162	(13,393,396)	(19,027,368)	6,018,363	(13,009,005)	(36,681,734)	12,694,514	(23,987,220)
Components of other comprehensive income	131,425,462	1,877,526	133,302,988	(802,801,716)	42,417,072	(760,384,644)	(164,724,736)	48,581,048	(116,143,688)

The movements in deferred taxes for the components of other comprehensive income for the years ended December 31, 2016, 2015 and 2014, are as follows:

Reconciliation of changes in deferred taxes of components of other comprehensive income	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Total increases (decreases) for deferred taxes of other comprehensive income from continuing operations	6,829,503	7,262,002	11,049,537
Income tax of changes in cash flow hedge transactions	(14,360)	3,504,452	3,055,371
Deferred tax of actuarial gains (losses) from defined benefit plans	(480,131)	(384,196)	2,322,543
Total increases (decreases) for deferred taxes of other comprehensive income from discontinued operations	(4,457,486)	32,034,814	32,153,597
Total income tax relating to components of other comprehensive income	1,877,526	42,417,072	48,581,048

b. In Chile, Law No. 20,780 was published in the Official Gazette on September 29, 2014. It changes the income tax system and other taxes, by replacing the current tax system in 2017 with two alternative tax systems: the attributed income system and partially integrated system.

The accompanying notes are an integral part of these consolidated financial statements.

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This law gradually increases the rate of income tax on corporate income. Thus, it will increase to 21% in 2014, to 22.5% in 2015 and to 24% in 2016. As from 2017 taxpayers choosing the attributed income system will be subject to a rate of 25%, while companies choosing the partially integrated system will be subject to a rate of 25.5% in 2017 and 27% in 2018.

Furthermore, this law establishes that the partially integrated system will apply by default to open stock companies, unless a future Extraordinary Shareholders’ Meeting agrees to adopt the attributed income system.

As discussed in Note 3.p, the Company assumed that since an Extraordinary Shareholders’ Meeting had not agreed to adopt the alternative system, the partially integrated system applies by default. The changes in deferred tax assets and liabilities as a direct effect of the increase in the corporate income tax rate were recognized directly in net income. Particularly, for the year ended December 31, 2014, the net charge against net income was ThCh$62,035,245, decreasing net income attributable to shareholders of Enel Américas by ThCh$38,284,524.  

c. In Colombia, Law No. 1.819, enacted on December 29, 2016, eliminates the CREE tax on corporations and CREE surcharge and introduces a temporary income surcharge of 6% for 2017 and 4% for 2018. The corporate income tax will have the following rate schedule: 40% in 2017 (34% income tax plus 6% income surcharge); 37% in 2018 (33% income tax plus 4% income surcharge); and 33% in 2019 onwards. The Colombian subsidiaries recognized changes in deferred tax assets and liabilities as of December 31, 2016. The net effect of the recognition was a loss of ThCh$943,570.

Law No. 1,739 enacted in 2014, increased from 8% to 9% indefinitely the rate for the specific income tax for financing social programs known as CREE, levied on taxable profits earned each year for the tax year 2016 onwards.

Additionally, this law established the CREE surcharge of 5%, 6%, 8% and 9% for 2015, 2016, 2017 and 2018, respectively.

The effect of temporary differences involving the payment of less or more income tax in the current year is recognized as a deferred tax credit or debit, as appropriate, at the applicable tax rates in effect when the differences are reversed (39% in 2015, 40% in 2016, 42% in 2017, 43% in 2018 and 34% from 2019), provided there is a reasonable expectation that such differences will reverse in the future and that the asset will generate sufficient taxable income.

As part of this increase in tax rates, the Colombian subsidiaries have recognized changes in deferred tax assets and liabilities as of December 31, 2014. The net effect was the recognition of a gain of ThCh$3,943,235.

d. In Peru, Legislative Decree No. 1261, issued on December 10, 2016, increases corporate income tax from 28% to 29.5%. Under the new law, previously planned reductions (Law No. 30.296) to the rate of corporate income tax no longer apply. The Peruvian subsidiaries recognized changes in deferred tax assets and liabilities as of December 31, 2016. The net effect of the recognition was a loss of ThCh$23,060,566.

The corporate income tax rate was 30% on taxable income, after deducting the employees profit share of 5% of taxable income, as of December 31, 2015 and 2014.

Law No. 30.296 established the applicable corporate income tax rates on taxable income, after deducting the employees profit share as: 28% in 2015 and 2016, 27% in 2017 and 2018, and 26% from 2019 onwards.

As part of this increase in tax rates, the Peruvian subsidiaries have recognized changes in deferred tax assets and liabilities as of December 31, 2014. The net effect was the recognition of a gain for ThCh$24,818,773.

The accompanying notes are an integral part of these consolidated financial statements.

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18. OTHER FINANCIAL LIABILITIES

The balance of other financial liabilities as of December 31, 2016 and 2015, is as follows:

Other Financial Liabilities	December 31, 2016		December 31, 2015
	Current	Non-Current	Current	Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing borrowings	497,915,481	2,386,006,677	617,276,453	1,846,995,721
Hedging derivatives (*)	3,531,642	10,747,217	69,545,029	300,871
Non-hedging derivatives (**)	3,237,240	-	1,052,026	-
Total	504,684,363	2,396,753,894	687,873,508	1,847,296,592

(*) See Note 20.2.a.

(**) See Note 20.2.b.

18.1 Interest-bearing borrowings

The detail of current and non-current interest-bearing borrowings as of December 31, 2016 and 2015, is as follows:

Classes of Interest-Bearing Borrowings		December 31, 2016		December 31, 2015
		Current	Non-Current	Current	Non-Current
		ThCh$	ThCh$	ThCh$	ThCh$
Bank loans		158,143,158	487,792,658	188,121,545	232,626,020
Unsecured obligations		307,225,157	1,804,774,407	356,221,587	1,391,715,407
Financial liabilities		28,448,190	55,362,703	19,668,436	58,669,900
Other obligations		4,098,976	38,076,909	53,264,885	163,984,394
	Total	497,915,481	2,386,006,677	617,276,453	1,846,995,721

Bank loans by currency and contractual maturity as of December 31, 2016 and 2015, are as follows:

            - Summary of bank loans by currency and maturity

Country	Currency	Effective Interest Rate	Nominal Interest Rate	Secured / Unsecured	Current			Non-Current
					Maturity		Total Current 12/31/2016	Maturity					Total Non-Current 12/31/2016
					One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five yeats
					ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	Ch$	6.00%	6.00%	Unsecured	4	-	4	-	-	-	-	-	-
Peru	US$	2.88%	2.79%	Unsecured	964,833	17,385,056	18,349,889	18,107,681	281,711	-	-	-	18,389,392
Peru	Soles	5.64%	5.53%	Unsecured	2,225,252	-	2,225,252	31,860,174	-	-	-	-	31,860,174
Argentina	Arg $	36.74%	32.50%	Unsecured	-	837,673	837,673	-	-	-	-	-	-
Colombia	CP	8.49%	8.21%	Unsecured	4,020,967	45,698,986	49,719,953	14,556,446	59,629,644	48,253,890	10,655,572	18,089,820	151,185,372
Brazil	US$	3.61%	3.60%	Unsecured	656,796	-	656,796	25,706,605	50,941,440	-	-	1,859,512	78,507,557
Brazil	Real	11.84%	11.56%	Unsecured	30,561,364	55,792,227	86,353,591	75,488,351	68,176,614	33,263,390	23,468,026	7,453,782	207,850,163
Total					38,429,216	119,713,942	158,143,158	165,719,257	179,029,409	81,517,280	34,123,598	27,403,114	487,792,658
Country	Currency	Tasa Efectiva	Nominal Interest Rate	Secured / Unsecured	Current			Non-Current
					Maturity		Total Current 12/31/2015	Maturity					Total Non-Current 12/31/2015
					One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five yeats
					ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Peru	US$	3.54%	2.40%	Unsecured	26,650,675	2,833,429	29,484,104	3,777,906	19,247,361	299,442	-	-	23,324,709
Peru	Soles	5.61%	5.20%	Unsecured	12,712,792	-	12,712,792	2,083,721	22,920,929	-	-	-	25,004,650
Argentina	US$	9.09%	13.13%	Unsecured	3,899,595	-	3,899,595	-	-	-	-	-	-
Argentina	Arg $	21.74%	37.06%	Unsecured	2,693,226	4,809,318	7,502,544	1,080,762	-	-	-	-	1,080,762
Colombia	CP	8.32%	6.46%	Unsecured	32,928,994	76,448,340	109,377,334	38,158,543	9,092,465	9,092,465	9,092,465	27,277,398	92,713,336
Brazil	Real	9.61%	14.53%	Unsecured	9,045,598	16,099,578	25,145,176	30,167,521	30,167,521	30,167,521	-	-	90,502,563
Total					87,930,880	100,190,665	188,121,545	75,268,453	81,428,276	39,559,428	9,092,465	27,277,398	232,626,020

The accompanying notes are an integral part of these consolidated financial statements.

F-97

- Fair value measurement and hierarchy

The fair value of current and non-current bank borrowings as of December 31, 2016 was ThCh$654,354,668 (ThCh$423,123,934 as of December 31, 2015). The borrowings have been classified as Level 2 fair value measurement based on the entry data used in the valuation techniques (see Note 3.g).

The accompanying notes are an integral part of these consolidated financial statements.

F-98

             - Identification of bank borrowings by company

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Amortization	December 31, 2016										December 31, 2015
										Current			Non-Current							Current				Non-Current
										Less than 90 days	More than 90 days	Tota Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days		More than 90 days	Tota Current	One to two years		Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
										ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$		ThCh$	ThCh$	ThCh$		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Ampla Energía S.A.	Brazil	Foreign	Banco do Brazil	Brazil	Real	13.58%	13.71%	At Maturity	-	-	-	-	-	-	-	-	-	-		400,960	400,960	7,765,896		7,765,896	7,765,896	-	-	23,297,688
Foreign	Ampla Energía S.A.	Brazil	Foreign	Citibank	Brazil	US$	3.53%	3.52%	At Maturity	196,649	-	196,649	25,706,605	-	-	-	-	25,706,605	-		-	-	-		-	-	-	-	-
Foreign	Ampla Energía S.A.	Brazil	Foreign	Banco Santander	Brazil	US$	2.85%	2.85%	At Maturity	442,187	-	442,187	-	50,941,440	-	-	-	50,941,440	-		-	-	-		-	-	-	-	-
Foreign	Ampla Energía S.A.	Brazil	Foreign	BNDES	Brazil	Real	11.67%	11.40%	Monthly	11,739,154	25,904,559	37,643,713	30,500,790	26,462,172	21,557,834	15,247,699	5,036,832	98,805,327	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Bank of Tokyo	Colombia	CP	8.49%	8.32%	At Maturity	1,069,178	-	1,069,178	-	44,483,163	-	-	-	44,483,163	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Bank of Tokyo	Colombia	CP	9.01%	8.82%	At Maturity	176,454	-	176,454	-	-	36,031,362	-	-	36,031,362	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Banco de Bogota	Colombia	CP	9.46%	9.08%	Quarterly	568,366	1,795,712	2,364,078	1,806,312	544,877	-	-	-	2,351,189	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Banco AV Villas	Colombia	CP	9.24%	8.87%	Quarterly	289,728	912,388	1,202,116	919,874	278,020	-	-	-	1,197,894	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Banco Popular	Colombia	CP	9.13%	8.77%	Quarterly	166,568	468,407	634,975	428,288	417,030	-	-	-	845,318	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Banco Popular	Colombia	CP	9.20%	8.83%	Quarterly	302,577	969,695	1,272,272	780,938	1,112,079	-	-	-	1,893,017	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	7.73%	7.47%	Quarterly	64,379	183,527	247,906	141,004	216,624	54,156	-	-	411,784	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	7.85%	7.58%	Quarterly	51,822	161,004	212,826	118,298	187,756	46,939	-	-	352,993	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	7.66%	7.40%	Quarterly	26,200	89,251	115,451	37,131	103,145	51,573	-	-	191,849	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	7.73%	7.47%	Quarterly	108,305	309,794	418,099	215,099	360,029	180,014	-	-	755,142	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	7.85%	7.58%	Quarterly	66,348	206,734	273,082	136,712	237,398	118,699	-	-	492,809	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	7.74%	7.48%	Quarterly	58,887	202,089	260,976	69,861	229,543	172,157	-	-	471,561	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	8.49%	8.18%	Quarterly	146,523	525,416	671,939	220,937	417,030	556,040	278,020	-	1,472,027	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	8.39%	8.08%	Quarterly	83,477	242,583	326,060	101,021	260,289	260,289	130,144	-	751,743	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA	Colombia	CP	8.51%	8.19%	Quarterly	116,510	384,149	500,659	144,028	403,257	403,257	201,628	-	1,152,170	-		-	-	-		-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Banco Agrario	Colombia	CP	8.91%	8.57%	Quarterly	392,475	1,289,272	1,681,747	392,034	1,334,495	1,334,495	1,000,871	-	4,061,895	-		-	-	-		-	-	-	-	-
Foreign	Chinango S.A.C.	Peru	Foreign	Banco de Credito del Peru	Peru	US$	2.64%	2.56%	Quarterly	238,475	566,028	804,503	16,980,837	-	-	-	-	16,980,837	244,599		601,653	846,252	802,204		18,049,594	-	-	-	18,851,798
Foreign	Chinango S.A.C.	Peru	Foreign	Bank Of Nova Scotia	Peru	US$	3.70%	3.57%	Quarterly	425,970	1,254,494	1,680,464	-	-	-	-	-	-	458,314		1,333,451	1,791,765	1,777,935		-	-	-	-	1,777,935
Foreign	Chinango S.A.C.	Peru	Foreign	Bank Of Nova Scotia	Peru	US$	3.52%	3.40%	Quarterly	300,388	845,133	1,145,521	1,126,844	281,711	-	-	-	1,408,555	328,118		898,325	1,226,443	1,197,767		1,197,767	299,442	-	-	2,694,976
Foreign	Enel Cien S.A. (formerly named Cien S.A.)	Brazil	Foreign	Bndes	Brazil	Real	9.85%	9.54%	Monthly	286,541	819,874	1,106,415	1,093,166	1,093,166	546,583	-	-	2,732,915	-		-	-	-		-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Banco Itaú Brazil	Brazil	Real	15.55%	15.19%	Annually	11,546,599	-	11,546,599	10,274,671	10,274,671	-	-	-	20,549,342	-		1,128,884	1,128,884	8,960,650		8,960,650	8,960,650	-	-	26,881,950
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Brazil	Brazil	Real	14.81%	14.51%	Annually	970,602	15,412,007	16,382,609	15,412,007	15,412,007	-	-	-	30,824,014	-		14,569,734	14,569,734	13,440,975		13,440,975	13,440,975	-	-	40,322,925
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	Real	7.85%	7.71%	Monthly	1,124,086	3,273,119	4,397,205	4,364,159	1,091,040	-	-	-	5,455,199	-		-	-	-		-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Bndes	Brazil	Real	11.33%	11.01%	Monthly	4,894,382	10,382,668	15,277,050	13,843,558	13,843,558	11,158,973	8,220,327	2,416,950	49,483,366	-		-	-	-		-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Brazil	Brazil	US$	4.44%	4.44%	Bi-Annually	17,960	-	17,960	-	-	-	-	1,859,512	1,859,512	-		-	-	-		-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Banco Santander	Brazil	Real	13.80%	15.76%	Other	-	-	-	-	-	-	-	-	-	9,045,598		-	9,045,598	-		-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Bank  Nova Scotia	Peru	US$	1.65%	1.62%	At Maturity	-	14,719,401	14,719,401	-	-	-	-	-	-	25,619,644		-	25,619,644	-		-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	6.90%	6.73%	Quarterly	2,018,760	-	2,018,760	-	-	-	-	-	-	28,776		-	28,776	2,083,721		-	-	-	-	2,083,721
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	5.83%	5.71%	Quarterly	91,824	-	91,824	4,181,648	-	-	-	-	4,181,648	95,383		-	95,383	-		4,375,814	-	-	-	4,375,814
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.10%	5.01%	Quarterly	16,554	-	16,554	2,986,891	-	-	-	-	2,986,891	14,718		-	14,718	-		3,125,581	-	-	-	3,125,581
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.10%	5.01%	Quarterly	26,898	-	26,898	4,978,152	-	-	-	-	4,978,152	23,807		-	23,807	-		5,209,302	-	-	-	5,209,302
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.10%	5.01%	Quarterly	19,188	-	19,188	4,779,026	-	-	-	-	4,779,026	15,918		-	15,918	-		5,000,930	-	-	-	5,000,930
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.10%	5.01%	Quarterly	17,916	-	17,916	4,978,152	-	-	-	-	4,978,152	14,416		-	14,416	-		5,209,302	-	-	-	5,209,302
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	5.17%	5.07%	Quarterly	-	-	-	-	-	-	-	-	-	12,519,774		-	12,519,774	-		-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Santander	Peru	Soles	6.35%	6.20%	Quarterly	34,112	-	34,112	9,956,305	-	-	-	-	9,956,305	-		-	-	-		-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Provincia de Buenos Aires	Argentina	Ar$	35.36%	30.67%	Monthly	-	-	-	-	-	-	-	-	-	83,049		-	83,049	-		-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	45.20%	37.88%	Quarterly	-	-	-	-	-	-	-	-	-	169,444		274,065	443,509	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA Colombia	Colombia	CP	9.43%	9.21%	At Maturity	143,449	6,672,474	6,815,923	6,672,474	6,672,474	6,672,474	6,672,474	13,344,949	40,034,845	135,920		3,353,778	3,489,698	6,707,556		6,707,556	6,707,556	6,707,556	20,122,671	46,952,895
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Bogota	Colombia	CP	9.46%	9.24%	At Maturity	51,174	2,372,435	2,423,609	2,372,435	2,372,435	2,372,435	2,372,435	4,744,871	14,234,611	48,510		1,192,454	1,240,964	2,384,909		2,384,909	2,384,909	2,384,909	7,154,727	16,694,363
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	AV VILLAS	Colombia	CP	6.06%	5.93%	At Maturity	-	-	-	-	-	-	-	-	-	11,038,653		-	11,038,653	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Citibank Colombia	Colombia	CP	5.57%	6.01%	At Maturity	-	-	-	-	-	-	-	-	-	5,169,932		-	5,169,932	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA Colombia	Colombia	CP	8.90%	8.61%	At Maturity	-	-	-	-	-	-	-	-	-	361,969		27,472,753	27,834,722	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Bogota	Colombia	CP	6.84%	6.66%	At Maturity	-	-	-	-	-	-	-	-	-	13,251,721		-	13,251,721	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Crédito del Peru	Colombia	Soles	5.87%	5.70%	At Maturity	-	-	-	-	-	-	-	-	-	-		20,318,330	20,318,330	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Crédito del Peru	Colombia	Soles	5.93%	5.76%	At Maturity	-	-	-	-	-	-	-	-	-	-		13,509,598	13,509,598	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Crédito del Peru	Colombia	Soles	5.65%	5.50%	At Maturity	-	-	-	-	-	-	-	-	-	-		10,462,152	10,462,152	-		-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	The Bank Of Tokyo	Colombia	CP	7.02%	6.90%	At Maturity	138,547	28,914,056	29,052,603	-	-	-	-	-	-	-		139,275	139,275	29,066,078		-	-	-	-	29,066,078
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco Davivienda	Colombia	CP	6.30%	6.15%	At Maturity	-	-	-	-	-	-	-	-	-	2,922,289		-	2,922,289	-		-	-	-	-	-
Foreign	Enel Argentina S.A. (formerly named Endesa Argentina S.A.)	Argentina	Foreign	Citibank	Argentina	Ar$	36.74%	34.00%	At Maturity	-	-	-	-	-	-	-	-	-	438,505		-	438,505	-		-	-	-	-	-
Foreign	Enel Generación Costanera S.A. (formerly named Endesa Costanera S.A.)	Argentina	Foreign	Banco Galicia	Argentina	Ar$	36.07%	32.00%	At Maturity	-	201,208	201,208	-	-	-	-	-	-	-		714,607	714,607	259,978		-	-	-	-	259,978
Foreign	Enel Generación Costanera S.A. (formerly named Endesa Costanera S.A.)	Argentina	Foreign	Banco Itaú Argentina	Argentina	Ar$	38.61%	34.00%	At Maturity	-	92,674	92,674	-	-	-	-	-	-	-		271,439	271,439	120,187		-	-	-	-	120,187
Foreign	Enel Generación Costanera S.A. (formerly named Endesa Costanera S.A.)	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	33.57%	30.00%	At Maturity	-	57,223	57,223	-	-	-	-	-	-	-		181,232	181,232	73,961		-	-	-	-	73,961
Foreign	Enel Generación Costanera S.A. (formerly named Endesa Costanera S.A.)	Argentina	Foreign	Banco Supervielle	Argentina	Ar$	43.80%	38.00%	At Maturity	-	89,446	89,446	-	-	-	-	-	-	-		259,139	259,139	115,564		-	-	-	-	115,564
Foreign	Enel Generación Costanera S.A. (formerly named Endesa Costanera S.A.)	Argentina	Foreign	Citibank	Argentina	Ar$	33.57%	30.00%	At Maturity	-	296,970	296,970	-	-	-	-	-	-	-		852,379	852,379	381,640		-	-	-	-	381,640
Foreign	Enel Generación Costanera S.A. (formerly named Endesa Costanera S.A.)	Argentina	Foreign	Credit Suisse International	Argentina	US$	14.84%	13.92%	Quarterly	-	-	-	-	-	-	-	-	-	1,216,306		-	1,216,306	-		-	-	-	-	-
Foreign	Enel Generación Costanera S.A. (formerly named Endesa Costanera S.A.)	Argentina	Foreign	ICBC Argentina	Argentina	Ar$	34.81%	31.00%	At Maturity	-	100,152	100,152	-	-	-	-	-	-	-		291,321	291,321	129,432		-	-	-	-	129,432
94.271.000-3	Enel Américas S.A.	Chile	97.004.000-5	Banco Santander Chile	Chile	Ch$	6.00%	6.00%	At Maturity	4	-	4	-	-	-	-	-	-	-		-	-	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Macro	Argentina	Ar$	43.63%	38.45%	At Maturity	-	-	-	-	-	-	-	-	-	1,119,924		-	1,119,924	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Deutsche Bank	Argentina	US$	13.50%	12.86%	Quarterly	-	-	-	-	-	-	-	-	-	1,341,641		-	1,341,641	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Standard Bank	Argentina	US$	13.50%	12.86%	Quarterly	-	-	-	-	-	-	-	-	-	670,824		-	670,824	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Itau	Argentina	US$	13.50%	12.86%	Quarterly	-	-	-	-	-	-	-	-	-	670,824		-	670,824	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Santander - Sindicado IV	Argentina	Ar$	34.58%	30.81%	Quarterly	-	-	-	-	-	-	-	-	-	202,930		451,981	654,911	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Itau- Sindicado IV	Argentina	Ar$	34.58%	30.81%	Quarterly	-	-	-	-	-	-	-	-	-	185,284		412,679	597,963	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Galicia - Sindicado IV	Argentina	Ar$	34.58%	30.81%	Quarterly	-	-	-	-	-	-	-	-	-	176,461		393,027	569,488	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Hipotecario - Sindicado IV	Argentina	Ar$	34.58%	30.81%	Quarterly	-	-	-	-	-	-	-	-	-	61,761		137,560	199,321	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Ciudad -Sindicado IV	Argentina	Ar$	34.58%	30.81%	Quarterly	-	-	-	-	-	-	-	-	-	26,469		58,954	85,423	-		-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	ICBC - Sindicado IV	Argentina	Ar$	34.58%	30.81%	Quarterly	-	-	-	-	-	-	-	-	-	229,399		510,935	740,334	-		-	-	-	-	-
					Totales					38,429,216	119,713,942	158,143,158	165,719,257	179,029,409	81,517,280	34,123,598	27,403,114	487,792,658	87,930,880		100,190,665	188,121,545	75,268,453		81,428,276	39,559,428	9,092,465	27,277,398	232,626,020

Appendix 4, letter a), shows the estimated future cash flows (undiscounted) that the Group will have to disburse to settle the bank loans detailed above.

The accompanying notes are an integral part of these consolidated financial statements.

F-99

18.2 Unsecured liabilities

The detail of Unsecured Liabilities by currency and maturity as of December 31, 2016 and 2015, is as follows:

      - Summary of unsecured liabilities by currency and maturity

Country	Currency	Nominal Interest Rate	Secured / Unsecured	Current			Non-Current
				Maturity		Total Current 12/31/2016	Maturity					Total Non-Current 12/31/2016
				One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
				ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	5.30%	Unsecured	-	2,948,827	2,948,827	-	-	-	-	388,960,853	388,960,853
Chile	U.F.	5.75%	Unsecured	-	3,702,837	3,702,837	3,855,689	4,077,390	4,311,838	4,559,767	1,886,118	18,690,802
Peru	US$	6.59%	Unsecured	651,132	-	651,132	6,690,637	5,463,574	6,690,637	-	6,690,637	25,535,485
Peru	Soles	6.27%	Unsecured	10,788,867	20,504,146	31,293,013	-	42,812,109	25,886,391	19,912,609	145,940,505	234,551,614
Colombia	CP	10.16%	Unsecured	153,373,228	-	153,373,228	106,728,453	132,686,629	73,597,188	224,310,020	455,767,738	993,090,028
Brazil	Real	13.50%	Unsecured	9,545,310	105,710,810	115,256,120	95,418,693	48,526,932	-	-	-	143,945,625
			Total	174,358,537	132,866,620	307,225,157	212,693,472	233,566,634	110,486,054	248,782,396	999,245,851	1,804,774,407
Country	Currency	Nominal Interest Rate	Secured / Unsecured	Current			Non-Current
				Maturity		Total Current 12/31/2015	Maturity					Total Non-Current 12/31/2015
				One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
				ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	7.00%	Unsecured	-	179,552,878	179,552,878	-	-	-	-	609,317	609,317
Chile	U.F.	5.75%	Unsecured	-	3,417,313	3,417,313	3,546,564	3,750,488	3,966,142	4,194,193	6,097,254	21,554,641
Peru	US$	6.50%	Unsecured	1,025,402	14,223,478	15,248,880	-	7,111,739	5,807,446	7,111,739	7,111,739	27,142,663
Peru	Soles	6.44%	Unsecured	11,874,390	9,345,624	21,220,014	20,628,837	-	44,799,999	27,088,371	123,043,719	215,560,926
Colombia	CP	10.81%	Unsecured	60,132,757	-	60,132,757	125,441,571	107,284,492	80,913,285	53,852,881	551,735,058	919,227,287
Brazil	Real	15.64%	Unsecured	-	76,649,745	76,649,745	87,811,094	79,034,498	40,774,981	-	-	207,620,573
			Total	73,032,549	283,189,038	356,221,587	237,428,066	197,181,217	176,261,853	92,247,184	688,597,087	1,391,715,407

18.3 Secured liabilities

As of December 31, 2016 and 2015, there are no secured liabilities.

      - Fair value measurement and hierarchy

The fair value of current and non-current secured and unsecured liabilities as of December 31, 2016 totaled ThCh$2,296,968,444 (ThCh$1,768,663,119 as of December 31, 2015). These liabilities have been classified as Level 2 fair value measurement based on the entry data used in the valuation techniques used (see Note 3.g). It is important to note that these financial liabilities are measured at amortized cost (see Note 3 f.4).

The accompanying notes are an integral part of these consolidated financial statements.

F-100

- Secured and unsecured liabilities by company

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Secured / Unsecured	December 31, 2016									December 31, 2015
										Corriente			No Corriente						Corriente			No Corriente
										Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
										ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 1ª Serie 16	Brazil	Real	14.39%	14.84%	No	-	-	-	-	-	-	-	-	-	-	10,550,152	10,550,152	-	-	-	-	-	-
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 1ª Serie 17	Brazil	Real	14.87%	14.57%	No	62,046	10,274,671	10,336,717	-	-	-	-	-	-	-	9,072,396	9,072,396	8,960,650	-	-	-	-	8,960,650
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 1ª Serie 18	Brazil	Real	15.39%	15.04%	No	2,240,529	10,274,671	12,515,200	10,274,671	10,274,671	-	-	-	20,549,342	-	1,980,285	1,980,285	8,960,650	8,960,650	8,960,650	-	-	26,881,950
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 2ª Serie 26	Brazil	Real	15.68%	11.69%	No	1,534,749	18,048,629	19,583,378	18,048,629	-	-	-	-	18,048,629	-	16,645,720	16,645,720	14,750,376	14,750,376	-	-	-	29,500,752
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 2ª Serie 27	Brazil	Real	12.99%	10.00%	No	2,686,357	28,037,075	30,723,432	28,017,908	27,977,590	-	-	-	55,995,498	-	2,256,837	2,256,837	22,653,731	22,888,844	22,853,681	-	-	68,396,256
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 2ª Serie 28	Brazil	Real	15.39%	15.04%	No	2,240,529	10,274,671	12,515,200	10,274,671	10,274,671	-	-	-	20,549,342	-	1,980,285	1,980,285	8,960,650	8,960,650	8,960,650	-	-	26,881,950
Foreign	Codensa	Colombia	Foreign	B102 Tramo 1	Colombia	CP	11.58%	11.10%	No	32,857,962	-	32,857,962	-	-	-	-	-	-	480,031	-	480,031	87,436,064	-	-	-	-	87,436,064
Foreign	Codensa	Colombia	Foreign	B102 Tramo 2	Colombia	CP	11.58%	11.10%	No	54,661,809	-	54,661,809	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	B103	Colombia	CP	11.84%	11.35%	No	116,191	-	116,191	17,793,265	-	-	-	-	17,793,265	121,021	-	121,021	-	17,886,817	-	-	-	17,886,817
Foreign	Codensa	Colombia	Foreign	B604	Colombia	CP	10.56%	10.17%	No	-	-	-	-	-	-	-	-	-	32,826,348	-	32,826,348	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Bonos B12-13	Colombia	CP	11.05%	10.62%	No	588,049	-	588,049	-	-	-	-	43,001,874	43,001,874	613,975	-	613,975	-	-	-	-	43,227,965	43,227,965
Foreign	Codensa	Colombia	Foreign	Bonos B5-13	Colombia	CP	10.11%	9.75%	No	507,258	-	507,258	40,404,057	-	-	-	-	40,404,057	531,899	-	531,899	-	40,616,490	-	-	-	40,616,490
Foreign	Codensa	Colombia	Foreign	Bonos B7-14	Colombia	CP	9.70%	9.36%	No	73,860	-	73,860	-	-	-	41,146,926	-	41,146,926	77,582	-	77,582	-	-	-	-	41,363,265	41,363,265
Foreign	Codensa	Colombia	Foreign	Bonos E4-16	Colombia	CP	7.70%	7.49%	No	69,829	-	69,829	-	-	20,017,423	-	-	20,017,423	-	-	-	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Itaú 1	Brazil	Real	15.02%	14.74%	No	-	-	-	-	-	-	-	-	-	-	9,601,388	9,601,388	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Itaú 2	Brazil	Real	14.88%	14.68%	No	781,100	28,801,093	29,582,193	28,802,814	-	-	-	-	28,802,814	-	24,562,682	24,562,682	23,525,037	23,473,978	-	-	-	46,999,015
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.41%	6.31%	No	-	7,856	7,856	-	-	-	-	4,978,152	4,978,152	-	8,221	8,221	-	-	-	-	5,209,304	5,209,304
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.38%	6.28%	No	153,739	-	153,739	-	4,978,152	-	-	-	4,978,152	-	-	-	-	-	5,209,302	-	-	5,209,302
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	US$	6.44%	6.34%	No	182,744	-	182,744	-	-	-	-	6,690,637	6,690,637	194,246	-	194,246	-	-	-	-	7,111,739	7,111,739
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	US$	7.93%	7.78%	No	188,949	-	188,949	-	5,463,574	-	-	-	5,463,574	200,841	-	200,841	-	-	5,807,446	-	-	5,807,446
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	6.73%	6.63%	No	-	-	-	-	-	-	-	-	-	215,945	7,111,739	7,327,684	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	6.09%	6.00%	No	-	-	-	-	-	-	-	-	-	117,344	7,111,739	7,229,083	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	5.86%	5.78%	No	96,701	-	96,701	-	-	6,690,637	-	-	6,690,637	102,787	-	102,787	-	-	-	7,111,739	-	7,111,739
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	6.57%	6.47%	No	182,738	-	182,738	6,690,637	-	-	-	-	6,690,637	194,239	-	194,239	-	7,111,739	-	-	-	7,111,739
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	AFP Horizonte	Peru	Soles	7.22%	7.09%	No	-	-	-	-	-	-	-	-	-	75,209	3,125,581	3,200,790	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	AFP Integra	Peru	Soles	8.16%	8.00%	No	-	-	-	-	-	-	-	-	-	3,899,407	-	3,899,407	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	AFP Integra	Peru	Soles	8.00%	7.85%	No	-	-	-	-	-	-	-	-	-	5,855,385	-	5,855,385	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	AFP Prima	Peru	Soles	7.13%	7.00%	No	-	-	-	-	-	-	-	-	-	-	5,226,830	5,226,830	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	AFP Prima	Peru	Soles	7.44%	7.30%	No	177,720	-	177,720	-	-	5,973,783	-	-	5,973,783	185,972	-	185,972	-	-	-	6,251,163	-	6,251,163
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	FCR - Macrofondo	Peru	Soles	5.56%	5.49%	No	195,375	-	195,375	-	-	-	-	9,956,304	9,956,304	204,447	-	204,447	-	-	-	-	10,418,604	10,418,604
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	FCR - Macrofondo	Peru	Soles	7.03%	6.91%	No	129,121	-	129,121	-	3,982,522	-	-	-	3,982,522	135,116	-	135,116	-	-	4,167,442	-	-	4,167,442
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Interseguro Cia de Seguros	Peru	Soles	6.28%	6.19%	No	-	107,010	107,010	-	-	-	-	7,965,044	7,965,044	-	111,978	111,978	-	-	-	-	8,334,884	8,334,884
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.06%	5.97%	No	-	83,833	83,833	-	-	-	-	9,956,304	9,956,304	-	87,726	87,726	-	-	-	-	10,418,604	10,418,604
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.50%	6.40%	No	-	4,024,228	4,024,228	-	-	-	-	-	-	-	43,642	43,642	4,167,442	-	-	-	-	4,167,442
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	7.06%	6.94%	No	-	6,061,678	6,061,678	-	-	-	-	-	-	-	91,977	91,977	6,251,163	-	-	-	-	6,251,163
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.00%	4.94%	No	-	58,632	58,632	-	-	-	-	7,965,044	7,965,044	-	61,354	61,354	-	-	-	-	8,334,884	8,334,884
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.13%	5.06%	No	219,696	-	219,696	-	-	-	-	9,956,304	9,956,304	229,897	-	229,897	-	-	-	-	10,418,604	10,418,604
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.75%	6.64%	No	237,085	-	237,085	-	-	9,956,304	-	-	9,956,304	248,093	-	248,093	-	-	-	10,418,604	-	10,418,604
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	7.28%	7.15%	No	181,578	-	181,578	-	-	-	-	7,068,976	7,068,976	190,009	-	190,009	-	-	-	-	7,397,209	7,397,209
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.50%	6.40%	No	-	71,907	71,907	-	-	9,956,304	-	-	9,956,304	-	75,245	75,245	-	-	-	10,418,604	-	10,418,604
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	7.38%	7.24%	No	-	97,904	97,904	-	-	-	-	11,947,565	11,947,565	-	102,450	102,450	-	-	-	-	12,502,325	12,502,325
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.78%	6.67%	No	296,321	-	296,321	-	-	-	19,912,609	-	19,912,609	-	310,080	310,080	-	-	-	-	20,837,209	20,837,209
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.34%	6.25%	No	-	37,896	37,896	-	-	-	-	11,947,565	11,947,565	-	39,656	39,656	-	-	-	-	12,502,325	12,502,325
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.84%	5.76%	No	-	58,182	58,182	-	19,912,609	-	-	-	19,912,609	-	60,884	60,884	-	-	20,837,209	-	-	20,837,209
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.34%	6.25%	No	286,327	-	286,327	-	-	-	-	15,930,087	15,930,087	304,643	-	304,643	-	-	-	-	16,669,767	16,669,767
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	4.81%	4.76%	No	-	9,895,020	9,895,020	-	-	-	-	-	-	139,221	-	139,221	10,210,232	-	-	-	-	10,210,232
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.13%	6.03%	No	388,932	-	388,932	-	13,938,826	-	-	-	13,938,826	406,991	-	406,991	-	-	14,586,046	-	-	14,586,046
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.96%	5.87%	No	7,425,025	-	7,425,025	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	8.13%	7.97%	No	324,029	-	324,029	-	-	-	-	13,938,826	13,938,826	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.09%	6.00%	No	586,489	-	586,489	-	-	-	-	19,912,609	19,912,609	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.00%	5.91%	No	187,430	-	187,430	-	-	-	-	14,417,725	14,417,725	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B09-09	Colombia	CP	12.21%	11.69%	No	1,414,523	-	1,414,523	48,531,131	-	-	-	-	48,531,131	1,472,677	-	1,472,677	-	48,781,185	-	-	-	48,781,185
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B10	Colombia	CP	12.08%	11.57%	No	575,721	-	575,721	-	35,599,875	-	-	-	35,599,875	599,598	-	599,598	-	-	35,783,303	-	-	35,783,303
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B-103	Colombia	CP	11.42%	10.86%	No	41,548,575	-	41,548,575	-	-	-	-	-	-	3,893,386	-	3,893,386	38,005,507	-	-	-	-	38,005,507
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B12	Colombia	CP	12.42%	11.88%	No	590,356	-	590,356	-	-	-	19,924,009	-	19,924,009	614,301	-	614,301	-	-	-	-	20,026,666	20,026,666
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B15	Colombia	CP	12.41%	11.88%	No	204,822	-	204,822	-	-	-	-	12,344,078	12,344,078	213,136	-	213,136	-	-	-	-	12,407,680	12,407,680
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B6-13	Colombia	CP	10.46%	10.07%	No	63,737	-	63,737	-	10,991,188	-	-	-	10,991,188	66,722	-	66,722	-	-	11,047,324	-	-	11,047,324
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B6-14	Colombia	CP	9.58%	9.26%	No	285,466	-	285,466	-	-	24,448,627	-	-	24,448,627	299,818	-	299,818	-	-	-	24,573,172	-	24,573,172
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos exterior	Colombia	CP	10.17%	10.17%	No	1,902,736	-	1,902,736	-	-	-	20,017,423	-	20,017,423	13,745,374	-	13,745,374	-	-	-	-	19,368,586	19,368,586
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos quimbo	Colombia	CP	10.17%	10.17%	No	13,673,482	-	13,673,482	-	-	-	143,221,662	-	143,221,662	1,912,740	-	1,912,740	-	-	-	-	144,605,973	144,605,973
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B10	Colombia	CP	9.69%	9.35%	No	324,929	-	324,929	-	-	-	-	66,675,529	66,675,529	341,157	-	341,157	-	-	-	-	67,020,604	67,020,604
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B10-14	Colombia	CP	10.02%	9.66%	No	504,981	-	504,981	-	-	-	-	41,423,665	41,423,665	529,437	-	529,437	-	-	-	-	41,638,617	41,638,617
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B12-13	Colombia	CP	11.26%	10.81%	No	502,166	-	502,166	-	-	-	-	80,682,512	80,682,512	524,321	-	524,321	-	-	-	-	81,102,939	81,102,939
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B15	Colombia	CP	9.82%	9.47%	No	219,362	-	219,362	-	-	-	-	44,443,548	44,443,548	230,201	-	230,201	-	-	-	-	44,675,420	44,675,420
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B16-14	Colombia	CP	10.36%	9.98%	No	454,529	-	454,529	-	-	-	-	36,108,963	36,108,963	475,939	-	475,939	-	-	-	-	36,297,343	36,297,343
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B6-13	Colombia	CP	10.46%	10.07%	No	196,638	-	196,638	-	33,909,218	-	-	-	33,909,218	205,848	-	205,848	-	-	34,082,658	-	-	34,082,658
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B6-14	Colombia	CP	9.58%	9.26%	No	340,146	-	340,146	-	-	29,131,138	-	-	29,131,138	357,246	-	357,246	-	-	-	29,279,709	-	29,279,709
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B3-16	Colombia	CP	9.66%	9.33%	No	681,016	-	681,016	-	52,186,348	-	-	-	52,186,348	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B7-16	Colombia	CP	10.93%	10.51%	No	947,630	-	947,630	-	-	-	-	64,452,160	64,452,160	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos E7-16	Colombia	CP	7.59%	7.38%	No	67,455	-	67,455	-	-	-	-	66,635,409	66,635,409	-	-	-	-	-	-	-	-	-
94.271.000-3	Enel Américas S.A.	Chile	97.036.000-k	Bonos UF 269	Chile	U.F.	7.02%	5.75%	No	-	3,702,837	3,702,837	3,855,689	4,077,390	4,311,838	4,559,767	1,886,118	18,690,802	-	3,417,313	3,417,313	3,546,564	3,750,488	3,966,142	4,194,193	6,097,254	21,554,641
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Yankee Bonds (maturity 2016)	EE.UU.	US$	7.76%	7.40%	No	-	-	-	-	-	-	-	-	-	-	179,549,527	179,549,527	-	-	-	-	-	-
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Yankee Bonds (US$ 600 millones)	E.E.U.U.	US$	4.21%	4.00%	No	-	2,945,668	2,945,668	-	-	-	-	388,386,448	388,386,448	-	-	-	-	-	-	-	-	-
94.271.000-3	Enel Américas S.A.	Chile	Foreign	Yankee Bonds (maturity 2026)	E.E.U.U.	US$	7.76%	6.60%	No	-	3,159	3,159	-	-	-	-	574,405	574,405	-	3,351	3,351	-	-	-	-	609,317	609,317
Total										174,358,537	132,866,620	307,225,157	212,693,472	233,566,634	110,486,054	248,782,396	999,245,851	1,804,774,407	73,032,549	283,189,038	356,221,587	237,428,066	197,181,217	176,261,853	92,247,184	688,597,087	1,391,715,407

Appendix 4, letter b), shows the estimated future cash flows (undiscounted) that the Group will have to disburse to settle the secured and unsecured liabilities detailed above.

The accompanying notes are an integral part of these consolidated financial statements.

F-101

- Detail of finance lease obligations

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Nominal Interest Rate	December 31, 2016									December 31, 2015
								Current			Non-Current						Current			Non-Current
								Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
								ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Codensa	Colombia	Foreign	Union Temporal Rentacol	Colombia	CP	10.80%	121,929	271,883	393,812	-	-	-	-	-	-	62,967	199,380	262,347	266,565	-	-	-	-	266,565
Foreign	Codensa	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP	10.98%	11,740	37,293	49,033	45,686	46,609	34,235	-	-	126,530	2,598	8,198	10,796	11,936	6,433	-	-	-	18,369
Foreign	Codensa	Colombia	Foreign	Banco Corpbanca	Colombia	CP	7.36%	11,413	23,470	34,883	13,778	-	-	-	-	13,778	19,831	31,119	50,950	22,853	13,512	-	-	-	36,365
Foreign	Codensa	Colombia	Foreign	Consorcio Empresarial	Colombia	CP	7.08%	61,371	189,003	250,374	200,636	-	-	-	-	200,636	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Equirent S.A.	Colombia	CP	9.54%	5,968	18,774	24,742	25,474	29,664	24,143	-	-	79,281	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Transportes Especializados JR S.A.S.	Colombia	CP	9.48%	2,609	8,208	10,817	11,135	10,708	-	-	-	21,843	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	5.29%	-	-	-	-	-	-	-	-	-	110,707	-	110,707	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.98%	-	-	-	-	-	-	-	-	-	85,240	178,308	263,548	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.00%	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.00%	-	-	-	-	-	-	-	-	-	77,976	239,624	317,600	-	-	-	-	-	-
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.98%	33,255	-	33,255	-	-	-	-	-	-	73,719	225,872	299,591	12,084	-	-	-	-	12,084
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.60%	268,393	807,131	1,075,524	557,663	-	-	-	-	557,663	65,285	199,365	264,650	89,743	-	-	-	-	89,743
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Santander Perú	Peru	Soles	5.13%	152,394	469,953	622,347	161,004	-	-	-	-	161,004	153,549	472,612	626,161	659,036	-	-	-	-	659,036
Foreign	Enel Generación Piura S.A. (formerly named EE Piura)	Peru	Foreign	Banco de Crédito	Peru	US$	5.80%	1,325,072	3,975,215	5,300,287	5,300,288	5,300,288	13,577,447	-	-	24,178,023	1,408,471	4,225,412	5,633,883	5,633,883	5,633,883	5,633,883	14,432,002	-	31,333,651
Foreign	Enel Generación Piura S.A. (formerly named EE Piura)	Peru	Foreign	Banco de Crédito	Peru	Soles	5.70%	-	1,815,173	1,815,173	1,815,173	1,815,173	4,649,826	-	-	8,280,172	474,864	1,424,592	1,899,456	1,899,456	1,899,456	1,899,456	4,865,731	-	10,564,099
Foreign	Enel Generación Piura S.A. (formerly named EE Piura)	Peru	Foreign	Banco Scotiabank	Peru	US$	3.75%	44,304	3,485,148	3,529,452	4,646,865	4,646,865	4,646,865	4,646,865	1,161,716	19,749,176	-	-	-	-	-	-	-	-	-
Foreign	Enel Generación Piura S.A. (formerly named EE Piura)	Peru	Foreign	Banco de Crédito	Peru	US$	3.63%	3,266	89,768	93,034	463,100	386,023	198,356			1,047,479	-	-	-	-	-	-	-	-	-
Foreign	Enel Generación Perú S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	2.75%	14,744,589	-	14,744,589	-	-	-	-	-	-	2,484,674	7,399,875	9,884,549	15,599,736	-	-	-	-	15,599,736
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco Corpbanca	Colombia	CP	8.40%	5,476	13,924	19,400	13,569	-	-	-	-	13,569	4,579	14,234	18,813	20,200	19,819	-	-	-	40,019
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Equirent S.A.	Colombia	CP	7.70%	41,044	127,223	168,267	162,815	166,733	11,225	-	-	340,773	5,424	16,795	22,219	23,718	19,648	-	-	-	43,366
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP	10.98%	5,315	16,896	22,211	22,613	23,535	15,048	-	-	61,196	795	2,372	3,167	3,650	3,217	-	-	-	6,867
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Transportes Especializados JR S.A.S.	Colombia	CP	11.69%	59,265	192,760	252,025	273,020	251,945	-	-	-	524,965	-	-		-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Consorcio Empresarial	Colombia	CP	7.08%	2,182	6,783	8,965	6,615	-	-	-	-	6,615	-	-		-	-	-	-	-	-
			Total					16,899,585	11,548,605	28,448,190	13,719,434	12,677,543	23,157,145	4,646,865	1,161,716	55,362,703	5,030,679	14,637,758	19,668,437	24,242,860	7,595,968	7,533,339	19,297,733	-	58,669,900

Appendix 4 letter c), shows the estimated future cash flows (undiscounted) that the Group will have to disburse to settle the finance lease obligations detailed above.

- Detail of other obligations

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Nominal Interest Rate	December 31, 2016									December 31, 2015
								Current			Non-Current						Current			Non-Current
								Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
								ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Ampla Energía S.A.	Brazil	Foreign	BNDES	Brazil	Real	9.17%	-	-	-	-	-	-	-	-	-	4,668,542	16,155,634	20,824,176	22,376,436	18,904,213	15,431,989	11,215,453	8,186,564	76,114,655
Foreign	Enel Cien S.A. (formerly named Cien S.A.)	Brazil	Foreign	BNDES	Brazil	Real	8.33%	-	-	-	-	-	-	-	-	-	215,214	659,135	874,349	860,857	860,857	860,857	430,428	-	3,012,999
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	Real	7.85%	-	-	-	-	-	-	-	-	-	951,507	2,896,151	3,847,658	3,806,030	3,806,030	951,507	-	-	8,563,567
Foreign	Coelce S.A.	Brazil	Foreign	Eletrobras	Brazil	Real	6.08%	430,434	1,281,812	1,712,246	1,589,999	1,459,832	1,244,048	909,553	775,930	5,979,362	559,718	1,259,783	1,819,501	1,489,541	1,383,305	1,269,785	1,081,597	1,488,913	6,713,141
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Brazil	Brazil	US$	52.56%	-	-	-	-	-	-	-	-	-	-	17,520	17,520	-	-	-	-	1,942,995	1,942,995
Foreign	Coelce S.A.	Brazil	Foreign	BNDES	Brazil	Real	10.43%	-	-	-	-	-	-	-	-	-	1,350,117	5,050,186	6,400,303	7,193,099	7,193,099	7,193,099	4,862,156	3,639,085	30,080,538
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Mitsubishi (deuda garantizada)	Argentina	US$	0.25%	-	2,014,913	2,014,913	2,006,396	2,006,396	2,006,396	2,006,396	24,071,963	32,097,547	-	2,153,867	2,153,867	2,144,288	2,144,288	2,144,288	2,144,288	24,342,682	32,919,834
Foreign	Hidroinvest S.A.	Argentina	Foreign	Otros	Argentina	US$	2.53%	371,817	-	371,817	-	-	-	-	-	-	-	391,530	391,530	-	-	-	-	-	-
Foreign	Enel Argentina S.A. (formerly named Endesa Argentina S.A.)	Argentina	Foreign	Otros	Argentina	Ar$	34.00%	-	-	-	-	-	-	-	-	-	23,515	-	23,515	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Otros	Argentina	Ar$	28.78%	-	-	-	-	-	-	-	-	-	16,912,466	-	16,912,466	4,636,665	-	-	-	-	4,636,665
		Total						802,251	3,296,725	4,098,976	3,596,395	3,466,228	3,250,444	2,915,949	24,847,893	38,076,909	24,681,079	28,583,806	53,264,885	42,506,916	34,291,792	27,851,525	19,733,922	39,600,239	163,984,394

Appendix 4 letter d), shows the estimated future cash flows (undiscounted) that the Group will have to disburse to settle these Other Obligations.

The accompanying notes are an integral part of these consolidated financial statements.

F-102

18.4 Hedged debt

The debt denominated in U.S. dollar for ThCh$106,418,951 held by the Group as of December 31, 2016, is related to future cash flow hedges for the Group’s U.S. dollar-linked operating revenues (ThCh$933,447,012 as of December 31, 2015, of which ThCh$119,366,828 corresponded to continuing operations) (see Note 3.m).

The following table details changes in “Reserve for cash flow hedges” for the years ended December 31, 2016, 2015 and 2014, due to exchange differences from this debt:

	12-31-2016	12-31-2015	12-31-2014
	ThCh$	ThCh$	ThCh$
Balance in hedging reserves (hedging revenues) at the beginning of the year, net	(5,732,192)	(38,783,599)	2,415,439
Foreign currency exchange differences recorded in equity, net	122,075	(44,992,798)	(31,401,584)
Recognition of foreign currency exchange differences revenue, net	(152,075)	3,172,291	(10,086,797)
Foreign currency translation differences	387,959	(81,479)	289,343
Transfer to assets held for distribution to owners	-	74,953,393	-
Other	(2,367,974)	-	-
Balance in hedging reserves (hedging revenues) at the end of the year, net	(7,742,207)	(5,732,192)	(38,783,599)

18.5 Other information

As of December 31, 2016, the Group has long-term lines of credit available for use amounting to ThCh$86,993,868 (ThCh$34,332,376 as of December 31, 2015)

The accompanying notes are an integral part of these consolidated financial statements.

F-103

19. RISK MANAGEMENT POLICY

The Group’s companies are exposed to certain risks that are managed by systems that identify, measure, limit concentration of, and monitor these risks.

The main principles in the Group’s risk management policy include the following:

-     Compliance with proper corporate governance standards.

-     Strict compliance with all of Group’s internal policies.

-     Each business and corporate area determines:

  I. The markets in which it can operate based on its knowledge and ability to ensure effective risk management;

 II. Criteria regarding counterparts;

III. Authorized operators.

- Business and corporate areas establish their risk tolerance in a manner consistent with the defined strategy for each market in which they operate.

- All of the operations of the businesses and corporate areas are conducted within the limits approved for each case.

- Businesses, corporate areas, lines of business and companies design the risk management controls necessary to ensure that transactions in the markets are conducted in accordance with the Group’s policies, standards, and procedures.

19.1 Interest rate risk

Changes in interest rates affect the fair value of assets and liabilities bearing fixed interest rates, as well as, the expected future cash flows of assets and liabilities subject to floating interest rates.

The objective of managing interest rate risk exposure is to achieve a balance in the debt structure to minimize the cost of debt with reduced volatility in profit or loss.

Depending on the Group’s estimates and the objectives of the debt structure, hedging transactions are performed by entering into derivatives contracts that mitigate interest rate risk. Derivative instruments currently used to comply with the risk management policy are interest rate swaps to set floating rate to a fixed rate.

The financial debt structure of the Group detailed by the mostly strongly hedged fixed and floating interest rates on total net debt, net of hedging derivative instruments, is as follows:

Net position:

	12-31-2016	12-31-2015
	%	%
Fixed interest rate debt	44%	30%

The accompanying notes are an integral part of these consolidated financial statements.

F-104

19.2 Exchange rate risk

Exchange rate risks involve basically the following transactions:

- Debt taken on by the Group’s companies that is denominated in a currency other than the currency in which its cash flows are indexed.

- Payments to be made in a currency other than that in which its cash flows are indexed for the acquisition of project-related materials and for corporate insurance policies.

- Income in Group companies directly linked to changes in currencies other than the currency of its cash flows.

- Cash flows from foreign subsidiaries to the Chilean parent company which are exposed to exchange rate fluctuations.

In order to mitigate foreign currency risk, the Group’s foreign currency risk management policy is based on cash flows and includes maintaining a balance between U.S. dollar flows and the levels of assets and liabilities denominated in this currency. The objective is to minimize the exposure to variability in cash flows that are attributable to foreign exchange risk.

The hedging instruments currently being used to comply with the policy are currency swaps and forward exchange contracts. In addition, the policy pursues to refinance debt in the functional currency of each of the Group’s companies.

19.3 Commodities risk

The Group has a risk exposure to price fluctuations in certain commodities, basically due to:

- Purchases of fuel used to generate electricity.

- Energy purchase/sale transactions that take place in local markets.

In order to reduce the risk in situations of extreme drought, the Group has designed a commercial policy that defines the levels of sales commitments in line with the capacity of its generating power plants in a dry year. It also includes risk mitigation terms in certain contracts with unregulated customers and with regulated customers subject to long-term tender processes, establishing indexation polynomials that allow for reducing commodities exposure risk.

Considering the operating conditions faced by the power generation market in Chile, with drought and highly volatile commodity prices on international markets, the Company is constantly evaluating the use of hedging to minimize the impacts that these price fluctuations have on its results. As of December 31, 2016, there are transactions of purchases of energy futures contracts for 69.84 GWh for the period January-December 2017. Such purchases cover an energy sales contract in the wholesale market. On the other hand, sales transactions of energy futures contracts for 15.12 GWh were made for the period January-December 2017 to cover cash flow risk of the customers indexed to the unregulated market. As of December 31, 2016, ten energy futures contracts and one energy future contract were each settled for 0.36 GWh. As of December 31, 2015, there were no commodity derivatives transactions.

19.4 Liquidity risk

The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets.

The projected needs mentioned above include maturities of financial debt net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial derivatives (see Notes 18, 20, and Appendix 4).

As of December 31, 2016, the Group has cash and cash equivalents for ThCh$1,800,510,297 and unconditionally available lines of long-term credit for ThCh$86,993,868. As of December 31, 2015, the Group had cash and cash equivalents for ThCh$1,185,163,344 and unconditionally available lines of long-term credit for ThCh$34,332,376.

The accompanying notes are an integral part of these consolidated financial statements.

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19.5 Credit risk

The Group closely monitors its credit risk.

Trade receivables:

The credit risk for receivables from the Group’s commercial activity has historically been very low, due to the short term period of collections from customers, resulting in non-significant cumulative receivables amounts. This situation applies to the electricity generating and distribution lines of business.

In our electricity generating business, some countries’ regulations allow suspending the energy service to customers with outstanding payments, and most contracts have termination clauses for payment default. The Company monitors its credit risk on an ongoing basis and measures quantitatively its maximum exposure to payment default risk, which, as stated above, is very low.

In our electricity distribution companies, the suspension of energy service to customers in payment default is permitted in all cases, in accordance with current regulations in each country. This facilitates our credit risk management, which is also low in this line of business.

Financial assets:

Cash surpluses are invested in the highest-rated local and foreign financial entities (with risk rating equivalent to investment grade where possible) with thresholds established for each entity.

Banks that have received investment grade ratings from the three major international rating agencies (Moody’s, S&P, and Fitch) are selected for making investments.

Investments may be backed with treasury bonds from the countries in which the company operates and/or with commercial papers issued by the highest rated banks; the latter are preferable as they offer higher returns (always in line with current investment policies).

Derivative instruments are entered into with entities with solid creditworthiness; all derivative transactions are performed with entities with investment grade ratings.

19.6 Risk measurement

The Group measures the Value at Risk (VaR) of its debt positions and financial derivatives in order to monitor the risk assumed by the Company, thereby reducing volatility in the income statement.

The portfolio of positions included for purposes of calculating the present Value at Risk include:

- Financial debt

- Hedge derivatives for debt

The VaR determined represents the potential variation in value of the portfolio of positions described above in a quarter with a 95% confidence level. To determine the VaR, we take into account the volatility of the risk variables affecting the value of the portfolio of positions, with respect to the Chilean peso, including:

- U.S. dollar Libor interest rate.

The accompanying notes are an integral part of these consolidated financial statements.

F-106

- The different currencies with which our companies operate and the customary local indices used in the banking industry.

- The exchange rates of the various currencies used in the calculation.

The calculation of VaR is based on generating possible future scenarios (at one quarter) of market values (both spot and term) for the risk variables, using Bootstrapping simulations.

The quarter 95%-confidence VaR number is calculated as the 5% percentile most adverse of the quarterly possible fluctuations.

Taking into consideration the assumptions previously described, the quarter VaR of the previously discussed positions was ThCh$112,729,307.

This value represents the potential increase of the Debt and Derivatives’ Portfolio, thus these Values at Risk are inherently related, among other factors, to the Portfolio’s value at each quarter end.

The accompanying notes are an integral part of these consolidated financial statements.

F-107

20. FINANCIAL INSTRUMENTS

20.1 Financial instruments, classified by type and category

a) The detail of financial assets, classified by type and category, as of December 31, 2016 and 2015, is as follows:

	December 31, 2016
	Financial assets held for trading	Financial assets at fair value through profit or loss	Held-to-maturity investments	Loans and receivables	Available-for-sale financial asssets	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Derivative instruments	21,825,932	-	-	-	-	173,106
Other financial assets	-	44,019,453	25,201,114	1,038,079,067	-	-
Total Current	21,825,932	44,019,453	25,201,114	1,038,079,067	-	173,106
Equity instrumentos	-	-	-	-	1,277,058	-
Other financial assets	-	320,461	36,272	318,332,881	687,458,647	-
Total Non-Current	-	320,461	36,272	318,332,881	688,735,705	-
Total	21,825,932	44,339,914	25,237,386	1,356,411,948	688,735,705	173,106
	December 31, 2015
	Financial assets held for trading	Financial assets at fair value through profit or loss	Held-to-maturity investments	Loans and receivables	Available-for-sale financial assets	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Derivative instruments	4,427,286	-	-	-	-	1,172,125
Other financial assets	-	35,467,539	27,195,496	1,045,820,479	-	-
Total Current	4,427,286	35,467,539	27,195,496	1,045,820,479	-	1,172,125
Equity instruments	-	-	-	-	616,296	-
Derivative instruments	-	-	-	-	-	978,556
Other financial assets	-	-	39,673	364,516,870	487,893,679	-
Total Non-Current	-	-	39,673	364,516,870	488,509,975	978,556
Total	4,427,286	35,467,539	27,235,169	1,410,337,349	488,509,975	2,150,681

The accompanying notes are an integral part of these consolidated financial statements.

F-108

b) The detail of financial liabilities, classified by type and category, as of December 31, 2016 and 2015, is as follows:

	December 31, 2016
	Financial liabilities held for trading	Loans and payables	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$
Interest-bearing loans	638,836	497,276,645	-
Derivative instruments	3,237,240	-	3,531,642
Other financial liabilities	-	1,657,944,574	-
Total Current	3,876,076	2,155,221,219	3,531,642
Interest-bearing loans	76,648,045	2,309,358,632	-
Derivative instrumentos	-	-	10,747,217
Other financial liabilities	-	296,322,235	-
Total Non-Current	76,648,045	2,605,680,867	10,747,217
Total	80,524,121	4,760,902,086	14,278,859
	December 31, 2015
	Financial liabilities held for trading	Loans and payables	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$
Interest-bearing loans	-	617,276,453	-
Derivative instruments	1,052,026	-	69,545,029
Other financial liabilities	-	1,447,306,354	-
Total Current	1,052,026	2,064,582,807	69,545,029
Interest-bearing loans	-	1,846,995,721	-
Derivative instruments	-	-	300,871
Other financial liabilities	-	244,079,004	-
Total Non-Current	-	2,091,074,725	300,871
Total	1,052,026	4,155,657,532	69,845,900

The accompanying notes are an integral part of these consolidated financial statements.

F-109

20.2 Derivative instruments

The risk management policy of the Group uses primarily interest rate and foreign exchange rate derivatives to hedge its exposure to interest rate and foreign currency risks.

The Company classifies its hedges as follows:

- Cash flow hedges: Those that hedge the cash flows of the underlying hedged item.

- Fair value hedges: Those that hedge the fair value of the underlying hedged item.

-      Non-hedge derivatives: Financial derivatives that do not meet the requirements established by IFRS to be designated as hedging instruments are recognized at fair value through profit or loss (financial assets held for trading).

a) Assets and liabilities for hedge derivative instruments

As of December 31, 2016 and 2015, financial derivative qualifying as hedging instruments resulted in recognition of the following assets and liabilities in the statement of financial position:

	December 31, 2016				December 31, 2015
	Asset		Liability		Asset		Liability
	Current	Non-Current	Current	Non-Current	Current	Non-Current	Current	Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	166,155	-	40,207	-	908,115	978,556	11,177	300,871
Cash flow hedge	166,155	-	40,207	-	908,115	978,556	11,177	300,871
Exchange rate hedge:	6,951	-	3,491,435	10,747,217	264,010	-	69,533,852	-
Cash flow hedge	6,951	-	-	-	264,010	-	69,533,852	-
Fair value hedge	-	-	3,491,435	10,747,217	-	-	-	-
TOTAL	173,106	-	3,531,642	10,747,217	1,172,125	978,556	69,545,029	300,871

-           General information on hedge derivative instruments

Hedging derivative instruments and their corresponding hedged instruments are shown in the following table:

Type of Hedge Instrument	Description of hedged risk	Description of hedged item	Fair Value of Hedged Item 12-31-2016 ThCh$	Fair Value of Hedged Item 12-31-2015 ThCh$
SWAP	Interest rate	Bank loans	(13,523,416)	(298,743)
SWAP	Interest rate	Unsecured obligations (bonds)	(40,207)	1,873,366
SWAP	Exchange rate	Bank loans	4,151	(314,746)
SWAP	Exchange rate	Bank loans	162,006	-
SWAP	Exchange rate	Unsecured obligations (bonds)	-	(67,966,043)
FORWARD	Exchange rate	Other	-	(19,920)
FORWARD	Exchange rate	Unsecured obligations (bonds)	6,951	-
FORWARD	Exchange rate	Operating costs	(715,238)	(969,133)

As of December 31, 2016 and 2015, the Group has not recognized significant gains or losses for ineffective cash flow hedges.

For fair value hedges, the gain or losses on the hedging derivative instrument and on the underlying hedged item recognized during the years ended December 31, 2016, 2015 and 2014, is detailed in the following table:

	December 31, 2016		December 31, 2015		December 31, 2104
	Gains Th$	Losses ThCh$	Gains Th$	Losses ThCh$	Gains Th$	Losses ThCh$
Hedging derivative instrument	5,622,666	-	-	-	610,861	-
Underlying hedged item	-	5,763,802	-	-	-	1,090,341
TOTAL	5,622,666	5,763,802	-	-	610,861	1,090,341

The accompanying notes are an integral part of these consolidated financial statements.

F-110

b) Financial derivative instruments assets and liabilities at fair value through profit or loss

As of December 31, 2016 and 2015, financial derivative transactions recognized at fair value through profit or loss, resulted in the recognition of the following assets and liabilities in the statement of financial position:

	December 31, 2016				December 31, 2015
	Assets	Liabilities	Assets	Liabilities	Assets	Liabilities	Assets	Liabilities
	Current ThCh$	Non-Current ThCh$	Current ThCh$	Non-Current ThCh$	Current ThCh$	Non-Current ThCh$	Current ThCh$	Non-Current ThCh$
Non-hedging derivative instrument (1)	21,825,932	3,237,240	-	-	4,427,286	1,052,026	-	-

(1) Includes forward contracts entered into by the Group mainly to hedge foreign exchange risk related to dividends received or to be received from its foreign subsidiaries. Although, the hedge relationship has economic substance, they do not comply with all the hedging documentation requirements set forth by IAS 39 Financial Instruments: Recognition and Measurement to qualify for hedge accounting. Also, it includes cross currency swaps to cover the interest rate and foreign exchange risks of financial debts which as part of the corporate reorganization were transferred to Enel Chile, thus, discontinuing the hedge accounting.

c) Other information on derivatives:

The following table sets forth the fair value of hedging and non-hedging derivatives entered into by the Group as well as the remaining contractual maturities as of December 31, 2016 and 2015:

Financial Derivatives	December 31, 2016
	Fair value	Notional amount
		Less than 1 year	1 - 2 years	2 - 3 years	3 - 4 years	4 - 5 years	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	125,948	22,734,662	-	-	-	-	22,734,662
Cash flow hedge	125,948	22,734,662	-	-	-	-	22,734,662
Exchange rate hedge:	(14,231,701)	9,195,235	30,812,341	57,047,508	-	-	97,055,084
Cash flow hedge	6,951	4,609,114	-	-	-	-	4,609,114
Fair value hedge	(14,238,652)	4,586,121	30,812,341	57,047,508	-	-	92,445,970
Derivatives not designated for hedge accounting	18,588,692	1,000,566,439	-	-	-	-	1,000,566,439
TOTAL	4,482,939	1,032,496,336	30,812,341	57,047,508	-	-	1,120,356,185
Financial Derivatives	December 31, 2015
	Fair value	Notional Amount
		Less than 1 year	1 - 2 years	2 - 3 years	3 - 4 years	4 - 5 years	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	1,574,623	38,204,658	22,314,853	-	-	-	60,519,511
Cash flow hedge	1,574,623	38,204,658	22,314,853	-	-	-	60,519,511
Exchange rate hedge:	(69,269,842)	308,412,252	-	-	-	-	308,412,252
Cash flow hedge	(69,269,842)	308,412,252	-	-	-	-	308,412,252
Derivatives not designated for hedge accounting	3,375,260	44,663,462	-	-	-	-	44,663,462
TOTAL	(64,319,959)	391,280,372	22,314,853	-	-	-	413,595,225

The hedging and non-hedging derivatives contractual maturities do not represent the Group’s total risk exposure, as the amounts presented in the above tables have been drawn up based on undiscounted contractual cash inflows and outflows for their settlement.

The accompanying notes are an integral part of these consolidated financial statements.

F-111

20.3 Fair value hierarchies

Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the hierarchies described in Note 3.g.

The following table presents financial assets and liabilities measured at fair value as of December 31, 2016 and 2015:

Financial Instruments Measured at Fair Value		Fair Value Measured at End of Reporting  Period Using:
	12-31-2016	Level 1	Level 2	Level 3
	ThCh$	ThCh$	ThCh$	ThCh$
Financial Assets
Financial derivatives designated as cash flow hedge	208,353	35,247	173,106	-
Financial derivatives not designated for hedge accounting	21,825,932	-	21,825,932	-
Financial assets at fair value through profit or loss	43,013,881	43,013,881	-	-
Available-for-sale financial assets, non-current	687,458,647	-	687,458,647	-
Total	752,506,813	43,049,128	709,457,685	-
Financial Liabilities
Financial derivatives designated as cash flow hedge	40,207	-	40,207	-
Financial derivatives designated as fair value hedge	14,245,229	6,577	14,238,652	-
Financial derivatives not designated for hedge accounting	3,237,240	-	3,237,240	-
Interest-bearing borrowings short term	638,836	-	638,836	-
Interest-bearing borrowings long term	76,648,045	-	76,648,045	-
Total	94,809,557	6,577	94,802,980	-
Financial Instruments Measured at Fair Value		Fair Value Measured at End of Reporting  Period Using:
	12-31-2015	Level 1	Level 2	Level 3
	ThCh$	ThCh$	ThCh$	ThCh$
Financial Assets
Financial derivatives designated as cash flow hedge	2,150,681	-	2,150,681	-
Financial derivatives not designated for hedge accounting	4,427,286	-	4,427,286	-
Commodity derivatives designated as cash flow hedge	-	-	-	-
Financial assets at fair value through profit or loss	35,467,539	35,467,539	-	-
Available-for-sale financial assets, non-current	487,893,679	-	487,893,679	-
Total	529,939,185	35,467,539	494,471,646	-
Financial Liabilities
Financial derivatives designated as cash flow hedge	69,845,900	-	69,845,900	-
Financial derivatives not designated for hedge accounting	1,052,026	-	1,052,026	-
Total	70,897,926	-	70,897,926	-

20.3.1 Financial instruments whose fair value measurement is classified as Level 3:

The Group does not have financial instruments measured at fair value whose fair value measurement is classified as Level 3.

The accompanying notes are an integral part of these consolidated financial statements.

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21. TRADE AND OTHER CURRENT PAYABLES

The detail of Trade and Other Payables as of December 31, 2016 and 2015, is as follows:

	Current		Non-Current
Trade and Other Payables	12-31-2016	12-31-2015	12-31-2016	12-31-2015
	ThCh$	ThCh$	ThCh$	ThCh$
Trade payables	397,280,153	414,404,744	-	2,247,156
Other payables	1,258,060,722	1,038,419,463	342,774,881	281,297,098
Total	1,655,340,875	1,452,824,207	342,774,881	283,544,254

The detail of Trade and Other Current Payables as of December 31, 2016 and 2015, is as follows:

	Current		Non-Current
			One to five years
Trade and other payables	12-31-2016	12-31-2015	12-31-2016	12-31-2015
	ThCh$	ThCh$	ThCh$	ThCh$
Energy suppliers	224,351,585	261,183,792	-	2,247,156
Fuel and gas suppliers	31,458,051	39,116,975	-	-
Payables for goods and services	542,003,125	446,669,578	18,213,568	18,190,772
Dividends payable to non-controlling interests	93,004,708	106,531,865	-	-
Fines and complaints (2)	115,424,845	94,165,502	-	-
Research and development	13,874,757	12,867,918	23,049,578	17,940,704
Taxes payables other than income tax	200,329,207	86,077,354	50,949	2,648,714
VAT debit	42,054,243	43,676,292	46,401,697	39,465,249
Mitsubishi contract (LTSA)	15,451,101	15,390,966	-	-
Obligations for social programs	103,141,064	69,506,842	2,664,078	2,567,956
Payables to CAMMESA (1)	222,837,956	218,839,805	233,322,967	187,895,235
Other payables	51,410,233	58,797,318	19,072,044	12,588,468
Total	1,655,340,875	1,452,824,207	342,774,881	283,544,254

See Note 19.4 for the description of the liquidity risk management policy.

(1) As of December 31, 2016, the balance includes ThCh$197,830,539 from our subsidiary Edesur related to the payables for energy purchases from CAMMESA (ThCh$142,620,396 as of December 31, 2015). In addition, it included a total amount of ThCh$ 258,330,384 (ThCh$ 261,114,644 as of December 31, 2015) related to the loan agreements signed with CAMMESA for (i) financing the functional operational needs of the power generating plant of our subsidiary Enel Generación Costanera, which payment will be made in 48 equal monthly installments with a 12-month grace period, at the earlier of the last partial funds advance or December 31, 2016; (ii) financing the maintenance needs of the turbosteam generators in our subsidiary Dock Sud, which payment will be made in 12 equal monthly installments with a 12-month grace period, after completion of maintenance works; and (iii) financing the Extraordinary Investment Plan in our subsidiary Edesur. The repayment is subject to Edesur’s economic and financial sustainability conditions as determined by the Secretary of Energy, which is pending resolution.

(2) Corresponds mainly to fines and complaints that our Argentine subsidiary Edesur S.A. has received during the current and prior years from the regulatory agency due to business service quality, technical product quality, and public safety. These fines have not been paid, as some were suspended under the Agreement Act signed in 2007 with the Argentine government, and others are pending until the Integral Tariff Review (“RTI” in its Spanish acronym) takes place, the amount of these fines and complaints is updated in line with the adjustments to the value added from distribution as part of tariff reviews. For the year ended December 31, 2016, as a result of application of ENRE Resolution No. 1/2016, financial update of those fines and complaints resulted in a finance cost for ThCh$47,110,667 (see Notes 31 and 33.5).

The detail of trade payables, both up to date and past due as of December 31, 2016 and 2015, are presented in Appendix 7.

The accompanying notes are an integral part of these consolidated financial statements.

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22. PROVISIONS

a) The detail of provisions as of December 31, 2016 and 2015, is as follows:

Provisions	Current		Non-Current
	12-31-2016	12-31-2015	12-31-2016	12-31-2015
	ThCh$	ThCh$	ThCh$	ThCh$
Provisions for legal proceedings	81,033,865	42,090,525	185,008,080	144,855,586
Decomissioning or restoration (*)	2,365,398	750,345	7,864,139	6,328,957
Provision for environmental issues (**)	19,004,466	73,381,544	40,291,360	31,880,082
Other provisions	17,609,716	11,076,762	115,907	783,659
Total	120,013,445	127,299,176	233,279,486	183,848,284

(*) It includes the provision for restoration of our subsidiary Emgesa related to the El Quimbo Project, regarding the necessary works to mitigate the environmental impact of filling the dam. The works are estimated to take 30 years. The main activities under this obligation, among other things, are forest restoration, border protection, lotic and fishing programs and flora and fauna monitoring programs.

(**) It includes obligations for the environmental license for the El Quimbo Project, such as settlement of contracts for completed works and minor works necessary to operate the power plant.

The expected timing and amount of any cash outflows related to the above provisions is uncertain and depends on the final resolution of the related matters.

b) Changes in provisions for the years ended December 31, 2016 and 2015, are as follows:

Provisions	Legal Proceedings	Decommissioning or Restoration	Environmental Issues and Other Provisions	Total
	ThCh$	ThCh$	ThCh$	ThCh$
Changes in Provisions
Balance as of January 1, 2016	186,946,111	7,079,302	117,122,047	311,147,460
Increase (decrease) in existing provisions	77,486,339	1,554,158	20,929,913	99,970,410
Provision used	(38,474,142)	(836,224)	(70,081,581)	(109,391,947)
Increase from adjustment to time value of money	35,858,522	1,014,833	4,966,640	41,839,995
Foreign currency translation	3,819,769	(219,359)	1,544,716	5,145,126
Other increases (decreases)	405,346	1,636,827	2,539,714	4,581,887
Total Changes in Provisions	79,095,834	3,150,235	(40,100,598)	42,145,471
Balance as of December 31, 2016	266,041,945	10,229,537	77,021,449	353,292,931
Provisions	Legal Proceedings	Decommissioning or Restoration	Environmental Issues and Other Provisions	Total
	ThCh$	ThCh$	ThCh$	ThCh$
Changes in Provisions
Balance as of January 1, 2015	223,968,140	32,216,194	31,282,191	287,466,525
Increase (decrease) in existing provisions	22,857,949	24,158,277	106,100,964	153,117,190
Provision used	(25,239,603)	(7,275)	(12,262,416)	(37,509,294)
Increase from adjustment to time value of money	31,412,199	2,031,788	23,054,386	56,498,373
Foreign currency translation	(32,537,015)	(234,141)	(24,082,348)	(56,853,504)
Transfer to non-current assets held for distribution to owners  (1)	(14,829,363)	(51,085,541)	(6,530,431)	(72,445,335)
Other increases (decreases)	(18,686,196)	-	(440,299)	(19,126,495)
Total Changes in Provisions	(37,022,029)	(25,136,892)	85,839,856	23,680,935
Balance as of December 31, 2015	186,946,111	7,079,302	117,122,047	311,147,460

(1)    See Note 5.1

The accompanying notes are an integral part of these consolidated financial statements.

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23. EMPLOYEE BENEFIT OBLIGATIONS

23.1 General information

The Company and certain of its subsidiaries in Brazil, Colombia, Peru and Argentina granted various post-employment benefits for all or certain of their active or retired employees. These benefits are calculated and recognized in the financial statements according to the policy described in Note 3.l.1, and include primarily the following:

a)  Defined benefit plans:

• Complementary pension: The beneficiary is entitled to receive a monthly amount that supplements the pension obtained from the respective social security system.

• Employee severance indemnities: The beneficiary receives a certain number of contractual salaries upon retirement. Such benefit is subject to a vesting minimum service requirement period, which depending on the company, varies within a range from 5 to 15 years.

b)  Other benefits

Five-year benefit: A benefit certain employees receive after 5 years and which begins to accrue from the second year onwards.

Unemployment: A benefit paid regardless of whether the employee is fired or leaves voluntarily. This benefit accrues on a daily basis and is paid at the time of contract termination (although the law allows for partial withdrawals for housing and education).

Seniority bonuses: There is an agreement to give workers (“subject to the collective agreement”) an extraordinary bonus for years of service upon completion of the equivalent of five years of actual work based on the following:

Years of Service	Benefit
5, 10, 15	1 monthly salary
20	1.5 monthly salary
25, 30, 35, 40	2.5 monthly salaries

Health plan: Corresponds to a medical and dental benefit granted to the immediate family of retired employees (currently 121 retirees) of our subsidiary Emgesa. This benefit was provided by the union until March 31, 2016. Beginning on April 1, 2016, the benefit was provided by Emgesa who contracted MEDPLUS as the service provider. The benefit covers the immediate family, and in the event of the death of the beneficiary, the benefit is extended for six months, after which time the benefit is no longer provided.

c)  Defined contribution benefits:

The Group makes contributions to a retirement benefit plan where the beneficiary receives additional pension supplements upon his/her retirement, disability or death.

The accompanying notes are an integral part of these consolidated financial statements.

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23.2   Details, changes and presentation in financial statements

a) The post-employment obligations associated with defined benefits plans and the related plan assets as of December 31, 2016 and 2015, are detailed as follows:

General ledger accounts:

	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Post-employment obligations, non-current	228,525,324	187,270,474
Total Liabilities	228,525,324	187,270,474
Total Post-Employment Obligations, Net	228,525,324	187,270,474

Reconciliation with general ledger accounts:

	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Post-employment obligations	575,377,309	428,066,630
(-) Fair value of plan assets (*)	(384,821,181)	(284,231,299)
Total	190,556,128	143,835,331
Amount not recognized due to limit on Plan Assets Ceiling  (**)	22,373,345	22,057,178
Minimum funding required (IFRIC 14)  (***)	15,595,851	21,377,965
Total Post-Employment Obligations, Net	228,525,324	187,270,474

(*) Plan assets to fund defined benefit plans only in our Brazilian subsidiaries (Ampla and Coelce); the remaining defined benefit plans in our other subsidiaries are unfunded.

(**) In Coelce, certain pension plans currently have an actuarial surplus amounting to ThCh$22,373,345 as of December 31, 2016 (ThCh$22,057,178 as of December 31, 2015). This actuarial surplus was not recognized as an asset in accordance with IFRIC 14 - The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction, because the Complementary Social Security (SPC) regulations - CGPC Resolution No. 26/2008 states that the surplus can only be used by the sponsor if the contingency reserve on the balance sheet of the Foundation is at the maximum percentage (25% of reserves). This ensures the financial stability of the plan based on the volatility of these obligations. If the surplus exceeds this limit, it may be used by the sponsor to reduce future contributions or be reimbursed to the sponsor.

(***) In Ampla has been recognized in accordance with the provisions of IFRIC 14 - The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction an additional liability as of December 31, 2016 for ThCh$15,595,851 (ThCh$21,377,965 as of December 31, 2015). This corresponds to actuarial debt contracts that the company signed with Brasiletros (an institution providing pension funds exclusively to employees and retired employees of Ampla). This was done to equalize deficits on certain pension plans, since the sponsor assumes responsibility for these plans, in accordance with current legislation.

The accompanying notes are an integral part of these consolidated financial statements.

F-116

The following table presents the balance recorded in the consolidated statement of financial position as a result of the difference between the actuarial liability from defined benefit plans and the fair value of the plan assets affected as of December 31, 2016, and at the end of each of the four prior years:

	12-31-2016	12-31-2015	12-31-2014	12-31-2013	12-31-2012
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Actuarial liability	575,377,309	428,066,630	588,148,279	521,850,486	628,823,491
Plan assets	(384,821,181)	(284,231,299)	(368,008,708)	(322,830,274)	(393,880,165)
Difference	190,556,128	143,835,331	220,139,571	199,020,212	234,943,326
Amount not recognized due to limit on Plan Assets	22,373,345	22,057,178	33,710,733	39,494,779	21,218,042
Minimum financing required (IFRIC 14)	15,595,851	21,377,965	16,080,108	-	-
Accounting balance of actuarial liability deficit	228,525,324	187,270,474	269,930,412	238,514,991	256,161,368

b) The following amounts were recognized in the consolidated statement of comprehensive income for the years ended December 31, 2016, 2015 and 2014:

Expense Recognized in Comprehensive Income	12-31-2016	12-31-2015	12-31-2014
	ThCh$	ThCh$	ThCh$
Current service cost for defined benefits plan	2,504,931	7,092,780	4,513,850
Interest cost for defined benefits plan	58,882,192	56,568,888	59,981,707
Interest income from the plan assets	(42,362,834)	(38,428,236)	(42,145,223)
Past service cost	1,758,899	(523)	667,153
Interest cost on asset ceiling components	3,476,115	3,619,155	5,348,952
Expenses recognized in Profit or Loss	24,259,303	28,852,064	28,366,439
(Gains) losses from remeasurement of defined benefit plans	19,879,558	19,027,368	36,681,734
Total expense recognized in Comprehensive Income	44,138,861	47,879,432	65,048,173
Discontinued Operations	03-01-2016	12-31-2015	12-31-2014
	ThCh$	ThCh$	ThCh$
Expense for discontinued operations	574,738	4,582,171	4,449,042

The accompanying notes are an integral part of these consolidated financial statements.

F-117

c) The presentation of net actuarial liabilities as of December 31, 2016 and 2015, are as follows

Net Actuarial Liability	ThCh$
Balance as of January 1, 2015	269,930,412
Net interest cost	21,759,807
Service cost	7,092,780
Benefits paid	(19,628,639)
Contributions paid	(15,322,998)
Actuarial (gains) losses from changes in financial assumptions	(41,003,639)
Actuarial (gains) losses from changes in experience adjustments	33,191,124
Return on plan assets, excluding interest	25,577,816
Changes in the asset limit	(8,365,724)
Minimum finance required (IFRIC 14)	9,627,791
Transfer to liabilities classified as held for distribution to owners  (*)	(55,023,456)
Past service cost	(523)
Foreign currency translation differences	(40,564,277)
Balance as of December 31, 2015	187,270,474
Net interest cost	19,995,473
Service cost	2,504,931
Benefits paid	(12,862,593)
Contributions paid	(16,841,277)
Actuarial (gains) losses from changes in financial assumptions	57,155,289
Actuarial (gains) losses from changes in experience adjustments	9,580,234
Return on plan assets, excluding interest	(32,200,640)
Changes in the asset limit	(6,232,680)
Minimum finance required (IFRIC 14)	(8,422,645)
Past service cost	1,758,899
Defined benefit plan obligations from business combinations	16,910,891
Transfer of employees	(1,147,411)
Other	(511,024)
Foreign currency translation differences	11,567,403
Net actuarial liability as of December 31, 2016	228,525,324

(*) See Note 5.1.

d) The balance and changes in post-employment defined benefit obligations as of December 31, 2016 and 2015, are as follows:

Actuarial Value of Post-employment Obligations	ThCh$
Balance as of January 1, 2015	588,148,279
Service cost (*)	7,092,780
Interest cost (*)	56,568,888
Contributions from plan participants	453,243
Actuarial (gains) losses from changes in financial assumptions	(41,003,639)
Actuarial (gains) losses from changes in experience adjustments	33,191,124
Foreign currency translation	(108,872,703)
Benefits paid	(52,487,363)
Past service cost	(523)
Transfer to liabilities classified as held for distribution to owners	(55,023,456)
Balance as of December 31, 2015	428,066,630
Service cost	2,504,931
Interest cost	58,882,192
Contributions from plan participants	406,132
Actuarial (gains) losses from changes in financial assumptions	57,155,289
Actuarial (gains) losses from changes in experience adjustments	9,580,234
Foreign currency translation	50,801,062
Benefits paid	(49,030,516)
Past service cost	1,758,899
Defined benefit plan obligations from business combinations	16,910,891
Transfer of employees	(1,147,411)
Other	(511,024)
Balance as of December 31, 2016	575,377,309

(*) Current service cost related to continuing operations for the year ended December 31, 2015 was ThCh$4,810,031, it also includes costs for ThCh$1,484,025 of new benefit plans and costs of ThCh$1,380,360 related to seniority bonuses.  Interest cost related to continuing operations for the year ended December 31, 2015 was ThCh$19,459,863. Actuarial gains (losses) for defined benefit plans related to continuing operations were ThCh$13,381,836 for the year ended December 31, 2015.

The accompanying notes are an integral part of these consolidated financial statements.

F-118

As of December 31, 2016, out of the total amount of post-employment benefit obligations, 0.34% is from defined benefit plans in the Chilean holding company (0.72% as of December 31, 2015); 81.36% is from defined benefit plans in Brazilian companies (80.5% as of December 31, 2015); 15.49% is from defined benefit plans in Colombian companies (15.01% as of December 31, 2015); 2.34% is from defined benefit plans in Argentine subsidiaries (3.16% as of December 31, 2015); and the remaining 0.47% is from defined benefit plans in Peruvian companies (0.61% as of December 31, 2015).

Changes in the fair value of the benefit plan assets are as follows:

Fair Value of  Plan Assets	ThCh$
Balance as of January 1, 2015	(368,008,708)
Interest income	(38,428,236)
Return on plan assets, excluding interest	25,577,816
Foreign currency translation differences	79,545,346
Employer contributions	(15,322,998)
Contributions paid	(453,243)
Benefits paid	32,858,724
Balance as of December 31, 2015	(284,231,299)
Interest income	(42,362,834)
Return on plan assets, excluding interest	(32,200,640)
Foreign currency translation differences	(44,946,922)
Employer contributions	(16,841,277)
Contributions paid	(406,132)
Benefits paid	36,167,923
Balance as of December 31, 2016	(384,821,181)

e) The main categories of benefit plan assets are as follows:

Category of Plan Assets	12-31-2016		12-31-2015
	ThCh$	%	ThCh$	%
Equity instruments (variable income)	16,583,600	4.31%	35,173,904	12.38%
Fixed-income assets	319,592,708	83.05%	210,347,356	74.01%
Real estate investments	43,911,876	11.41%	33,391,752	11.75%
Other	4,732,997	1.23%	5,318,287	1.87%
Total	384,821,181	100%	284,231,299	100%

The plans for retirement benefits and pension funds held by our Brazilian subsidiaries, Ampla and Coelce, maintain investments as determined by the resolutions of the National Monetary Council, ranked in fixed income, equities and real estate. Fixed income investments are predominantly invested in federal securities. Regarding equities, Faelce (an institution providing pension funds exclusively to employees and retired employees of Coelce) holds common shares of Coelce, while Brasiletros (a similar institution for employees of Ampla) holds shares in investment funds with a portfolio traded on Bovespa (the São Paulo Stock Exchange). Finally, with regards to real estate, both foundations have properties that are currently leased to Ampla and Coelce.

The following table sets forth the assets affected by the plans and invested in shares, leases and real estate owned by the Group:

	12-31-2016	12-31-2015
	ThCh$	ThCh$
Equity instruments	-	1
Real Estate	18,554,488	16,535,844
Total	18,554,488	16,535,845

The accompanying notes are an integral part of these consolidated financial statements.

F-119

f) Reconciliation of asset ceiling:

Reconciliation of Asset Ceiling	ThCh$
Balance as of January 1, 2015	33,710,733
Interest on assets not recognized	3,619,155
Other changes in assets not recognized due to asset limit	(8,365,724)
Foreign currency translation differences	(6,906,986)
Balance as of December 31, 2015	22,057,178
Interest on assets not recognized	3,476,115
Other changes in assets not recognized due to asset limit	(6,232,680)
Foreign currency translation differences	3,072,733
Total asset ceiling as of December 31, 2016	22,373,346

Other disclosures:

● Actuarial assumptions:

As of December 31, 2016 and 2015, the following assumptions were used in the actuarial calculation of defined benefit plans:

	Chile		Brazil		Colombia		Argentina		Peru
	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
Discount rates used	4.70%	5.00%	12.2% - 12.31%	14.02% - 14.21%	6.54%	7.25%	5.50%	5.50%	6.20%	7.60%
Expected rate of salary increases	4.00%	4.00%	9.18%	9.69%	4.20%	4.20%	0.00%	0.00%	3.00%	3.00%
Mortality tables	CB-H-2014 RV-M-2014	RV -2009	AT 2000	AT 2000	RV 2008	RV 2008	CB-H-2014 RV-M-2014	RV 2004	CB-H-2014 RV-M-2014	RV 2009
Turnover rate	6.12% - 7.00%	5.69%	4.55% - 5.68%	4.55% - 5.68%	0.35% - 0.74%	0.44% - 0.65%	1.20% - 1.52%	1.20% - 1.52%	3.88% - 4.20%	3.90% - 4.07%

● Sensitivity:

As of December 31, 2016, the sensitivity of the value of the actuarial liability for post-employment benefits to variations of 100 basis points in the discount rate assumes a decrease of ThCh$46,997,078 (ThCh$32,618,877 as of December 31, 2015) if the rate rises and an increase of ThCh$55,052,865 (ThCh$38,040,654 as of December 31, 2015) if the rate falls in those 100 basis points.

● Future disbursements:

The estimates available indicate that ThCh$34,797,933 will be disbursed for defined benefit plans next year.

● Length of commitments:

The Group’s obligations have a weighted average length of 11.14 years, and the outflows of benefits for the next 5 years and more is expected to be as follows:

Years	ThCh$
1	55,890,335
2	44,225,077
3	44,462,518
4	43,963,708
5	44,529,707
Over 5	222,756,026

● Defined contributions:

The total expense recognized in the consolidated statement of comprehensive income within line item “Employee expenses” represents contributions payable to the defined contribution plans by the Group. For the years ended December 31, 2016, 2015 and 2014, the amounts recognized as expenses were ThCh$4,591,012, ThCh$4,799,333 and ThCh$4,700,327, respectively. These amounts correspond in its entirety to continuing operations.

The accompanying notes are an integral part of these consolidated financial statements.

F-120

24. EQUITY

24.1 Equity attributable to the shareholders of Enel Américas

24.1.1 Subscribed and paid capital and number of shares

The issued capital of the Company for the year ended December 31, 2016 is Ch$4,621,809,178,631 divided into 58,324,975,387 shares. The issued capital of the Company for the years ended December 31, 2015 and 2014 was Ch$5,804,447,986,087 divided into 49,092,772,762 shares, in both periods. All of the shares issued by the Company are subscribed and paid, and they are listed for trade on the Bolsa de Comercio de Santiago de Chile, the Bolsa Electrónica de Chile, the Bolsa de Valores de Valparaiso, and the New York Stock Exchange (NYSE).

Treasury shares

The treasury shares for the year ended December 31, 2016 are Ch$94,046,713,075 divided into 872,333,871 shares, and were acquired as part of the merger process as follows:

• 129,829,692 shares for a total amount of Ch$14,492,693,875 acquired from the minority shareholders of the Company, Endesa Américas and Chilectra Américas, who disagreed with respect to the merger and exercised their withdrawal rights.

• 742,504,179 shares for a total amount of Ch$79,554,019,200 corresponding to the shares of Endesa Américas acquired in the tender offer.

The shares of Endesa Américas and Chilectra Américas that were acquired as part of the merger were exchanged for shares of Enel Américas, since Endesa Américas and Chilectra Américas ceased to exist as separate entities upon consummation of the Merger.

Changes to the issued capital as a result of the Corporate Reorganization  

The Spin-Off Process:

At the Extraordinary Shareholders’ Meeting of Enersis (currently Enel Américas S.A.) held on December 18, 2015, the shareholders approved the spin-off of Enersis into two companies (the “Spin-Off”). As a result of this Spin-Off, Enersis Chile S.A. (currently Enel Chile S.A.), a new publicly held company governed under Chapter XII of D.L. 3,500 was created, and was allocated the shareholdings and other associated assets and liabilities of Enersis in Chile, including the ownership interests in Endesa Chile and Chilectra. All of Enersis’ shareholders participated in Enersis Chile in the same proportion as they had in Enersis’ issued capital, with the number of shares equal to what they had held in Enersis (ratio 1:1). All the businesses outside of Chile were allocated to the continuing company Enersis Américas, including Enersis’ ownership interests in the new entities as a result of the spin-offs of Chilectra and Endesa Chile, and all the assets and liabilities and administrative authorizations in Chile not expressly allocated to Enersis Chile in the Spin-Off.

As part of the Spin-Off, the capital of Enersis was reduced from Ch$5,804,447,986,000, divided into 49,092,772,762 registered common shares of a single series and no par value, to the new amount of Ch$3,575,339,011,549, divided into 49,092,772,762 registered common shares of a single series and no par value. Additionally, it was agreed to (i) establish the capital of Enersis Chile at Ch$2,229,108,974,451 corresponding to the amount by which the capital of Enersis had been decreased, divided into 49,092,772,762 registered common shares, all of the same series and no par value, and (ii) distribute the former Enersis’ equity interest between Enersis and Enersis Chile, by allocating assets and liabilities as indicated by the aforementioned meeting, to Enersis Chile.

On March 1, 2016, upon satisfying all conditions precedent, including the capital decrease and modifications to the by-laws, the separation of the Chilean and non-Chilean businesses of Enersis became effective and Enersis’ corporate name was changed to Enersis Américas (currently Enel Américas S.A.). The distribution of shares of Enersis Chile to the shareholders of Enersis was completed in April 2016.

On October 4, 2016, the corporate name changes of Enersis Chile, Endesa Chile and Chilectra to Enel Chile S.A., Enel Generación Chile S.A., and Enel Distribución Chile S.A., respectively, were approved at the respective Extraordinary Shareholders’ Meetings. The corporate name changes became effective on October 4, 2016, through modifications to the by-laws of each of these entities.

The accompanying notes are an integral part of these consolidated financial statements.

F-121

The Merger Process:

On September 28, 2016, the respective shareholders of Enersis Américas, Endesa Américas and Chilectra Américas met, voted and approved by more than two-thirds of the outstanding voting shares of each company, the merger of Endesa Américas and Chilectra Américas with and into Enersis Américas, with Enersis Américas continuing as the surviving company under the new name “Enel Américas S.A.” (the “Merger”). Pursuant to the Merger, Enel Américas S.A. (the “Surviving Company”) absorbed Endesa Américas and Chilectra Américas by incorporation, each of which were then dissolved without liquidation, and Enel Américas S.A. substituted for them in all their rights and obligations.

On September 14, 2016, the Company commenced a public cash tender offer (oferta pública de adquisición de valores, in Spanish) for all the outstanding shares and ADSs of Endesa Américas under Chilean law and applicable U.S. securities laws (the “Tender Offer”). The Tender Offer was for all shares (other than those held by the Company), including in the form of ADSs represented by ADRs of Endesa Américas, for a price of Ch$ 300 per share (or the equivalent in U.S. dollars of Ch$ 9,000 per ADS in the case of ADSs).

The Tender Offer was contingent on (i) the approval of the Merger by the relevant shareholders at the Extraordinary Shareholders’ Meetings pursuant to the Chilean Companies Act, (ii) less than 10% of the outstanding shares of the Company, 10% of the outstanding shares of Endesa Américas and 0.91% of the outstanding shares of Chilectra Américas exercising the statutory merger dissenters’ withdrawal rights in connection with the Merger, provided that no shareholder owned more than 65% of the Company after all exercises of statutory merger dissenters’ withdrawal rights, and (iii) the absence of any material adverse effect on Endesa Américas and its subsidiaries. Since the conditions were met, the Tender Offer was successfully completed on October 28, 2016. The Tender Offer resulted in the acquisition of 265,180,064 shares of Endesa Américas for a total amount of ThCh$79,554,019.

In summary, the Company increased its ownership interest in Endesa Américas by 3.23%, reaching a controlling interest of 63.21% of the shares.

On November 15, 2016, as agreed to at the Extraordinary Shareholders’ Meeting of the Company on September 28, 2016, the Company signed, together with its subsidiaries Endesa Américas and Chilectra Américas, the Deed of Compliance with Merger Conditions (Escritura Declarativa de Cumplimiento de Condiciones de Fusión, in Spanish), which affirmed the satisfaction of the conditions precedent to which the Merger of the Company with the aforementioned companies was subject to, and allowed the Merger to become effective as of the first calendar day of the following month.

On December 1, 2016, the Merger took effect and the Company absorbed Endesa Américas and Chilectra Américas by incorporation. On the same date, the Company changed its corporate name to “Enel Américas S.A.”.

As a consequence of the approval and completion of the Merger, shareholders of the Company, Endesa Américas and Chilectra Américas had the following options:

• shareholders of Endesa Américas that participated in the Merger received 2.8 shares of the Company’s common stock for each Endesa Américas share they owned and 1.68 ADSs of the Company for each Endesa Américas ADS they owned, since Endesa Américas ceased to exist as a separate entity upon consummation of the Merger;

• shareholders of Chilectra Américas that participated in the Merger received 4.0 shares of the Company’s common stock for each Chilectra Américas share they owned, since Chilectra Américas ceased to exist as a separate entity upon consummation of the Merger;

• shareholders of the Company, Endesa Américas and Chilectra Américas that dissented with respect to the Merger and exercised their statutory merger dissenters’ withdrawal rights provided under Chilean law received a cash payment equivalent to the weighted average of the closing prices of the Company or Endesa Américas shares, as the case may be, as reported on the Chilean Stock Exchanges during the 60-trading day period preceding the 30th trading day prior to the date the Merger was approved or the book value of the Chilectra Américas shares, as applicable; and

• shareholders of Endesa Américas tendered their Endesa Américas shares and ADSs in the Tender Offer.

The accompanying notes are an integral part of these consolidated financial statements.

F-122

The following table sets forth the movements in the number of shares of the Company as a result of the merger:

Number of outstanding shares of the Company prior the Merger			49,092,772,762
	Number of shares	Share exchange ratio	Number of shares
New shares issued (1):
Exchange of shares with minority shareholders of Endesa Américas	3,282,265,786	2.8	9,190,344,201
Exchange of shares with minority shareholders of Chilectra Américas	10,464,606	4	41,858,424
Total new shares issued	3,292,730,392		9,232,202,625
Repurchase of shares (2):
Withdrawal right exercised by the minority shareholders of the Company	(119,185,929)		(119,185,929)
Withdrawal right exercised by the minority shareholders of Endesa Américas	(3,706,909)	2.8	(10,379,345)
Withdrawal right exercised by the minority shareholders of Chilectra Américas	(65,035)	4	(260,140)
Remaining shares for exchange of shares			(4,278)
Total repurchase of shares	(122,957,873)		(129,829,692)
Tender Offer of Endesa Américas (3):
Purchased shares	(265,180,064)	2.8	(742,504,179)
Total Tender Offer of Endesa Américas	(265,180,064)		(742,504,179)
Number of outstanding shares of the Company after the Merger			57,452,641,516
Total number of shares - Issued Capital			58,324,975,387
Total number of shares - Treasury Shares			(872,333,871)
Number of outstanding shares of the Company after the Merger			57,452,641,516

(1) On December 29, 2016, a total of 9,232,202,625 new shares of the Company as a result of the Merger were registered with the Chilean Stock Register. The total amount for the issuance of new shares was ThCh$1,046,470,168.

(2) The total amount paid for the shares repurchased was ThCh$14,492,694.

(3) The total amount paid for the shares of Endesa Américas purchased in the Tender Offer was ThCh$79,554,019.

24.1.2 Dividends

On November 25, 2014, the Board unanimously agreed to distribute interim dividend No. 90 of Ch$0.83148 per share on January 30, 2015 against fiscal year 2014 statutory net income; this corresponded to 15% of net income calculated at September 30, 2014, in accordance with the dividend policy.

The Ordinary Shareholders’ Meeting held on April 28, 2015 approved the distribution of a minimum mandatory dividend (partially consisting of interim dividend No. 90 of Ch$0.83148 per share) and an additional dividend, which in the aggregate amounted to Ch$305,078,934,556 at Ch$6.21433 per share.

Since interim dividend No. 90 had already been paid, the remainder was distributed and paid in final dividend No. 91, which totaled Ch$264,259,128,599 equivalent to Ch$5.38285 per share.

On November 24, 2015, the Board unanimously agreed to distribute interim dividend No. 92 of Ch$1.23875 per share on January 29, 2016 against fiscal year 2015 statutory net income. This corresponded to 15% of net income calculated as of September 30, 2015, in accordance with the dividend policy.

The Ordinary Shareholders’ Meeting held on April 28, 2016 approved the distribution of a minimum mandatory dividend (deducting the interim dividend paid in January 2016) and an additional dividend, which in the aggregate amounted to Ch$204,974,253,630 at Ch$4.17321 per share.

Since interim dividend No. 92 had already been paid, the remainder was distributed and paid in final dividend No. 93, which totaled Ch$167,209,724,296 equivalent to Ch$3.40599 per share.

On November 24, 2016, the Board unanimously agreed to distribute interim dividend No. 94 of Ch$0.94664 per share for a total amount of Ch$54,387,251,604 on January 27, 2017 against fiscal year 2016 statutory net income. This corresponded to 15% of net income calculated as of September 30, 2016, in accordance with the dividend policy.

The accompanying notes are an integral part of these consolidated financial statements.

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The following table sets forth the dividends paid in recent years:

Dividend No.	Type of Dividend	Payment Date	Pesos per Share	Charged to
88	Interim	1-31-2014	1.42964	2013
89	Final	5-16-2014	5.27719	2013
90	Interim	1-30-2015	0.83148	2014
91	Final	5-25-2015	5.38285	2014
92	Interim	1-29-2016	1.23875	2015
93	Final	5-24-2016	3.40599	2015
94	Interim	1-27-2017	0.94664	2016

24.2 Foreign currency translation reserves

The following table sets forth foreign currency translation differences attributable to the shareholders of the Company for the years ended December 31, 2016, 2015 and 2014:

Reserves for Accumulated Currency Translation Differences	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Empresa Distribuidora Sur S.A.	(85,158,910)	(81,730,224)	(76,439,681)
Compañía Distribuidora y Comercializadora de Energía S.A.	97,776,402	97,135,435	130,582,841
Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	30,447,038	44,016,474	36,743,627
Dock Sud	(14,020,172)	(6,090,959)	3,671,460
Enel Brasil S.A.	(296,599,727)	(517,335,089)	(164,554,392)
Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	(2,198,481)	139,888	2,335,611
Inversiones GasAtacama Holding Ltda. (1) (2)	-	-	11,500,876
Emgesa S.A. E.S.P.	8,950,913	9,032,752	46,718,154
Enel Generación El Chocón S.A. (formerly named  Hidroeléctrica El Chocón S.A.)	(64,805,100)	(48,704,485)	(30,145,604)
Generandes Perú S.A.	64,927,577	80,370,339	71,188,012
Enel Generación Piura S.A. (formerly named Empresa Eléctrica de Piura S.A.)	5,931,003	8,753,615	7,321,905
Other	(5,635,874)	(4,580,660)	(3,767,935)
TOTAL	(260,385,331)	(418,992,914)	35,154,874

(1) Beginning on January 1, 2015, the company changed its functional currency from the U.S. dollar to Chilean pesos.

(2) As of December 31, 2015, this company was classified as a discontinued operation. Beginning on March 1, 2016, the company is no longer part of the Group (see Note 5.1)

24.3 Capital Management

The Company’s objective is to maintain an adequate level of capitalization in order to be able to secure its access to the financial markets, so as to fulfill its medium- and long-term goals while maximizing the return to its shareholders and maintaining a robust financial position.

24.4 Restrictions on subsidiaries transferring funds to the parent

Certain of the Group’s subsidiaries must comply with financial ratio covenants which require them to have a minimum level of equity or other requirements that restrict the transferring of assets to the Group. The Group’s restricted net assets as of December 31, 2016 from its subsidiaries Ampla, Coelce, Enel Distribución Perú, Enel Generación Piura, Enel Generación Perú, and Chinango were ThCh$668,014,559, ThCh$58,359,679, ThCh$199,473,547, ThCh$56,824,398, ThCh$48,979,531 and ThCh$977,128, respectively.

The accompanying notes are an integral part of these consolidated financial statements.

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24.5 Other reserves

Other reserves within equity attributable to shareholders of Enel Américas for the years ended December 31, 2016, 2015 and 2014, are as follows:

	Balance as of January 1, 2016	2016 changes	Balance as of December 31, 2016
	ThCh$	ThCh$	ThCh$
Exchange differences on translation (a)	(418,992,914)	158,607,583	(260,385,331)
Cash flow hedges (b)	(9,826,557)	2,179,035	(7,647,522)
Available-for-sale financial assets	(167,739)	319,842	152,103
Other comprehensive income from non-current assets held for distribution to owners	(101,436,996)	101,436,996	-
Other miscellaneous reserves (c )	(2,628,536,018)	376,066,035	(2,252,469,983)
TOTAL	(3,158,960,224)	638,609,491	(2,520,350,733)
	Balance as of January 1, 2015	2015 changes	Balance as of December 31, 2015
	ThCh$	ThCh$	ThCh$
Exchange differences on translation (a)	35,154,874	(454,147,788)	(418,992,914)
Cash flow hedges (b)	(69,404,677)	59,578,120	(9,826,557)
Available-for-sale financial assets	14,046	(181,785)	(167,739)
Other comprehensive income from non-current assets held for distribution to owners	-	(101,436,996)	(101,436,996)
Other miscellaneous reserves (c )	(2,619,970,627)	(8,565,391)	(2,628,536,018)
TOTAL	(2,654,206,384)	(504,753,840)	(3,158,960,224)
	Balance as of January 1, 2014	2014 changes	Balance as of December 31, 2014
	ThCh$	ThCh$	ThCh$
Exchange differences on translation (a)	(56,022,016)	91,176,890	35,154,874
Cash flow hedges (b)	(3,086,726)	(66,317,951)	(69,404,677)
Available-for-sale financial assets	11,811	2,235	14,046
Other miscellaneous reserves (c )	(2,414,023,486)	(205,947,141)	(2,619,970,627)
TOTAL	(2,473,120,417)	(181,085,967)	(2,654,206,384)

a) Reserves for exchange differences on translation: These reserves arise primarily from exchange differences relating to: (i) Translation of the financial statements of our subsidiaries with functional currencies other than the Chilean peso (see Note 2.7.3); and (ii) Translation of goodwill arising from the acquisition of companies with functional currencies other than the Chilean peso (see Note 3.b).

b) Cash flow hedge reserves: These reserves represent the cumulative effective portion of gains and losses on cash flow hedges (see Note 3.f.5).

The accompanying notes are an integral part of these consolidated financial statements.

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c) Other miscellaneous reserves.

The main items and their effects are the following:

Other Miscellaneous Reserves	12-31-2016	12-31-2015	12-31-2014
	ThCh$	ThCh$	ThCh$
Reserve for capital increase in 2013  (1)	(900,683,317)	(892,845,532)	(892,845,532)
Reserve for corporate reorganization (“Spin-off”)  (2)	479,817,274	-	-
Reserve for subsidiaries transactions  (3)	(294,091,592)	(289,426,882)	(289,426,882)
Reserve for transition to IFRS  (4)	(997,915,790)	(1,455,137,625)	(1,455,137,625)
Reserve for merger of Enel Américas, Endesa Américas and Chilectra Américas (5)	(489,213,328)	-	-
Reserve for Tender Offer of Endesa Américas and withdrawal rights (6)	(38,227,305)	-	-
Other miscellaneous reserves (7)	(12,155,925)	8,874,021	17,439,412
Total	(2,252,469,983)	(2,628,536,018)	(2,619,970,627)

(1) Reserve originated from the capital increase that the Company made during the first quarter of 2013.

(2) Reserve for corporate reorganization (Spin-Offs of companies) completed on March 1, 2016. Corresponds to the effects from the reorganization of the Company and the separation of the Chilean business into a new entity, Enel Chile S.A. (see Note 5.1).

(3) Reserve from transactions with our subsidiaries. Corresponds to the effect of purchases of equity interests in subsidiaries that were accounted for as transactions between entities under common control.

(4) Reserve for transition to IFRS. In accordance with Official Bulletin No. 456 from the SVS (Superintendencia de Valores y Seguros de Chile), included in this line item is the price-level restatement of paid-in capital from the date of transition to IFRS, January 1, 2004, to December 31, 2008.

(5) Reserve for merger of Endesa Américas and Chilectra Américas with and into the Company, completed on December 1, 2016. Represents the recognition of the difference between the capital increase in the Company and the carrying amount of the non-controlling interests that became part of the equity attributable to the equity owners of Enel Américas after completion of the Merger. The difference between the fair market value of the consideration received or paid and the amount by which the non-controlling interests is adjusted is being recognized in equity attributable to the owners of Enel Américas.

(6) Reserve for Tender Offer of Endesa Américas and withdrawal rights. Represents the recognition of the difference between the carrying amount and the price paid for the non-controlling interests acquired in the Tender Offer, which resulted in a charge to other reserves for ThCh$37,877,290. Also, includes ThCh$350,015 related to recognition of the difference between the carrying amount and the price paid for the shares of those shareholders who exercised their withdrawal rights.

(7) Other miscellaneous reserves from transactions made in prior years.

The accompanying notes are an integral part of these consolidated financial statements.

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24.6 Non-controlling Interests

 The detail of non-controlling interests for the years ended December 31, 2016, 2015 and 2014, is as follows:

Companies	Non-controlling interests
	12-31-2016	Equity		Profit (Loss)
		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2014
	%	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Ampla Energía E Serviços S.A.	0.36%	1,735,671	1,670,381	(154,382)	(39,491)	183,454
Compañía Energética Do Ceará S.A.	26.00%	133,994,165	102,309,115	19,953,608	18,722,431	14,883,752
Compañía Distribuidora y Comercializadora de Energía S.A.	51.52%	294,254,383	270,808,395	58,465,318	63,817,434	80,226,416
Emgesa S.A. E.S.P.	51.53%	402,781,136	412,145,236	86,052,535	109,187,510	148,822,948
Enel Distribución Perú  S.A.A (formerly named Edelnor S.A.A)	24.32%	81,256,041	75,852,375	15,044,949	15,467,507	14,524,832
Generandes Perú S.A.	0.00%	-	-	-	-	12,672,210
Enel Generación Perú S.A.A. (formerly named Edegel S.A.A)	16.40%	92,728,215	91,467,160	8,639,278	15,078,085	17,790,998
Chinango S.A.C.	20.00%	14,727,972	14,268,911	3,477,957	3,042,018	3,002,284
Empresa Distribuidora Sur S.A.	27.87%	469,321	7,873,277	(5,817,925)	27,738,670	(23,918,192)
Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	24.32%	5,376,086	3,759,405	2,745,894	(242,897)	11,072,950
Enel Generación El Chocón S.A. (formerly named Hidroeléctrica El Chocón S.A.)	32.33%	46,498,068	48,208,347	10,329,344	35,783,793	3,538,006
Inversora Dock Sud S.A.	42.86%	22,170,133	24,059,619	4,021,366	11,745,296	(6,544,116)
Central Dock Sud S.A.	29.76%	21,702,544	23,536,086	3,949,998	11,624,813	(8,857,902)
Enel Distribución Chile S.A. (formerly named Chilectra Chile S.A.) (1)	0.00%	-	10,118,233	274,125	1,743,825	1,264,684
Chilectra Américas S.A. (2)	0.00%	-	-	83,289	-	-
Enel Generación Chile S.A. (formerly named Endesa Chile S.A.) (1)	0.00%	-	1,059,805,601	48,377,285	157,225,820	110,198,149
Endesa Américas S.A. (2)	0.00%	-	-	45,046,210	-	-
Empresa Eléctrica Pehuenche S.A. (1)	7.35%	-	10,900,863	1,201,670	8,674,207	9,526,575
Enel Generación Piura S.A. (formerly named Empresa Eléctrica de Piura S.A.)	3.50%	2,642,479	2,201,500	537,587	-	3,948,804
Others		4,443,469	4,674,591	957,822	3,313,547	3,286,014
TOTAL		1,124,779,683	2,163,659,095	303,185,928	482,882,568	395,621,866

(1) Classified as disposal groups held for distribution to owners as of December 31, 2015. Beginning on March 1, 2016, these non-controlling interests are no longer within the Group (see Note 5.1).

(2) On December 1, 2016, these entities were merged with and into the Company, and were then dissolved without liquidation (see Note 24.1.1).

The accompanying notes are an integral part of these consolidated financial statements.

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25. REVENUE AND OTHER OPERATING INCOME

The detail of revenue presented in the statement of comprehensive income for the years ended December 31, 2016, 2015 and 2014, is as follows:

Revenues	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Energy sales (1)(2)	4,323,908,358	4,224,381,699	4,349,833,962
Generation	1,140,390,661	1,202,615,603	1,192,444,520
Regulated customers	110,739,036	141,728,020	137,536,698
Unregulated customers	709,697,806	664,527,858	676,023,056
Spot market sales	250,678,234	338,995,080	338,908,636
Other customers	69,275,585	57,364,645	39,976,130
Distribution	3,183,517,697	3,021,766,096	3,157,389,442
Residential	1,443,432,457	1,485,240,702	1,583,857,094
Business	888,463,061	722,634,924	737,471,663
Industrial	369,218,116	299,722,654	309,822,204
Other customers	482,404,063	514,167,816	526,238,481
Other sales	35,373,060	40,648,051	34,220,939
Gas sales	21,847,481	16,779,246	8,154,469
Sales of goods and services	13,525,579	23,868,805	26,066,470
Revenue from other services	408,844,273	402,615,560	422,400,836
Tolls and transmission	292,949,677	248,565,422	251,366,453
Metering equipment leases	74,132	70,485	82,069
Public lighting	5,085,646	23,162,879	28,050,833
Verifications and connections	7,510,995	4,580,679	4,200,004
Engineering and consulting services	3,257,072	1,404,449	12,826,190
Other services	99,966,751	124,831,646	125,875,287
Total revenues	4,768,125,691	4,667,645,310	4,806,455,737
Other Operating Income	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Revenue from construction contracts	270,075,694	230,687,290	186,078,925
Other income (2)	159,084,585	403,106,978	213,835,126
Total other operating income	429,160,279	633,794,268	399,914,051

(1) In Argentina, on January 29, 2016, ENRE Resolution No. 1/2016 was issued, approving the tariff table of Edesur applicable to the invoicing of meter readings, which commenced after midnight on February 1, 2016. The effect recognized for this resolution during the year ended December 31, 2016 was ThCh$419,665,450. For the year ended December 31, 2015, revenues from energy sales of ThCh$33,972,365 related to the application of Resolution No. 32/2015 were recognized, which stated that as of February 1, 2015, the funds from PUREE must be considered part of the revenues of energy distribution companies.

(2) For the year ended December 31, 2015, on March 11, 2015, Argentine SE Resolution No. 32/2015 was issued for the purpose of funding the expenditures and investments used during normal operations to render distribution of electricity public services, which: (i) approved a non-recurrent increase of revenues (energy sales) for ThCh$264,987,134 in our subsidiary Edesur beginning on February 1, 2015 without any increase in tariffs; (ii) compensated until January 31, 2015, the outstanding amounts from PUREE up to the amount of the Cost Monitoring Mechanism (“MMC”) adjustment for recognizing costs that were not passed on to electricity tariffs for ThCh$11,551,237; and (iii) instructed CAMMESA to issue LVFVD in amounts determined by ENRE by virtue of the higher salary costs of Edesur due to the application of Resolution No. 836/2014 of the Secretary of Labor for a total amount of ThCh$40,953,407. For the year ended December 31, 2016, the preceding non-recurrent measures were no longer applicable since, as previously discussed; ENRE Resolution No. 1/2016 approved the tariff table of Edesur.

In addition, other income includes ThCh$59,235,949, ThCh$52,400,888 and ThCh$39,282,571 for the years ended December 31, 2016, 2015 and 2014, respectively, related to the availability contracts that our subsidiary Enel Generación Costanera entered into with CAMMESA in December 2012.

The accompanying notes are an integral part of these consolidated financial statements.

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26. RAW MATERIALS AND CONSUMABLES USED

The detail of raw materials and consumables used presented in profit or loss for the years ended December 31, 2016, 2015 and 2014, is as follows:

Raw Materials and Consumables Used	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Energy purchases	(1,651,606,817)	(1,885,916,426)	(1,824,002,786)
Fuel consumption	(244,886,033)	(258,113,922)	(205,534,394)
Transportation costs	(266,484,464)	(245,813,374)	(265,185,382)
Costs from construction contracts	(270,075,694)	(230,687,290)	(186,078,925)
Other raw materials and consumables	(212,045,797)	(156,670,500)	(150,867,949)
Total	(2,645,098,805)	(2,777,201,512)	(2,631,669,436)

27. EMPLOYEE BENEFITS EXPENSE

Employee expenses for the years ended December 31, 2016, 2015 and 2014, are as follows:

Employee Benefits Expenses	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Wages and salaries	(270,822,889)	(309,761,095)	(266,240,462)
Post-employment benefit obligations expense	(8,854,842)	(9,609,364)	(7,571,331)
Social security and other contributions	(134,441,521)	(159,641,192)	(110,493,404)
Other employee expenses	(9,244,846)	(8,686,496)	(5,363,276)
Total	(423,364,098)	(487,698,147)	(389,668,473)

28. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES

The detail of depreciation, amortization and impairment losses for the years ended December 31, 2016, 2015 and 2014, are as follows:

	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Depreciation	(235,574,729)	(245,598,045)	(244,376,550)
Amortization	(84,424,312)	(74,944,152)	(106,366,200)
Subtotal	(319,999,041)	(320,542,197)	(350,742,750)
Impairment (losses) reversals (*)	(106,214,656)	(39,811,756)	(38,329,942)
Total	(426,213,697)	(360,353,953)	(389,072,692)

(*) Information on Impairment Losses by Reportable Segment	Generation			Distribution			Other			For the years ended December 31,
	2016	2015	2014	2016	2015	2014	2016	2015	2014	2016	2015	2014
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Financial assets (See Note 8)	(9,995,956)	(4,794,591)	(2,024,186)	(78,660,049)	(34,909,411)	(20,090,180)	(95,529)	(75,708)	(78,174)	(88,751,534)	(39,779,710)	(22,192,540)
Other financial assets	(13,110,022)	-	-	-	-	-	(4,353,100)	-	-	(17,463,122)	-	-
Intangible assets other than goodwill (See Note 13)	-	-	-	-	-	(14,948,785)	-	-	-	-	-	(14,948,785)
Property, plants and equipment (See Note 15)	-	(32,046)	(1,188,617)	-	-	-	-	-	-	-	(32,046)	(1,188,617)
Total	(23,105,978)	(4,826,637)	(3,212,803)	(78,660,049)	(34,909,411)	(35,038,965)	(4,448,629)	(75,708)	(78,174)	(106,214,656)	(39,811,756)	(38,329,942)

The accompanying notes are an integral part of these consolidated financial statements.

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29. OTHER EXPENSES

Other miscellaneous operating expenses for the years ended December 31, 2016, 2015 and 2014, are as follows:

Other expenses	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Other supplies and services	(147,298,051)	(58,304,067)	(53,366,436)
Professional, outsourced and other services	(90,335,758)	(162,323,852)	(168,177,580)
Repairs and maintenance	(111,190,930)	(107,991,590)	(112,073,249)
Indemnities and fines	(2,826,797)	(12,912,842)	(16,742,020)
Taxes and charges	(24,898,571)	(32,252,186)	(13,489,033)
Insurance premiums	(28,448,289)	(28,245,178)	(23,656,637)
Leases and rental costs	(11,678,441)	(12,449,187)	(14,352,431)
Marketing, public relations and advertising	(3,526,540)	(5,270,796)	(4,700,359)
Other supplies	(118,144,838)	(53,888,664)	(41,535,780)
Travel expenses	(12,840,901)	(13,769,681)	(13,814,472)
Environmental expenses (1)	(1,511,614)	(1,120,706)	(1,821,267)
Total	(552,700,730)	(488,528,749)	(463,729,264)

(1) It includes research costs recognized as expenses for the years ended December 31, 2016, 2015 and 2014, of ThCh$194,990, ThCh$237,085 and ThCh$403,574, respectively.

30. OTHER GAINS (LOSSES)

Other gains (losses) for the years ended December 31, 2016, 2015 and 2014, are as follows:

Other Gains (Losses)	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Disposals of property, plants and equipment	17,475,697	(6,758,695)	-
Other (1)	(9,266,214)	192,470	876,554
Total	8,209,483	(6,566,225)	876,554

(1) For the year ended December 31, 2016, this item includes the effects from the merger of Codensa with DECSA and EEC related to (i) the loss for ThCh$11,556,684 recognized in remeasuring the pre-existent interest that Codensa owned in DECSA and EECSA; (ii) the loss for ThCh$2,456,619 recognized in reclassifying to profit or loss the accumulated foreign exchange translation differences included in the pre-existent interest that Codensa owned in DECSA and EEC, and (iii) the recognized bargain purchase gain for ThCh$4,708,663 (see Note 6).

The accompanying notes are an integral part of these consolidated financial statements.

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31. FINANCIAL RESULTS

Financial income and costs for the years ended December 31, 2016, 2015 and 2014, are as follows:

Financial Income	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	101,644,945	124,314,454	86,576,973
Financial income on plan assets  (Brazil)	111,003	135,153	224,310
Financial income from concessions IFRIC 12 (Brazil) (1)	37,303,103	37,618,478	-
Other financial income (2)	47,878,463	132,702,187	164,320,479
Total financial income	186,937,514	294,770,272	251,121,762
Financial costs	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Financial costs	(522,800,993)	(385,455,340)	(432,314,329)
Bank loans	(57,308,976)	(38,921,033)	(33,061,726)
Unsecured obligations (bonds)	(192,607,024)	(179,258,559)	(172,288,757)
Financial leasing	(1,549,452)	(1,414,900)	(817,985)
Valuation of financial derivatives	(11,174,750)	(656,450)	(124,470)
Financial provisions (4)	(109,919,998)	(54,616,547)	(46,354,184)
Post-employment benefit obligations (3)	(20,106,476)	(19,595,016)	(21,270,704)
Capitalized borrowing costs	20,920,558	73,008,564	55,101,384
Other financial costs	(151,054,875)	(164,001,399)	(213,497,887)
Gains (losses) from indexed assets and liabilities (*)	(698,141)	(9,266,040)	(13,630,068)
Foreign currency exchange differences (**) (2)	39,850,562	128,238,047	(18,493,594)
Total financial costs	(483,648,572)	(266,483,333)	(464,437,991)
Total financial results	(296,711,058)	28,286,939	(213,316,229)

(1) For the years ended December 31, 2016 and 2015, this item corresponds to the financial update of non-amortized assets at their new replacement value at the end of the concession in the distribution companies Ampla and Coelce.  

(2) For the year ended December 31, 2015, our Argentine subsidiaries, Enel Generación Costanera, Enel Generación El Chocón y Dock Sud recognized a gain in foreign currency exchange differences for ThCh$141,559,960, as a result of the dollarization (re-denomination to US$) of the receivables (“LVFVD”) related to the Central Vuelta de Obligado (VOSA) project, and other financial income for ThCh$57,079,871 related to the accrued interest on those dollarized receivables. In addition, our subsidiary Edesur, recognized a financial income for ThCh$27,215,856 related to the compensation from the application of the MMC (see Note 33.5).

(3) See Note 23.2.b.

(4) This item includes ThCh$47,110,667 for the year ended December 31, 2016 from our subsidiary Edesur for the finance cost recognized in relation to the update of the quality service fine due to the application of ENRE Resolution No. 1/2016 (see Notes 21 and 33.5). In addition, our Brazilian subsidiaries Ampla and Coelce have recognized ThCh$34,351,383, ThCh$30,951,657 and ThCh$ 35,103,119 related to the financial update of legal claims (see Note 22).

The accompanying notes are an integral part of these consolidated financial statements.

F-131

The effects on financial results from exchange differences and the application of indexed assets and liabilities are originated from the following:

Gains (losses) from Indexed Assets and Liabilities (*)	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Other financial assets	10	-	-
Current tax assets and liabilities	36,471	1,240	21,157
Other financial liabilities (financial debt and derivative instruments)	(695,250)	(9,267,280)	(13,651,225)
Other provisions	(39,372)	-	-
Total	(698,141)	(9,266,040)	(13,630,068)
Foreign Currency Exchange Differences (**)	For the years ended December 31,
	2016	2015	2014
	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	10,239,814	7,304,624	22,199,061
Other financial assets	67,847,538	170,679,018	34,690,822
Other non-financial assets	(1,413,526)	4,995,376	93,239
Trade and other receivables	7,307,240	51,506,895	12,791,191
Current tax assets and liabilities	499,124	-	24,876
Other financial liabilities (financial debt and derivative instruments)	(37,327,934)	(44,858,948)	(74,345,529)
Trade and other payables	1,144,094	(37,360,135)	(10,195,770)
Other non-financial liabilities	(8,445,788)	(24,028,783)	(3,751,484)
Total	39,850,562	128,238,047	(18,493,594)

The accompanying notes are an integral part of these consolidated financial statements.

F-132

32. INFORMATION BY SEGMENT

32.1 Basis of segmentation

The Group’s activities operate under a matrix management structure with dual and cross management responsibilities (based on business and geographical areas of responsibility), and its subsidiaries are engaged in either the Generation and Transmission Business or the Distribution Business.

The Group adopted a “bottom-up” approach to determine its reportable segments. The Generation and Transmission and the Distribution reportable segments have been defined based on IFRS 8.9 and on the criteria described in IFRS 8.12, taking into account the aggregation of the operating segments having similar economic drivers that are common in all countries.

Generation and Transmission Business:The Generation and Transmission Reportable Segment is comprised of a group of electricity companies that own electricity generating plants, whose energy is transmitted and distributed to end customers in four different countries.

The following four operating segments have been aggregated into one combined set of information for the Generation and Transmission Reportable Segment:

Generation and Transmission Reportable Segment:

• Generation and Transmission Business in Argentina

• Generation and Transmission Business in Brazil

• Generation and Transmission Business in Colombia

• Generation and Transmission Business in Peru

The Generation and Transmission Business is conducted: in Argentina through Cemsa, Central Dock Sud, Enel Generación Costanera, and Enel Generación El Chocón; in Brazil through EGP Cachoeira Dourada, Enel CIEN, Enel Brasil, and Fortaleza; in Colombia through Emgesa; and in Peru through Enel Generación Perú and Enel Generación Piura.

Distribution Business:The Distribution Reportable Segment is comprised of a group of electricity companies operating under a public utility concession, with service obligations and regulated tariffs for supplying regulated customers in four different countries.

The following four operating segments have been aggregated into one combined set of information for the Distribution Reportable Segment:

Distribution Reportable Segment:

• Generation and Transmission Business in Argentina

• Generation and Transmission Business in Brazil

• Generation and Transmission Business in Colombia

• Generation and Transmission Business in Peru

The Distribution Business is conducted: in Argentina through Edesur; in Brazil through Ampla and Coelce; in Colombia through Codensa; and in Peru through Enel Distribución Perú.

The accompanying notes are an integral part of these consolidated financial statements.

F-133

Each of the operating segments generates separate financial information, which is aggregated into one combined set of information for the Generation and Transmission Business, and another set of combined information for the Distribution Business at the reportable segment level. In addition, in order to assist the decision maker process, the Planning & Control Department at the parent company level prepares internal reports containing combined information at the reportable segment level about the main key performance indicators (KPIs), such as: EBITDA, Gross Margin, Total Capex, Total Opex, Net income, Total Energy Generation and Transmission, among others. The presentation of information under this business/country approach has been made taking into consideration that the KPIs are similar and comparable in all countries, in each of the following aspects:

(a) the nature of the activities: Generation and Transmission on one hand, and Distribution on the other;

(b) the nature of the production processes: the Generation and Transmission Business deals with the generation of electricity and its transmission to dispatch centers, while the Distribution Business does not generate electricity, but distributes electricity to end customers;

(c) the type or class of customer for their products and services: the Generation and Transmission Business provides services mainly to unregulated customers, while the Distribution Business provides energy to regulated customers;

(d) the methods used to distribute their products or provide their services: generators generally sell the energy through energy auctions, while distributors provide energy in their concession area; and

(e) the nature of the regulatory environment (public utilities): the regulatory frameworks differs in the Generation and Transmission Business and Distribution Business

The Company’s chief operating decision maker (“CODM”) in conjunction with the country managers reviews on a monthly basis these internal reports and uses the KPI information to make decisions on the allocation of resources and the assessment of the performance of the operating segments for each reportable segment.

The information disclosed in the following tables is based on the financial information of the companies forming each segment. The accounting policies used to determine the segment information are the same as those used in the preparation of the Group’s consolidated financial statements. Based on this context and taking into consideration the corporate reorganization as discussed in Note 5.1, the assets and liabilities related to the Chilean operations are presented as held for distribution to owners, and in the case of income statement accounts, as discontinued operations.

The following tables present details of this information by reportable segment:

The accompanying notes are an integral part of these consolidated financial statements.

F-134

32.2 Generation and transmission, distribution and others

Line of business		Generation and transmission		Distribution		Holdings, Eliminations and Others		Total
ASSETS		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS		745,759,643	3,974,309,548	1,338,474,717	2,233,248,507	1,113,016,501	1,706,003,655	3,197,250,861	7,913,561,710
	Cash and cash equivalents	394,918,734	158,234,836	372,652,977	174,458,784	1,032,938,586	852,469,724	1,800,510,297	1,185,163,344
	Other current financial assets	17,658,485	11,466,253	34,990,586	34,171,369	38,570,534	22,624,824	91,219,605	68,262,446
	Other current non-financial assets	17,819,024	26,895,066	76,703,728	72,076,278	1,502,473	3,017,713	96,025,225	101,989,057
	Trade and other current receivables	215,705,335	281,533,993	807,300,896	802,286,571	7,212,996	4,311,003	1,030,219,227	1,088,131,567
	Current accounts receivable from related parties	61,906,976	69,698,172	7,717,238	27,676,364	(39,083,015)	(93,807,606)	30,541,199	3,566,930
	Inventories	32,313,348	33,665,661	33,525,093	61,185,174	571,608	207,062	66,410,049	95,057,897
	Current tax assets	5,437,741	3,751,263	5,584,199	11,961,862	71,303,319	31,741,463	82,325,259	47,454,588
	Non-current assets or disposal groups held for sale or held for distribution to owners	-	3,389,064,304	-	1,049,432,105	-	885,439,472	-	5,323,935,881
NON-CURRENT ASSETS		3,539,807,873	4,070,922,143	4,242,778,102	4,091,696,107	301,718,670	(627,025,569)	8,084,304,645	7,535,592,681
	Other non-current financial assets	1,267,061	625,982	687,804,828	488,884,301	20,549	17,921	689,092,438	489,528,204
	Other non-current non-financial assets	8,337,562	9,847,779	62,178,337	54,741,348	2,059,281	12,973,581	72,575,180	77,562,708
	Trade and other non-current receivables	292,497,865	310,451,501	66,941,597	88,178,936	208,134	65,427	359,647,596	398,695,864
	Non-current accounts receivable from related parties	-	-	240,677	355,485	-	-	240,677	355,485
	Investments accounted for using the equity method	91,417,560	478,361,882	17,268	491,519,716	(90,249,867)	(938,921,153)	1,184,961	30,960,445
	Intangible assets other than goodwill	36,397,602	33,665,518	1,170,364,011	933,484,014	5,085,131	14,249,740	1,211,846,744	981,399,272
	Goodwill	12,739,519	100,700,655	87,951,185	76,703,162	377,818,418	266,795,230	478,509,122	444,199,047
	Property, plants and equipment	3,052,464,550	3,097,266,606	2,094,171,642	1,905,927,300	3,700,867	372,727	5,150,337,059	5,003,566,633
	Deferred tax assets	44,686,154	40,002,220	73,108,557	51,901,845	3,076,157	17,420,958	120,870,868	109,325,023
TOTAL ASSETS		4,285,567,516	8,045,231,691	5,581,252,819	6,324,944,614	1,414,735,171	1,078,978,086	11,281,555,506	15,449,154,391
Line of business		Generation and Transmission		Distribution		Holdings, Eliminations and Others		Total
LIABILITIES AND EQUITY		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES		792,682,510	2,735,116,868	1,757,079,613	1,838,355,464	9,028,231	(68,091,532)	2,558,790,354	4,505,380,800
	Other current financial liabilities	152,992,685	230,270,298	341,802,767	206,125,030	9,888,911	251,478,180	504,684,363	687,873,508
	Trade and other current payables	394,678,678	342,712,347	1,176,412,922	1,037,064,551	84,249,275	73,047,309	1,655,340,875	1,452,824,207
	Current accounts payable to related parties	96,548,117	104,568,189	113,295,239	72,131,804	(98,139,317)	(66,802,485)	111,704,039	109,897,508
	Other current provisions	31,742,643	81,419,354	76,292,279	45,879,822	11,978,523	-	120,013,445	127,299,176
	Current tax liabilities	113,011,367	91,117,121	21,780,288	24,166,415	84,678	27,324,424	134,876,333	142,607,960
	Other current non-financial liabilities	3,709,020	1,951,295	27,496,118	35,966,491	966,161	1,308,553	32,171,299	39,226,339
	Liabilities associated with groups of assets or disposal groups held for sale or distribution to owners	-	1,883,078,264	-	417,021,351	-	(354,447,513)	-	1,945,652,102
NON-CURRENT LIABILITIES		1,425,473,091	1,313,277,539	1,821,542,055	1,559,780,584	200,501,433	(119,092,912)	3,447,516,579	2,753,965,211
	Other non-current financial liabilities	1,027,909,549	941,834,867	961,192,689	883,297,767	407,651,656	22,163,958	2,396,753,894	1,847,296,592
	Trade and other non-current payables	113,683,403	97,364,873	222,357,299	178,027,558	6,734,179	8,151,823	342,774,881	283,544,254
	Non-current accounts payable to related parties	13,240,806	10,685,702	210,599,867	157,179,286	(223,840,673)	(167,864,988)	-	-
	Other long-term provisions	52,299,461	41,883,233	180,771,384	141,808,620	208,641	156,431	233,279,486	183,848,284
	Deferred tax liabilities	176,738,031	181,262,110	36,075,916	34,940,876	7,815,710	15,701,629	220,629,657	231,904,615
	Non-current provisions for employee benefits	24,388,017	21,548,342	202,205,387	163,123,897	1,931,920	2,598,235	228,525,324	187,270,474
	Other non-current non-financial liabilities	17,213,824	18,698,412	8,339,513	1,402,580	-	-	25,553,337	20,100,992
EQUITY		2,067,411,915	3,996,837,284	2,002,631,151	2,926,808,566	1,205,205,507	1,266,162,530	5,275,248,573	8,189,808,380
Equity attributable to shareholders of Enel Américas		2,067,411,915	3,996,837,284	2,002,631,151	2,926,808,566	1,205,205,507	1,266,162,530	4,150,468,890	6,026,149,285
	Issued capital	686,296,536	1,476,722,861	564,587,301	860,651,565	3,370,925,341	3,467,073,560	4,621,809,178	5,804,447,986
	Retained earnings	582,568,239	2,358,601,470	131,313,178	1,414,711,314	1,429,175,741	(392,651,261)	2,143,057,158	3,380,661,523
	Share premium	25,237,324	206,058,198	42,382,044	3,547,484	(67,619,368)	(209,605,682)	-	-
	Treasury shares	-	-	-	-	(94,046,713)	-	(94,046,713)	-
	Other reserves	773,309,816	(44,545,245)	1,264,348,628	647,898,203	(3,433,229,494)	(1,598,654,087)	(2,520,350,733)	(3,158,960,224)
Non-controlling interests		-	-	-	-	-	-	1,124,779,683	2,163,659,095
Total Liabilities and Equity		4,285,567,516	8,045,231,691	5,581,252,819	6,324,944,614	1,414,735,171	1,078,978,086	11,281,555,506	15,449,154,391

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

F-135

Line of business		Generation and Transmission			Distribution			Holdings, eliminations and others			Total
STATEMENT OF COMPREHENSIVE INCOME		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
REVENUE AND OTHER OPERATING INCOME		1,832,553,706	1,734,761,772	1,762,869,133	3,857,347,068	3,890,722,930	3,802,108,560	(492,614,804)	(324,045,124)	(358,607,905)	5,197,285,970	5,301,439,578	5,206,369,788
	Revenues	1,749,546,603	1,668,272,704	1,701,051,112	3,510,753,247	3,321,156,669	3,463,626,805	(492,174,159)	(321,784,063)	(358,222,180)	4,768,125,691	4,667,645,310	4,806,455,737
	Energy sales	1,588,869,749	1,486,031,970	1,514,124,760	3,184,042,732	3,022,021,032	3,157,667,595	(449,004,123)	(283,671,303)	(321,958,393)	4,323,908,358	4,224,381,699	4,349,833,962
	Other sales	27,010,786	21,124,909	13,080,015	2,217,428	19,523,142	21,140,924	6,144,846	-	-	35,373,060	40,648,051	34,220,939
	Other services rendered	133,666,068	161,115,825	173,846,337	324,493,087	279,612,495	284,818,286	(49,314,882)	(38,112,760)	(36,263,787)	408,844,273	402,615,560	422,400,836
	Other operating income	83,007,103	66,489,068	61,818,021	346,593,821	569,566,261	338,481,755	(440,645)	(2,261,061)	(385,725)	429,160,279	633,794,268	399,914,051
RAW MATERIALS AND CONSUMABLES USED		(769,078,400)	(677,940,967)	(653,688,007)	(2,373,433,611)	(2,423,363,923)	(2,338,428,095)	497,413,206	324,103,378	360,446,666	(2,645,098,805)	(2,777,201,512)	(2,631,669,436)
	Energy purchases	(308,347,858)	(235,046,359)	(258,676,854)	(1,820,089,885)	(1,951,642,845)	(1,900,048,593)	476,830,926	300,772,778	334,722,661	(1,651,606,817)	(1,885,916,426)	(1,824,002,786)
	Fuel consumption	(244,886,033)	(258,113,922)	(205,534,394)	-	-	-	-	-	-	(244,886,033)	(258,113,922)	(205,534,394)
	Transportation expenses	(138,952,698)	(124,612,122)	(124,900,859)	(154,388,360)	(147,073,303)	(168,191,394)	26,856,594	25,872,051	27,906,871	(266,484,464)	(245,813,374)	(265,185,382)
	Other miscellaneous supplies and services	(76,891,811)	(60,168,564)	(64,575,900)	(398,955,366)	(324,647,775)	(270,188,108)	(6,274,314)	(2,541,451)	(2,182,866)	(482,121,491)	(387,357,790)	(336,946,874)
CONTRIBUTION MARGIN		1,063,475,306	1,056,820,805	1,109,181,126	1,483,913,457	1,467,359,007	1,463,680,465	4,798,402	58,254	1,838,761	2,552,187,165	2,524,238,066	2,574,700,352
	Other work performed by the entity and capitalized	10,913,895	14,387,605	13,548,280	56,260,014	52,567,319	42,103,255	72,476	146,345	118,883	67,246,385	67,101,269	55,770,418
	Employee benefits expense	(91,230,952)	(107,850,396)	(92,178,851)	(311,327,429)	(365,683,363)	(283,638,620)	(20,805,717)	(14,164,388)	(13,851,002)	(423,364,098)	(487,698,147)	(389,668,473)
	Other expenses	(108,419,018)	(96,544,274)	(84,426,859)	(383,384,811)	(372,678,643)	(376,865,536)	(60,896,901)	(19,305,832)	(2,436,869)	(552,700,730)	(488,528,749)	(463,729,264)
GROSS OPERATING RESULT		874,739,231	866,813,740	946,123,696	845,461,231	781,564,320	845,279,564	(76,831,740)	(33,265,621)	(14,330,227)	1,643,368,722	1,615,112,439	1,777,073,033
	Depreciation and amortization expense	(140,696,750)	(147,291,267)	(142,609,270)	(179,563,109)	(173,636,385)	(208,532,299)	260,818	385,455	398,819	(319,999,041)	(320,542,197)	(350,742,750)
	Impairment (losses) reversals recognized in profit or loss	(23,105,978)	(4,826,638)	(3,212,803)	(78,660,049)	(34,909,411)	(35,038,965)	(4,448,629)	(75,707)	(78,174)	(106,214,656)	(39,811,756)	(38,329,942)
OPERATING INCOME		710,936,503	714,695,835	800,301,623	587,238,073	573,018,524	601,708,300	(81,019,551)	(32,955,873)	(14,009,582)	1,217,155,025	1,254,758,486	1,388,000,341
FINANCIAL RESULT		(100,463,836)	99,864,652	(22,550,175)	(261,843,538)	(97,880,409)	(252,708,515)	65,596,316	26,302,696	61,942,461	(296,711,058)	28,286,939	(213,316,229)
	Financial income	45,160,453	88,032,028	111,084,259	105,611,180	177,432,364	84,910,412	36,165,881	29,305,880	55,127,091	186,937,514	294,770,272	251,121,762
	Cash and cash equivalents	38,305,538	86,308,158	26,728,453	27,369,142	8,809,058	14,617,999	35,970,265	29,197,237	45,230,521	101,644,945	124,314,453	86,576,973
	Other financial income	6,854,915	1,723,870	84,355,806	78,242,038	168,623,306	70,292,413	195,616	108,643	9,896,570	85,292,569	170,455,819	164,544,789
	Financial costs	(168,606,379)	(109,517,207)	(85,935,531)	(370,919,769)	(275,453,176)	(335,813,681)	16,725,155	(484,957)	(10,565,117)	(522,800,993)	(385,455,340)	(432,314,329)
	Bank borrowings	(16,388,376)	(15,348,968)	(21,393,127)	(39,279,930)	(20,445,056)	(11,665,822)	(1,640,671)	3,601,320	(2,777)	(57,308,977)	(32,192,704)	(33,061,726)
	Secured and unsecured obligations	(94,429,975)	(80,843,198)	(78,729,951)	(67,467,407)	(90,623,554)	(80,574,024)	(30,709,641)	(14,045,547)	(12,984,782)	(192,607,023)	(185,512,299)	(172,288,757)
	Other	(57,788,028)	(13,325,041)	14,187,547	(264,172,432)	(164,384,566)	(243,573,835)	49,075,467	9,959,270	2,422,442	(272,884,993)	(167,750,337)	(226,963,846)
	Gains (losses) from indexed assets and liabilities	-	-	-	-	1,240	1,579	(698,141)	(9,267,280)	(13,631,647)	(698,141)	(9,266,040)	(13,630,068)
	Foreign currency exchange differences	22,982,090	121,349,831	(47,698,903)	3,465,051	139,163	(1,806,825)	13,403,421	6,749,053	31,012,134	39,850,562	128,238,047	(18,493,594)
	Positive	86,750,004	219,603,572	39,651,691	28,050,640	9,537,474	4,303,366	59,667,933	45,868,225	57,413,955	174,468,577	275,009,271	101,369,012
	Negative	(63,767,914)	(98,253,741)	(87,350,594)	(24,585,589)	(9,398,311)	(6,110,191)	(46,264,512)	(39,119,172)	(26,401,821)	(134,618,015)	(146,771,224)	(119,862,606)
	Share of profit (loss) of associates and joint ventures accounted for using the equity method	1,209,140	2,678,513	-	975,936	787,056	2,595,760	(354,929)	(132,598)	(35,737)	1,830,147	3,332,971	2,560,023
	Other gains (losses)	19,167,677	(394,854)	798,130	(10,964,459)	(6,171,371)	78,424	6,265	-	-	8,209,483	(6,566,225)	876,554
	Gain (loss) from other investments	-	-	707,468	(9,266,479)	-	-	265	-	-	(9,266,214)	-	707,468
	Gain (loss) from the sale of property, plants and equipment	19,167,677	(394,854)	90,662	(1,697,980)	(6,171,371)	78,424	6,000	-	-	17,475,697	(6,566,225)	169,086
Income before tax		630,849,484	816,844,146	778,549,578	315,406,012	469,753,800	351,673,969	(15,771,899)	(6,785,775)	47,897,142	930,483,597	1,279,812,171	1,178,120,689
	Income tax	(249,299,022)	(335,604,989)	(254,393,601)	(128,995,175)	(135,349,415)	(124,465,813)	18,925,675	(52,708,808)	(47,098,048)	(359,368,522)	(523,663,212)	(425,957,462)
Net income from continuing operations		381,550,462	481,239,157	524,155,977	186,410,837	334,404,385	227,208,156	3,153,776	(59,494,583)	799,094	571,115,075	756,148,959	752,163,227
	Income from discontinued operations	-	-	-	-	-	-	115,130,387	388,320,526	215,331,981	115,130,387	388,320,526	215,331,981
NET INCOME		381,550,462	481,239,157	524,155,977	186,410,837	334,404,385	227,208,156	118,284,163	328,825,943	216,131,075	686,245,462	1,144,469,485	967,495,208
	Net income attributable to:	381,550,462	481,239,157	524,155,977	186,410,837	334,404,385	227,208,156	118,284,163	328,825,943	216,131,075	686,245,462	1,144,469,485	967,495,208
	Shareholders of Enel Américas	-	-	-	-	-	-	-	-	-	383,059,534	661,586,917	571,873,342
	Non-controlling interests	-	-	-	-	-	-	-	-	-	303,185,928	482,882,568	395,621,866
Line of Business		Generation and Transmission			Distribution			Holdings, eliminations and others			Total
STATEMENT OF CASH FLOWS		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
	Net cash flows from (used in) operating activities	881,297,021	1,098,739,134	1,026,718,651	928,174,791	945,599,327	769,341,885	(97,232,340)	(120,887,859)	(98,022,542)	1,712,239,472	1,923,450,602	1,698,037,994
	Net cash flows from (used in) investing activities	(133,221,872)	(545,677,324)	(357,107,188)	(541,383,688)	(787,409,305)	(513,969,018)	177,634,044	117,787,581	571,389,216	(496,971,516)	(1,215,299,048)	(299,686,990)
	Net cash flows from (used in) financing activities	(539,803,190)	(797,630,653)	(575,096,742)	(200,626,496)	(225,244,202)	(220,294,230)	778,293	(37,339,524)	(488,068,691)	(739,651,393)	(1,060,214,379)	(1,283,459,663)

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

F-136

32.3 Segment information by country

Country		Chile ( Holdings y Others)		Argentina		Brazil		Colombia		Peru		Holdings, eliminations and others		Total
ASSETS		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS		1,133,059,486	7,206,153,017	383,395,558	335,086,963	924,414,972	790,909,682	466,871,907	372,444,839	360,638,046	246,261,307	(71,129,108)	-            1,037,294,098	3,197,250,861	7,913,561,710
	Cash and cash equivalents	976,219,832	842,075,831	145,279,563	46,181,049	199,882,961	91,204,686	275,859,549	156,927,518	203,268,392	48,774,260	-	-	1,800,510,297	1,185,163,344
	Other current financial assets	21,865,047	16,360,472	1,005,572	694,177	65,402,649	48,170,095	2,942,186	3,037,702	4,151	-	-	-	91,219,605	68,262,446
	Other current non-financial assets	156,147	41,022	4,815,123	2,763,894	75,671,465	80,268,243	4,851,565	9,724,564	10,530,925	9,191,334	-	-	96,025,225	101,989,057
	Trade and other current receivables	1,548,281	729,821	215,433,621	216,550,824	539,265,384	536,725,492	155,019,920	179,304,792	118,865,628	154,034,146	86,393	786,492	1,030,219,227	1,088,131,567
	Current accounts receivable from related parties	74,330,831	72,105,375	3,181,663	24,224,813	22,322,154	19,580,577	356,628	2,063,025	1,565,424	1,292,410	(71,215,501)	-               115,699,270	30,541,199	3,566,930
	Inventories	-	-	10,897,843	40,147,347	1,693,458	900,446	27,842,059	21,381,902	25,976,689	32,628,202	-	-	66,410,049	95,057,897
	Current tax assets	58,939,348	28,523,295	2,782,173	4,524,859	20,176,901	14,060,143	-	5,336	426,837	340,955	-	-	82,325,259	47,454,588
	Non-current assets or disposal groups held-for-sale or held for distribution to owners	-	6,246,317,201	-	-	-	-	-	-	-	-	-	-               922,381,320	-	5,323,935,881
NON-CURRENT ASSETS		4,083,711,290	4,419,757,344	934,323,659	989,117,985	2,480,737,723	2,026,630,282	2,820,444,766	2,655,603,106	1,592,297,489	1,626,705,797	(3,827,210,282)	-            4,182,221,833	8,084,304,645	7,535,592,681
	Other non-current financial assets	-	-	336,183	21,751	687,479,197	488,876,852	1,277,058	616,296	-	13,305	-	-	689,092,438	489,528,204
	Other non-current non-financial assets	1,608,523	9,809,121	2,085,239	3,927,495	64,736,129	60,707,204	4,145,289	3,380,076	-	-	-	-                      261,188	72,575,180	77,562,708
	Trade and other non-current receivables	159,825	-	277,661,656	307,327,055	59,280,698	81,551,731	22,545,417	9,817,078	-	-	-	-	359,647,596	398,695,864
	Non-current accounts receivable from related parties	34,660,419	-	240,677	355,485	13,259,121	34,884,531	-	-	-	-	(47,919,540)	-                 34,884,531	240,677	355,485
	Investments accounted for using the equity method	4,044,244,975	4,392,452,234	26,179,549	33,278,110	-	-	5,645	29,497,710	87,863,952	78,272,852	(4,157,109,160)	-            4,502,540,461	1,184,961	30,960,445
	Intangible assets other than goodwill	-	-	5,174,866	1,901,334	1,133,804,899	910,420,453	48,839,016	36,607,957	24,027,963	32,469,528	-	-	1,211,846,744	981,399,272
	Goodwill	-	-	822,088	1,070,609	87,951,185	76,703,162	4,263,044	4,285,457	7,654,387	6,675,472	377,818,418	355,464,347	478,509,122	444,199,047
	Property, plant and equipment	-		621,823,401	640,616,088	341,130,124	307,829,742	2,714,632,347	2,545,846,163	1,472,751,187	1,509,274,640	-	-	5,150,337,059	5,003,566,633
	Deferred tax assets	3,037,548	17,495,989	-	620,058	93,096,370	65,656,607	24,736,950	25,552,369	-	-	-	-	120,870,868	109,325,023
TOTAL ASSETS		5,216,770,776	11,625,910,361	1,317,719,217	1,324,204,948	3,405,152,695	2,817,539,964	3,287,316,673	3,028,047,945	1,952,935,535	1,872,967,104	(3,898,339,390)	(5,219,515,931)	11,281,555,506	15,449,154,391
Country		Chile ( Holdings y Others)		Argentina		Brazil		Colombia		Peru		Holdings, eliminations and others		Total
LIABILITIES AND EQUITY		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES		585,878,623	2,214,708,056	660,811,979	650,930,971	829,389,573	649,275,989	648,166,283	589,400,597	345,878,331	313,823,925	(511,334,435)	87,241,262	2,558,790,354	4,505,380,800
	Other current financial liabilities	9,888,909	251,988,261	3,224,402	30,883,517	207,470,193	136,422,798	204,327,709	170,601,821	79,773,150	97,977,111	-	-	504,684,363	687,873,508
	Trade and other current payables	41,192,361	30,630,264	543,831,664	524,765,510	516,464,380	438,614,827	324,881,007	258,880,100	199,962,821	149,516,849	29,008,642	50,416,657	1,655,340,875	1,452,824,207
	Current accounts payable to related parties	522,734,153	37,738,690	4,482,529	23,671,742	67,927,812	50,826,174	40,756,687	30,878,126	16,145,935	8,587,452	(540,343,077)	(41,804,676)	111,704,039	109,897,508
	Other current provisions	11,978,524	3,595	66,569,258	30,169,043	1,206,376	2,144,014	24,730,876	77,759,932	15,528,411	17,222,592	-	-	120,013,445	127,299,176
	Current tax liabilities	84,676	27,324,425	42,704,126	41,441,159	32,477,743	19,959,622	53,205,885	49,992,270	6,403,903	3,890,484	-	-	134,876,333	142,607,960
	Current provisions for employee benefits	-	-	-	-	-	-	-	-	-	-	-	-	-	-
	Other current non-financial liabilities	-	-	-	-	3,843,069	1,308,554	264,119	1,288,348	28,064,111	36,629,437	-	-	32,171,299	39,226,339
	Liabilities associated with groups of assets or disposal groups held for sale or distribution to owners	-	1,867,022,821	-	-	-	-	-	-	-		-	78,629,281	-	1,945,652,102
NON-CURRENT LIABILITIES		409,583,719	25,261,654	386,453,073	393,937,987	821,843,411	725,609,705	1,291,008,588	1,113,128,603	571,618,249	555,256,672	(32,990,461)	(59,229,410)	3,447,516,579	2,753,965,211
	Other non-current financial liabilities	407,651,655	22,163,958	32,097,548	38,637,260	447,029,924	424,551,031	1,145,664,586	1,012,352,174	364,310,181	349,592,169	-	-	2,396,753,894	1,847,296,592
	Trade and other non-current payables	144	-	291,303,551	249,256,884	44,576,094	25,765,233	-	-	6,755,833	8,522,137	139,259	-	342,774,881	283,544,254
	Non-current accounts payable to related parties	-	-	-	35,630,861	33,129,720	23,598,549	-	-	-	-	(33,129,720)	(59,229,410)	-	-
	Other long-term provisions	-	-	11,913,432	10,544,604	167,144,707	132,216,036	49,693,751	36,538,802	4,527,596	4,548,842	-	-	233,279,486	183,848,284
	Deferred tax liabilities	-	-	37,124,077	46,358,947	8,709,988	15,701,628	-	-	174,795,592	169,844,040	-	-	220,629,657	231,904,615
	Non-current provisions for employee benefits	1,931,920	3,097,696	13,469,373	13,509,431	121,252,978	103,777,228	89,148,229	64,237,627	2,722,824	2,648,492	-	-	228,525,324	187,270,474
	Other non-current non-financial liabilities	-	-	545,092	-	-	-	6,502,022	-	18,506,223	20,100,992	-	-	25,553,337	20,100,992
EQUITY		4,221,308,434	9,385,940,651	270,454,165	279,335,990	1,753,919,711	1,442,654,270	1,348,141,802	1,325,518,745	1,035,438,955	1,003,886,507	(3,354,014,494)	(5,247,527,783)	5,275,248,573	8,189,808,380
Equity attributable to shareholders of Enel Américas		4,221,308,434	9,385,940,651	270,454,165	279,335,990	1,753,919,711	1,442,654,270	1,348,141,802	1,325,518,745	1,035,438,955	1,003,886,507	(3,354,014,494)	(5,247,527,783)	4,150,468,890	6,026,149,285
	Issued capital	4,887,115,404	8,275,947,660	158,141,600	157,658,399	287,284,757	216,661,867	148,731,647	149,451,431	510,245,405	484,427,384	(1,369,709,635)	(3,479,698,755)	4,621,809,178	5,804,447,986
	Retained earnings	1,675,148,316	3,903,767,587	197,754,436	24,530,244	167,496,700	144,278,288	236,308,527	322,708,452	36,035,147	66,656,282	(169,685,968)	(1,081,279,330)	2,143,057,158	3,380,661,523
	Share premium	-	206,574,859	-	-	614,091,688	535,555,881	67,571,929	2,981,182	47,439	49,641	(681,711,056)	(745,161,563)	-	-
	Treasury shares	(94,046,713)	-	-	-	-	-	-	-	-	-	-	-	(94,046,713)	-
	Other reservers	(2,246,908,573)	(3,000,349,455)	(85,441,871)	97,147,347	685,046,566	546,158,234	895,529,699	850,377,680	489,110,964	452,753,200	(1,132,907,835)	58,611,865	(2,520,350,733)	(3,158,960,224)
Non-controlling interests		-	-	-	-	-	-	-	-	-	-	-	-	1,124,779,683	2,163,659,095
Total Liabilities and Equity		5,216,770,776	11,625,910,361	1,317,719,217	1,324,204,948	3,405,152,695	2,817,539,964	3,287,316,673	3,028,047,945	1,952,935,535	1,872,967,104	(3,898,339,390)	(5,219,515,931)	11,281,555,506	15,449,154,391

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

F-137

Country		Chile (Holdings and Others)			Argentina			Brazil			Colombia			Peru			Holdings, eliminations and others			Total
STATEMENT OF OTHER COMPREHENSIVE INCOME		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
REVENUE AND OTHER OPERATING INCOME		7,595,186	4,346,811	5,160,988	870,307,176	817,366,617	538,871,174	1,879,878,846	2,013,355,544	2,266,459,965	1,533,414,307	1,568,088,010	1,601,692,843	906,090,455	902,656,878	796,341,810	-	(4,374,282)	(2,156,992)	5,197,285,970	5,301,439,578	5,206,369,788
	Revenue	6,442,501	4,342,565	5,160,988	782,263,132	435,789,546	346,911,584	1,555,179,472	1,782,667,222	2,081,466,805	1,521,752,727	1,551,589,289	1,590,209,560	902,487,859	897,613,346	784,863,792	-	(4,356,658)	(2,156,992)	4,768,125,691	4,667,645,310	4,806,455,737
	Energy sales	-	-	-	740,635,365	379,092,257	280,176,215	1,404,320,028	1,626,946,066	1,923,078,033	1,382,288,167	1,415,825,122	1,445,643,276	796,664,798	802,518,254	701,058,885	-	-	(122,447)	4,323,908,358	4,224,381,699	4,349,833,962
	Other sales	6,144,846	-	-	139,001	460,133	523,507	1,424,402	16,073,260	16,820,481	10,033,998	7,508,473	492,002	17,630,813	16,606,185	16,384,949	-	-	-	35,373,060	40,648,051	34,220,939
	Other services rendered	297,655	4,342,565	5,160,988	41,488,766	56,237,156	66,211,862	149,435,042	139,647,896	141,568,291	129,430,562	128,255,694	144,074,282	88,192,248	78,488,907	67,419,958	-	(4,356,658)	(2,034,545)	408,844,273	402,615,560	422,400,836
	Other operating income	1,152,685	4,246	-	88,044,044	381,577,071	191,959,590	324,699,374	230,688,322	184,993,160	11,661,580	16,498,721	11,483,283	3,602,596	5,043,532	11,478,018	-	(17,624)	-	429,160,279	633,794,268	399,914,051
RAW MATERIALS AND CONSUMABLES USED		(2,833,924)	-	-	(362,890,339)	(207,711,417)	(209,270,232)	(1,130,554,814)	(1,385,921,253)	(1,405,383,543)	(656,249,653)	(727,204,325)	(634,092,249)	(492,570,075)	(456,364,517)	(382,923,412)	-	-	-	(2,645,098,805)	(2,777,201,512)	(2,631,669,436)
	Energy purchases	-	-	-	(268,100,580)	(157,071,520)	(165,988,305)	(699,699,499)	(992,325,912)	(1,041,607,105)	(386,095,894)	(467,945,400)	(389,379,482)	(299,679,947)	(271,677,147)	(230,083,919)	1,969,103	3,103,553	3,056,025	(1,651,606,817)	(1,885,916,426)	(1,824,002,786)
	Fuel consumption	-	-	-	(49,122,888)	(39,487,378)	(31,350,429)	(49,847,399)	(61,626,347)	(58,409,123)	(47,273,727)	(62,987,536)	(33,015,871)	(98,642,019)	(94,012,661)	(82,758,971)	-	-	-	(244,886,033)	(258,113,922)	(205,534,394)
	Transportation expense	-	-	-	(3,305,873)	(1,603,737)	(2,887,611)	(76,356,468)	(74,851,323)	(93,644,111)	(136,015,042)	(122,810,084)	(130,555,197)	(48,837,978)	(43,444,677)	(35,042,438)	(1,969,103)	(3,103,553)	(3,056,025)	(266,484,464)	(245,813,374)	(265,185,382)
	Other miscellaneous supplies and services	(2,833,924)	-	-	(42,360,998)	(9,548,782)	(9,043,887)	(304,651,448)	(257,117,671)	(211,723,204)	(86,864,990)	(73,461,305)	(81,141,699)	(45,410,131)	(47,230,032)	(35,038,084)	-	-	-	(482,121,491)	(387,357,790)	(336,946,874)
CONTRIBUTION MARGIN		4,761,262	4,346,811	5,160,988	507,416,837	609,655,200	329,600,942	749,324,032	627,434,291	861,076,422	877,164,654	840,883,685	967,600,594	413,520,380	446,292,361	413,418,398	-	(4,374,282)	(2,156,992)	2,552,187,165	2,524,238,066	2,574,700,352
	Other works performed by the entity and capitalized	-	-	-	36,385,952	38,651,134	27,871,088	17,315,365	10,165,042	12,046,728	8,856,176	9,792,909	10,209,703	4,688,892	4,859,848	3,969,512	-	3,632,336	1,673,387	67,246,385	67,101,269	55,770,418
	Employee benefits expense	(10,096,380)	(6,198,154)	(4,663,987)	(223,384,619)	(282,962,098)	(182,617,639)	(95,846,256)	(99,652,482)	(107,989,443)	(51,595,737)	(57,583,893)	(55,772,427)	(42,441,106)	(41,301,520)	(38,624,977)	-	-	-	(423,364,098)	(487,698,147)	(389,668,473)
	Other expenses	(34,171,019)	(8,580,775)	(904,591)	(112,322,613)	(160,072,998)	(150,390,844)	(235,273,667)	(176,649,576)	(169,097,432)	(90,859,032)	(85,846,339)	(91,510,241)	(80,074,399)	(58,121,007)	(52,309,761)	-	741,946	483,605	(552,700,730)	(488,528,749)	(463,729,264)
GROSS OPERATING RESULTS		(39,506,137)	(10,432,118)	(407,590)	208,095,557	205,271,238	24,463,547	435,519,474	361,297,275	596,036,275	743,566,061	707,246,362	830,527,629	295,693,767	351,729,682	326,453,172	-	-	-	1,643,368,722	1,615,112,439	1,777,073,033
	Depreciation and amortization expense	(144,304)	-	-	(41,882,784)	(48,164,380)	(34,457,311)	(100,485,832)	(93,577,654)	(126,219,710)	(101,069,493)	(98,604,705)	(115,830,740)	(76,416,628)	(80,195,458)	(74,234,989)	-	-	-	(319,999,041)	(320,542,197)	(350,742,750)
	Impairment (losses) reversals recognized in profit or loss	(1,068,657)	-	-	(9,255,836)	(2,289,187)	(2,641,255)	(70,475,908)	(31,029,774)	(29,563,651)	(24,025,279)	(189,779)	(3,189,097)	(1,388,976)	(6,303,016)	(2,935,939)		-	-	(106,214,656)	(39,811,756)	(38,329,942)
OPERATING INCOME		(40,719,098)	(10,432,118)	(407,590)	156,956,937	154,817,671	(12,635,019)	264,557,734	236,689,847	440,252,914	618,471,289	608,451,878	711,507,792	217,888,163	265,231,208	249,282,244	-	-	-	1,217,155,025	1,254,758,486	1,388,000,341
FINANCIAL RESULTS		19,437,204	(1,613,675)	2,287,603	(103,841,461)	130,614,694	(39,636,349)	(55,750,402)	708,538	(127,456,000)	(133,313,204)	(67,348,700)	(61,236,977)	(23,243,195)	(34,073,918)	(23,920,963)	-	-	36,646,457	(296,711,058)	28,286,939	(213,316,229)
	Financial income	33,834,485	23,085,427	37,359,473	42,151,978	141,071,582	112,698,022	94,951,239	118,746,948	88,275,167	16,189,617	10,037,527	18,603,031	4,607,815	4,305,859	3,921,832	(4,797,620)	(2,477,071)	(9,735,763)	186,937,514	294,770,272	251,121,762
	Cash and cash equivalents	30,065,485	23,058,503	27,551,155	34,854,462	76,904,478	4,063,184	20,981,818	15,980,631	39,601,245	13,534,226	6,394,711	13,228,981	2,208,954	1,976,131	2,132,408				101,644,945	124,314,454	86,576,973
	Other financial income	3,769,000	26,924	9,808,318	7,297,516	64,167,104	108,634,838	73,969,421	102,766,317	48,673,922	2,655,391	3,642,816	5,374,050	2,398,861	2,329,728	1,789,424	(4,797,620)	(2,477,071)	(9,735,763)	85,292,569	170,455,818	164,544,789
	Financial costs	(25,337,374)	(23,676,545)	(22,139,600)	(168,218,270)	(111,418,295)	(90,124,247)	(156,997,166)	(142,493,697)	(227,554,883)	(149,795,850)	(78,846,539)	(78,795,617)	(27,105,556)	(31,497,335)	(23,435,746)	4,653,223	2,477,071	9,735,764	(522,800,993)	(385,455,340)	(432,314,329)
	Bank borrowings	(522)	(974)	-	(1,484,758)	(6,430,781)	(11,090,608)	(33,369,245)	(17,755,433)	(8,986,098)	(16,719,506)	(8,596,624)	(6,395,703)	(5,734,946)	(6,137,221)	(6,589,317)				(57,308,977)	(38,921,033)	(33,061,726)
	Secured and unsecured obligations	(15,935,517)	(14,045,548)	(12,984,782)	-		-	(39,355,313)	(49,470,132)	(43,100,513)	(119,681,990)	(98,156,546)	(99,009,223)	(17,634,203)	(17,586,333)	(17,194,239)				(192,607,023)	(179,258,559)	(172,288,757)
	Other	(9,401,335)	(9,630,023)	(9,154,818)	(166,733,512)	(104,987,514)	(79,033,639)	(84,272,608)	(75,268,132)	(175,468,272)	(13,394,354)	27,906,631	26,609,309	(3,736,407)	(7,773,781)	347,810	4,653,223	2,477,071	9,735,764	(272,884,993)	(167,275,748)	(226,963,846)
	Gains (losses) from indexed assets and liabilities	(698,141)	(9,266,040)	(13,630,068)	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	(698,141)	(9,266,040)	(13,630,068)
	Foreign currency exchange differences	11,638,234	8,243,483	697,798	22,224,831	100,961,407	(62,210,124)	6,295,525	24,455,287	11,823,716	293,029	1,460,312	(1,044,391)	(745,454)	(6,882,442)	(4,407,049)	144,397	-	36,646,456	39,850,562	128,238,047	(18,493,594)
	Positve	53,920,867	61,064,473	73,497,873	55,206,016	193,605,073	17,360,161	47,341,313	51,717,523	16,882,667	4,205,567	3,433,799	1,520,289	25,166,630	3,435,721	3,950,172	(11,371,816)	(38,247,318)	(11,842,150)	174,468,577	275,009,271	101,369,012
	Negative	(42,282,633)	(52,820,990)	(72,800,075)	(32,981,185)	(92,643,666)	(79,570,285)	(41,045,788)	(27,262,236)	(5,058,951)	(3,912,538)	(1,973,487)	(2,564,680)	(25,912,084)	(10,318,163)	(8,357,221)	11,516,213	38,247,318	48,488,606	(134,618,015)	(146,771,224)	(119,862,606)
	Share of profit (loss) of associates and joint ventures accounted for using the equity method	(354,929)	(132,598)	(35,735)	1,209,232	2,712,948	34,720	-	-	-	975,844	752,621	2,561,038	-	-	-	-	-	-	1,830,147	3,332,971	2,560,023
	Other gains (losses)	6,265	-	-	(28,952)	(315,656)	662,310	(832,957)	(6,758,695)	-	(10,144,165)	(238,818)	120,697	19,209,292	746,944	93,547	-	-	-	8,209,483	(6,566,225)	876,554
	Gain (loss) from other investments	265		-	38,164	-	707,468	-	-	-	(9,304,643)	-	-	-	-	-	-	-	-	(9,266,214)	-	707,468
	Gain (loss) from sale of property, plant and equipment	6,000	-	-	(67,116)	(315,656)	(45,158)	(832,957)	(6,758,695)	-	(839,522)	(238,818)	120,697	19,209,292	746,944	93,547	-	-	-	17,475,697	(6,566,225)	169,086
Income before tax		(21,630,558)	(12,178,391)	1,844,278	54,295,756	287,829,657	(51,574,338)	207,974,375	230,639,690	312,796,914	475,989,764	541,616,981	652,952,550	213,854,260	231,904,234	225,454,828	-	-	36,646,457	930,483,597	1,279,812,171	1,178,120,689
	Income tax	12,057,716	(93,756,951)	(56,501,196)	(30,207,431)	(79,403,591)	(25,322,535)	(47,039,172)	(73,751,149)	(83,386,302)	(197,957,750)	(205,841,587)	(208,404,127)	(96,221,885)	(70,909,934)	(52,343,302)	-	-	-	(359,368,522)	(523,663,212)	(425,957,462)
Net income from continuing operations		(9,572,842)	(105,935,342)	(54,656,918)	24,088,325	208,426,066	(76,896,873)	160,935,203	156,888,541	229,410,612	278,032,014	335,775,394	444,548,423	117,632,375	160,994,300	173,111,526	-	-	36,646,457	571,115,075	756,148,959	752,163,227
	Net income from discontinued operations	115,130,387	388,320,526	215,331,981		-	-	-	-		-	-		-	-		-	-	-	115,130,387	388,320,526	215,331,981
NET INCOME		105,557,545	282,385,184	160,675,063	24,088,325	208,426,066	(76,896,873)	160,935,203	156,888,541	229,410,612	278,032,014	335,775,394	444,548,423	117,632,375	160,994,300	173,111,526	-	-	36,646,457	686,245,462	1,144,469,485	967,495,208
Country		Chile (Holdings and Others)			Argentina			Brazil			Colombia			Peru			Holdings, eliminations and others			Total
STATEMENT OF CASH FLOWS		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
	Net cash flows from (used in) operating activities	77,994,403	549,960,852	203,323,918	222,201,301	349,787,261	267,157,901	517,733,180	266,234,483	412,841,873	591,064,643	489,849,453	582,492,679	301,831,279	276,916,200	239,070,342	1,414,666	(9,297,647)	(6,848,719)	1,712,239,472	1,923,450,602	1,698,037,994
	Net cash flows from (used in) investing activities	329,557,704	40,279,970	956,586,408	(106,309,205)	(287,437,006)	(236,905,557)	(273,280,471)	(266,497,586)	(142,166,536)	(215,270,622)	(271,946,454)	(202,123,930)	(52,759,202)	(156,966,672)	(75,195,327)	(178,909,720)	(272,731,300)	(599,882,048)	(496,971,516)	(1,215,299,048)	(299,686,990)
	Net cash flows from (used in) financing activities	(425,128,976)	(603,778,788)	(1,096,385,941)	8,514,418	(28,362,528)	(28,140,190)	(157,916,680)	(78,409,908)	(326,502,619)	(251,684,610)	(425,470,875)	(320,548,584)	(90,881,039)	(206,144,926)	(118,613,377)	177,445,494	281,952,646	606,731,048	(739,651,393)	(1,060,214,379)	(1,283,459,663)

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

F-138

32.4 Generation and Transmission, and Distribution by Country

a) Generation and transmission

Line of business		Generation and Transmission
Country		Chile		Argentina		Brazil		Colombia		Peru		Holdings, eliminations and others		Total
ASSETS		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS		-	5,216,028,617	131,013,959	143,791,564	177,167,193	109,584,185	193,951,548	172,957,080	263,515,857	172,786,358	(19,888,914)	(1,840,838,256)	745,759,643	3,974,309,548
	Cash and cash equivalents	-	13,726,062	41,760,752	21,513,878	57,006,162	22,236,032	138,039,685	66,939,946	158,112,135	33,818,918	-	-	394,918,734	158,234,836
	Other current financial assets	-	2,649,187	-	-	14,763,882	5,824,350	2,890,452	2,992,716	4,151	-	-	-	17,658,485	11,466,253
	Other current non-financial assets	-	47	1,443,895	1,458,900	6,990,632	11,386,388	2,141,918	7,812,064	7,242,579	6,237,667	-	-	17,819,024	26,895,066
	Trade and other current receivables	-	15,361	79,484,119	91,879,708	51,686,998	27,816,899	41,022,853	80,179,914	43,538,850	81,432,845	(27,485)	209,266	215,705,335	281,533,993
	Current accounts receivable from related parties	-	28,482,912	3,283,009	24,188,529	43,774,996	40,682,826	72,052	7,299,356	34,638,348	28,001,327	(19,861,429)	(58,956,778)	61,906,976	69,698,172
	Inventories	-	-	2,260,011	2,707,246	322,652	19,388	9,784,588	7,727,748	19,946,097	23,211,279	-	-	32,313,348	33,665,661
	Current tax assets	-	-	2,782,173	2,043,303	2,621,871	1,618,302	-	5,336	33,697	84,322	-	-	5,437,741	3,751,263
	Non-current assets or disposal groups held for sale or held for distribution to owners	-	5,171,155,048	-	-	-	-	-	-	-	-	-	(1,782,090,744)	-	3,389,064,304
NON-CURRENT ASSETS		-	34,135	464,827,055	514,526,563	398,856,323	377,376,503	1,820,385,877	1,807,828,818	855,738,618	903,328,613	-	467,827,511	3,539,807,873	4,070,922,143
	Other non-current financial assets	-	-	(412)	-	1	1	1,267,472	612,676	-	13,305	-	-	1,267,061	625,982
	Other non-current non-financial assets	-	-	1,834,261	3,600,646	5,080,410	5,159,456	1,422,891	1,087,677	-	-	-	-	8,337,562	9,847,779
	Trade and other non-current receivables	-	-	276,413,879	301,118,584	9,126,684	7,390,854	6,957,302	1,942,063	-	-	-	-	292,497,865	310,451,501
	Non-current accounts receivable from related parties	-	-	-	-	-	24,422,654	-	-	-	-	-	(24,422,654)	-	-
	Investments accounted for using the equity method	-	-	2,668,324	2,083,893	37,300,460	32,530,127	-	-	51,448,776	40,166,814	-	403,581,048	91,417,560	478,361,882
	Intangible assets other than goodwill	-	-	-	44,948	3,219,490	2,367,312	22,381,473	20,180,823	10,796,639	11,072,435	-	-	36,397,602	33,665,518
	Goodwill	-	-	822,088	1,070,608	-	-	4,263,044	4,285,458	7,654,387	6,675,472	-	88,669,117	12,739,519	100,700,655
	Property, plant and equipment	-	-	183,088,915	205,987,826	321,053,944	284,339,062	1,762,482,875	1,761,539,131	785,838,816	845,400,587	-	-	3,052,464,550	3,097,266,606
	Deferred tax assets	-	34,135	-	620,058	23,075,334	21,167,037	21,610,820	18,180,990	-	-	-	-	44,686,154	40,002,220
TOTAL ASSETS		-	5,216,062,752	595,841,014	658,318,127	576,023,516	486,960,688	2,014,337,425	1,980,785,898	1,119,254,475	1,076,114,971	(19,888,914)	(1,373,010,745)	4,285,567,516	8,045,231,691
Line of business		Generation and Transmission
Country		Chile		Argentina		Brazil		Colombia		Peru		Holdings, eliminations and others		Total
LIABILITIES AND EQUITY		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES		-	1,828,533,074	164,455,606	219,381,678	164,430,623	126,744,267	283,176,032	349,716,663	180,620,249	149,548,832	-	61,192,354	792,682,510	2,735,116,868
	Other current financial liabilities	-	417,400	3,224,402	30,356,957	1,821,651	1,718,719	103,261,274	135,606,953	44,685,358	62,170,269	-	-	152,992,685	230,270,298
	Trade and other current payables	-	158,892	107,993,996	121,997,587	74,995,236	47,259,646	103,343,637	89,385,378	108,345,809	67,063,567	-	16,847,277	394,678,678	342,712,347
	Current accounts payable to related parties	-	2,336	3,849,497	22,841,700	52,259,088	57,806,281	25,736,524	22,926,498	14,703,008	11,770,115	-	(10,778,741)	96,548,117	104,568,189
	Other current provisions		-	7,404,534	2,744,275	-	-	18,688,050	72,379,364	5,650,059	6,295,715	-	-	31,742,643	81,419,354
	Current tax liabilities		-	41,983,177	41,441,159	32,477,740	19,959,621	32,146,547	28,563,318	6,403,903	1,153,023	-	-	113,011,367	91,117,121
	Current provisions for employee benefits		-	-	-	-	-	-	-	-	-	-	-	-	-
	Other current non-financial liabilities		-	-	-	2,876,908	-	-	855,152	832,112	1,096,143	-	-	3,709,020	1,951,295
	Liabilities associated with assets or disposal groups held for sale or distribution to owners	-	1,827,954,446	-	-	-	-	-	-	-	-	-	55,123,818	-	1,883,078,264
NON-CURRENT LIABILITIES		-	199,807	186,170,232	218,971,414	40,813,336	34,180,263	949,335,325	831,187,905	269,043,112	277,281,858	(19,888,914)	(48,543,708)	1,425,473,091	1,313,277,539
	Other non-current financial liabilities	-	-	32,097,548	38,637,260	2,732,914	3,012,998	885,943,060	781,500,274	107,136,027	118,684,335	-	-	1,027,909,549	941,834,867
	Trade and other non-current payables	-	-	113,228,702	94,453,409	454,701	2,911,464	-	-	-	-	-	-	113,683,403	97,364,873
	Non-current accounts payable to related parties	-	-	-	35,630,861	33,129,720	23,598,549	-	-	-	-	(19,888,914)	(48,543,708)	13,240,806	10,685,702
	Other long-term provisions	-	-	-	-	4,496,001	4,657,252	43,583,548	32,991,300	4,219,912	4,234,681	-	-	52,299,461	41,883,233
	Deferred tax liabilites	-	-	37,124,077	46,358,947	-	-	-	-	139,613,954	134,903,163	-	-	176,738,031	181,262,110
	Non-current provisions for employee benefits	-	199,807	3,719,905	3,890,937	-	-	19,808,717	16,696,331	859,395	761,267	-	-	24,388,017	21,548,342
	Other non-current non-financial liabilities	-	-	-	-	-	-	-	-	17,213,824	18,698,412	-	-	17,213,824	18,698,412
EQUITY		-	3,387,329,871	245,215,176	219,965,035	370,779,557	326,036,158	781,826,068	799,881,330	669,591,114	649,284,281	-	(1,385,659,391)	2,067,411,915	3,996,837,284
Equity attributable to shareholders of Enel Américas		-	3,387,329,871	245,215,176	219,965,035	370,779,557	326,036,158	781,826,068	799,881,330	669,591,114	649,284,281	-	(1,385,659,391)	2,067,411,915	3,996,837,284
	Issued capital	-	2,041,622,319	100,728,542	82,865,510	103,404,348	90,172,688	145,731,804	146,498,021	336,431,842	323,227,193	-	(1,207,662,870)	686,296,536	1,476,722,861
	Retained earnings	-	1,726,639,410	236,579,694	49,183,508	163,776,977	134,179,155	146,488,536	217,958,120	35,723,032	48,944,655	-	181,696,622	582,568,239	2,358,601,470
	Share premium	-	206,008,557	-	-	-	-	25,189,885	-	47,439	49,641	-	-	25,237,324	206,058,198
	Treasury shares	-	-	-	-	-	-	-	-	-	-	-	-	-	-
	Other reserves	-	(586,940,415)	(92,093,060)	87,916,017	103,598,232	101,684,315	464,415,843	435,425,189	297,388,801	277,062,792	-	(359,693,143)	773,309,816	(44,545,245)
Non-controlling interests		-	-	-	-	-		-		-	-	-	-	-	-
TOTAL LIABILITIES AND EQUITY		-	5,216,062,752	595,841,014	658,318,127	576,023,516	486,960,688	2,014,337,425	1,980,785,898	1,119,254,475	1,076,114,971	(19,888,914)	(1,373,010,745)	4,285,567,516	8,045,231,691

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

F-139

Line of business		Generation and Transmission
Country		Chile			Argentina			Brazil			Colombia			Peru			Holdings, eliminations and others			Total
STATEMENT OF COMPREHENSIVE INCOME		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
REVENUES AND OTHER OPERATING INCOME		-	-	-	207,605,200	212,136,445	167,629,542	387,093,920	305,829,811	437,032,601	778,880,285	778,768,427	753,385,349	458,974,301	437,887,044	401,695,198	-	140,045	3,126,443	1,832,553,706	1,734,761,772	1,762,869,133
	Revenue	-	-	-	146,942,061	157,348,898	124,403,558	371,927,879	305,829,811	437,032,601	772,601,727	769,665,035	744,236,226	458,074,936	435,277,054	392,252,284	-	151,906	3,126,443	1,749,546,603	1,668,272,704	1,701,051,112
	Energy sales	-	-	-	146,931,948	118,064,590	75,488,280	320,061,268	250,599,834	369,739,130	762,550,451	762,280,521	743,649,328	359,326,082	355,087,025	325,248,022	-	-	-	1,588,869,749	1,486,031,970	1,514,124,760
	Other sales	-	-	-	-	-	-	-	-	-	9,924,392	7,290,919	476,853	17,086,394	13,833,990	12,603,162	-	-	-	27,010,786	21,124,909	13,080,015
	Other services rendered	-	-	-	10,113	39,284,308	48,915,278	51,866,611	55,229,977	67,293,471	126,884	93,595	110,045	81,662,460	66,356,039	54,401,100	-	151,906	3,126,443	133,666,068	161,115,825	173,846,337
	Other operating income	-	-	-	60,663,139	54,787,547	43,225,984	15,166,041	-	-	6,278,558	9,103,392	9,149,123	899,365	2,609,990	9,442,914	-	(11,861)	-	83,007,103	66,489,068	61,818,021
RAW MATERIALS AND CONSUMABLES USED		-	-	-	(59,538,589)	(50,332,370)	(47,296,150)	(181,654,011)	(131,431,046)	(234,224,494)	(293,212,188)	(321,664,855)	(220,460,069)	(234,673,612)	(174,512,696)	(151,707,294)	-	-	-	(769,078,400)	(677,940,967)	(653,688,007)
	Energy purchases	-	-	-	(838,294)	(1,479,711)	(5,069,376)	(112,379,413)	(57,315,995)	(155,266,089)	(131,994,695)	(162,261,692)	(80,294,031)	(65,104,559)	(17,092,514)	(21,103,383)	1,969,103	3,103,553	3,056,025	(308,347,858)	(235,046,359)	(258,676,854)
	Fuel consumption	-	-	-	(49,122,888)	(39,487,378)	(31,350,429)	(49,847,399)	(61,626,347)	(58,409,123)	(47,273,727)	(62,987,536)	(33,015,871)	(98,642,019)	(94,012,661)	(82,758,971)	-	-	-	(244,886,033)	(258,113,922)	(205,534,394)
	Transportation expenses	-	-	-	(2,493,411)	(883,161)	(1,832,459)	(13,705,014)	(12,466,467)	(16,037,191)	(71,929,576)	(64,562,969)	(68,739,282)	(48,855,594)	(43,595,972)	(35,235,902)	(1,969,103)	(3,103,553)	(3,056,025)	(138,952,698)	(124,612,122)	(124,900,859)
	Other miscellaneous supplies and services	-	-	-	(7,083,996)	(8,482,120)	(9,043,886)	(5,722,185)	(22,237)	(4,512,091)	(42,014,190)	(31,852,658)	(38,410,885)	(22,071,440)	(19,811,549)	(12,609,038)	-	-	-	(76,891,811)	(60,168,564)	(64,575,900)
CONTRIBUTION MARGIN		-	-	-	148,066,611	161,804,075	120,333,392	205,439,909	174,398,765	202,808,107	485,668,097	457,103,572	532,925,280	224,300,689	263,374,348	249,987,904	-	140,045	3,126,443	1,063,475,306	1,056,820,805	1,109,181,126
	Other works performed by the entity and capitalized	-	-	-	9,220,995	3,949,935	4,717,343	767,752	1,029,091	843,966	772,531	5,344,745	5,763,278	152,617	431,498	550,306	-	3,632,336	1,673,387	10,913,895	14,387,605	13,548,280
	Employee benefits expense	-	-	-	(45,844,715)	(56,220,837)	(40,274,266)	(10,512,638)	(11,749,621)	(14,797,349)	(15,961,883)	(20,843,530)	(20,155,909)	(18,911,716)	(18,628,501)	(16,552,441)	-	(407,907)	(398,886)	(91,230,952)	(107,850,396)	(92,178,851)
	Other expenses	-	-	-	(19,344,113)	(23,389,085)	(22,301,843)	(12,463,402)	(10,599,409)	(12,075,955)	(33,197,259)	(29,558,639)	(24,447,808)	(43,414,244)	(31,408,734)	(25,612,492)	-	(1,588,407)	11,239	(108,419,018)	(96,544,274)	(84,426,859)
GROSS OPERATING RESULTS		-	-	-	92,098,778	86,144,088	62,474,626	183,231,621	153,078,826	176,778,769	437,281,486	412,046,148	494,084,841	162,127,346	213,768,611	208,373,277	-	-	4,412,183	874,739,231	866,813,740	946,123,696
	Depreciation and amortization expense	-	-	-	(30,579,755)	(34,934,726)	(23,684,899)	(20,794,777)	(21,509,767)	(26,790,105)	(42,522,707)	(39,108,707)	(43,806,832)	(46,799,511)	(51,738,067)	(48,327,434)	-	-	-	(140,696,750)	(147,291,267)	(142,609,270)
	Impairment (losses) reversals recognized in profit or loss	-	-	-	(34,767)	-	(81,595)	(392,503)	(13,312)	(1,154,946)	(22,678,708)	(109,012)	(787,645)	-	(4,704,314)	(1,188,617)	-	-	-	(23,105,978)	(4,826,638)	(3,212,803)
OPERATING INCOME		-	-	-	61,484,256	51,209,362	38,708,132	162,044,341	131,555,747	148,833,718	372,080,071	372,828,429	449,490,364	115,327,835	157,326,230	158,857,226	-	-	-	710,936,503	714,695,835	800,301,623
FINANCIAL RESULTS		-	-	-	5,281,267	133,277,754	(1,703,723)	(513,069)	22,320,357	19,658,005	(98,230,553)	(39,872,136)	(34,591,411)	(7,001,481)	(16,392,039)	(12,653,612)	-	530,716	6,740,566	(100,463,836)	99,864,652	(22,550,175)
	Financial income	-	-	-	23,632,633	75,454,262	83,671,357	10,476,279	10,178,944	23,653,993	10,327,720	3,321,340	11,379,616	2,047,160	970,851	1,062,402	(1,323,339)	(1,893,369)	(8,683,109)	45,160,453	88,032,028	111,084,259
	Cash and cash equivalents		-	-	21,581,841	75,357,320	3,480,928	5,942,136	7,132,537	12,088,079	9,542,080	2,942,242	9,848,063	1,239,481	798,003	868,225		78,056	443,158	38,305,538	86,308,158	26,728,453
	Other financial income	-	-	-	2,050,792	96,942	80,190,429	4,534,143	3,046,407	11,565,914	785,640	379,098	1,531,553	807,679	172,848	194,177	(1,323,339)	(1,971,425)	(9,126,267)	6,854,915	1,723,870	84,355,806
	Financial costs	-	-	-	(41,062,872)	(40,380,160)	(23,365,735)	(11,650,696)	(11,661,217)	(14,528,800)	(109,051,496)	(44,085,917)	(44,880,587)	(8,164,654)	(12,234,468)	(10,024,755)	1,323,339	(1,155,445)	6,864,346	(168,606,379)	(109,517,207)	(85,935,531)
	Bank borrowings		-	-	(1,435,270)	(5,338,424)	(8,088,985)	(389,902)	(288,377)	(1,846,966)	(11,134,653)	(8,596,486)	(6,301,664)	(3,428,551)	(4,252,551)	(5,155,512)	-	3,126,870		(16,388,376)	(15,348,968)	(21,393,127)
	Secured and unsecured obligations		-	-	-	-	-	-	-		(91,569,896)	(71,452,386)	(74,994,653)	(2,860,079)	(3,137,072)	(3,735,298)	-	(6,253,740)		(94,429,975)	(80,843,198)	(78,729,951)
	Other	-	-	-	(39,627,602)	(35,041,736)	(15,276,750)	(11,260,794)	(11,372,840)	(12,681,834)	(6,346,947)	35,962,955	36,415,730	(1,876,024)	(4,844,845)	(1,133,945)	1,323,339	1,971,425	6,864,346	(57,788,028)	(13,325,041)	14,187,547
	Gains (losses) from indexed assets and liabilities	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
	Foreign currency exchange differences	-	-	-	22,711,506	98,203,652	(62,009,345)	661,348	23,802,630	10,532,812	493,223	892,441	(1,090,440)	(883,987)	(5,128,422)	(3,691,259)	-	3,579,530	8,559,329	22,982,090	121,349,831	(47,698,903)
	Positive	-	-	-	53,596,741	188,314,172	15,924,492	17,135,063	44,422,294	15,287,550	2,624,769	1,875,433	1,172,568	22,147,762	2,210,163	2,845,603	(8,754,331)	(17,218,490)	4,421,478	86,750,004	219,603,572	39,651,691
	Negative	-	-	-	(30,885,235)	(90,110,520)	(77,933,837)	(16,473,715)	(20,619,664)	(4,754,738)	(2,131,546)	(982,992)	(2,263,008)	(23,031,749)	(7,338,585)	(6,536,862)	8,754,331	20,798,020	4,137,851	(63,767,914)	(98,253,741)	(87,350,594)
	Share of profit (loss) of associates and joint ventures accounted for using the equity method	-	-	-	1,209,140	2,678,513	-	-	-	-	-	-	-	-	-	-	-	-	-	1,209,140	2,678,513	-
	Other gains (losses)	-	-	-	(67,116)	(428,872)	662,310	-	-	-	47,188	(110,332)	74,183	19,187,605	144,350	61,637	-	-	-	19,167,677	(394,854)	798,130
	Gain (loss) from other investments		-	-	-	-	707,468	-	-	-	-	-	-	-	-	-	-	-	-	-	-	707,468
	Gain (loss) from the sale of property, plant and equipment	-	-	-	(67,116)	(428,872)	(45,158)	-	-	-	47,188	(110,332)	74,183	19,187,605	144,350	61,637	-	-	-	19,167,677	(394,854)	90,662
Income before tax		-	-	-	67,907,547	186,736,757	37,666,719	161,531,272	153,876,104	168,491,723	273,896,706	332,845,961	414,973,136	127,513,959	141,078,541	146,265,251	-	530,716	6,740,566	630,849,484	816,844,146	778,549,578
	Income tax	-	-	-	(23,095,829)	(78,511,077)	(28,903,711)	(56,307,496)	(53,206,799)	(39,386,507)	(106,927,731)	(120,949,697)	(126,151,738)	(62,967,966)	(42,320,368)	(32,191,266)	-	(40,617,048)	(27,760,379)	(249,299,022)	(335,604,989)	(254,393,601)
Net Income from continuing operations		-	-	-	44,811,718	108,225,680	8,763,008	105,223,776	100,669,305	129,105,216	166,968,975	211,896,264	288,821,398	64,545,993	98,758,173	114,073,985	-	(40,086,332)	(21,019,813)	381,550,462	481,239,157	524,155,977
	Net income from discontinued operations	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
NET INCOME		-	-	-	44,811,718	108,225,680	8,763,008	105,223,776	100,669,305	129,105,216	166,968,975	211,896,264	288,821,398	64,545,993	98,758,173	114,073,985	-	(40,086,332)	(21,019,813)	381,550,462	481,239,157	524,155,977
Country		Chile			Argentina			Brazil			Colombia			Peru			Holdings, eliminations and others			Total
STATEMENT OF CASH FLOWS		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
	Net cash flows from (used in) operating activities	147,723,267	451,437,274	239,014,894	61,734,508	106,129,177	79,108,857	155,045,628	118,976,796	187,589,266	351,848,797	254,539,609	364,425,930	183,401,849	170,273,397	156,986,993	(49,560)	(2,617,119)	(407,289)	899,704,489	1,098,739,134	1,026,718,651
	Net cash flows from (used in) investing activities	(45,466,005)	(132,211,583)	34,558,119	(23,011,097)	(78,645,571)	(56,312,879)	(17,599,694)	(4,610,998)	(24,096,560)	(74,674,288)	(159,371,575)	(185,214,366)	27,529,212	(56,503,902)	(18,336,629)	-	(114,333,695)	(107,704,873)	(133,221,872)	(545,677,324)	(357,107,188)
	Net cash flows from (used in) financing activities	(152,507,855)	(320,808,291)	(281,839,416)	(9,364,296)	(20,192,869)	(18,507,611)	(108,595,502)	(159,800,756)	(122,230,027)	(204,150,609)	(259,847,758)	(151,340,517)	(83,592,396)	(153,855,492)	(109,291,615)	-	116,874,513	108,112,444	(558,210,658)	(797,630,653)	(575,096,742)

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

F-140

b) Distribution

Line of business		Distribution
Country		Chile		Argentina		Brazil		Colombia		Peru		Holdings, eliminations and others		Total
ASSETS		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS		-	1,068,956,933	253,221,877	191,441,460	679,377,555	653,342,371	275,367,757	207,553,675	132,512,236	116,371,663	(2,004,708)	(4,417,595)	1,338,474,717	2,233,248,507
	Cash and cash equivalents	-	10,694,452	103,517,648	24,665,201	86,201,338	34,293,476	137,819,864	89,987,572	45,114,127	14,818,083	-	-	372,652,977	174,458,784
	Other current financial assets	-	188,143	1,005,572	694,177	33,933,280	33,244,064	51,734	44,985	-	-	-	-	34,990,586	34,171,369
	Other current non-financial assets	-	-	3,316,942	1,261,261	67,420,508	65,958,327	2,709,647	1,912,501	3,256,631	2,944,189	-	-	76,703,728	72,076,278
	Trade and other current receivables	-	105	135,949,502	124,663,167	485,003,579	508,562,286	113,997,067	99,124,879	72,351,507	69,883,209	(759)	52,925	807,300,896	802,286,571
	Current accounts receivable from related parties	-	8,208,642	794,381	239,991	521,229	1,564,236	2,731,974	2,829,584	5,673,603	19,302,467	(2,003,949)	(4,468,556)	7,717,238	27,676,364
	Inventories	-	-	8,637,832	37,440,101	799,198	673,996	18,057,471	13,654,154	6,030,592	9,416,923	-	-	33,525,093	61,185,174
	Current tax assets	-	431,522	-	2,477,562	5,498,423	9,045,986	-	-	85,776	6,792	-	-	5,584,199	11,961,862
	Non-current assets or disposal groups held for sale or held for distribution to owners	-	1,049,434,069	-	-	-	-	-		-	-	-	(1,964)	-	1,049,432,105
NON-CURRENT ASSETS		-	462,047,875	445,997,002	443,412,233	2,096,987,666	1,662,603,605	1,000,058,888	847,774,289	699,734,546	675,858,105	-	-	4,242,778,102	4,091,696,107
	Other non-current financial assets	-	-	336,595	21,751	687,458,647	488,858,930	9,586	3,620	-	-	-	-	687,804,828	488,884,301
	Other non-current non-financial assets	-	-	250,978	326,850	59,204,962	52,122,099	2,722,397	2,292,399	-	-	-	-	62,178,337	54,741,348
	Trade and other non-current receivables	-	-	1,247,777	6,208,472	50,105,705	74,095,449	15,588,115	7,875,015	-	-	-	-	66,941,597	88,178,936
	Non-current accounts receivable from related parties	-	-	240,677	355,485	-	-	-	-	-	-	-	-	240,677	355,485
	Investments accounted for using the equity method	-	462,006,979	11,623	15,027	-	-	5,645	29,497,710	-	-	-	-	17,268	491,519,716
	Intangible assets other than goodwill	-	-	5,174,866	1,856,386	1,127,372,940	905,374,088	26,457,543	16,427,134	11,358,662	9,826,406	-	-	1,170,364,011	933,484,014
	Goodwill	-	-	-	-	87,951,185	76,703,162	-	-	-	-	-	-	87,951,185	76,703,162
	Property, plant and equipment	-	-	438,734,486	434,628,262	14,911,800	20,960,307	952,149,472	784,307,032	688,375,884	666,031,699	-	-	2,094,171,642	1,905,927,300
	Deferred tax assets	-	40,896	-	-	69,982,427	44,489,570	3,126,130	7,371,379	-	-	-	-	73,108,557	51,901,845
TOTAL ASSETS		-	1,531,004,808	699,218,879	634,853,693	2,776,365,221	2,315,945,976	1,275,426,645	1,055,327,964	832,246,782	792,229,768	(2,004,708)	(4,417,595)	5,581,252,819	6,324,944,614
Line of business		Distribution
Country		Chile		Argentina		Brazil		Colombia		Peru		Holdings, eliminations and others		Total
LIABILITIES AND EQUITY		12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015	12-31-2016	12-31-2015
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES		-	418,047,564	497,137,195	431,630,046	710,291,176	552,804,640	367,437,649	247,749,856	184,218,301	192,540,953	(2,004,708)	(4,417,595)	1,757,079,613	1,838,355,464
	Other current financial liabilities	-	92,682	-	526,559	205,648,540	134,704,079	101,066,435	34,994,868	35,087,792	35,806,842	-	-	341,802,767	206,125,030
	Trade and other current payables	-	293,820	435,634,269	402,486,702	428,822,863	383,345,351	221,537,370	169,494,726	90,418,420	81,443,952	-	-	1,176,412,922	1,037,064,551
	Current accounts payable to related parties	-	636,116	1,617,253	1,192,017	74,613,395	32,611,195	17,467,561	16,017,544	21,601,738	26,092,527	(2,004,708)	(4,417,595)	113,295,239	72,131,804
	Other current provisions	-	3,595	59,164,724	27,424,768	1,206,377	2,144,014	6,042,826	5,380,567	9,878,352	10,926,878	-	-	76,292,279	45,879,822
	Current tax liabilities	-	-	720,949	-	1	1	21,059,338	21,428,954	-	2,737,460	-	-	21,780,288	24,166,415
	Current provisions for employee benefits	-	-	-	-	-	-	-	-	-	-	-	-	-	-
	Other current non-financial liabilities	-	-	-	-	-	-	264,119	433,197	27,231,999	35,533,294	-	-	27,496,118	35,966,491
	Liabilities associated with assets or disposal groups held for sale or distribution to owners	-	417,021,351	-	-	-	-	-	-	-	-	-	-	-	417,021,351
NON-CURRENT LIABILITIES		-	299,654	200,282,841	174,966,573	983,604,330	832,749,665	341,673,263	281,940,695	295,981,621	269,823,997	-	-	1,821,542,055	1,559,780,584
	Other non-current financial liabilities	-	-	-	-	444,297,009	421,538,033	259,721,526	230,851,899	257,174,154	230,907,835	-	-	961,192,689	883,297,767
	Trade and other non-current payables	-	-	178,074,849	154,803,475	44,120,133	22,852,766	-	-	162,317	371,317	-	-	222,357,299	178,027,558
	Non-current accounts payable to related parties	-	-	-	-	210,599,867	157,179,286	-	-	-	-	-	-	210,599,867	157,179,286
	Other long-term provisions	-	-	11,913,432	10,544,604	162,440,065	127,402,352	6,110,203	3,547,501	307,684	314,163	-	-	180,771,384	141,808,620
	Deferred tax liabilites	-	-	-	-	894,278	-	-	-	35,181,638	34,940,876	-	-	36,075,916	34,940,876
	Non-current provisions for employee benefits	-	299,654	9,749,468	9,618,494	121,252,978	103,777,228	69,339,512	47,541,295	1,863,429	1,887,226	-	-	202,205,387	163,123,897
	Other non-current non-financial liabilities	-	-	545,092	-	-	-	6,502,022	-	1,292,399	1,402,580	-	-	8,339,513	1,402,580
EQUITY		-	1,112,657,590	1,798,843	28,257,074	1,082,469,715	930,391,671	566,315,733	525,637,413	352,046,860	329,864,818	-	-	2,002,631,151	2,926,808,566
Equity attributable to shareholders of Enel Américas		-	1,112,657,590	1,798,843	28,257,074	1,082,469,715	930,391,671	566,315,733	525,637,413	352,046,860	329,864,818	-	-	2,002,631,151	2,926,808,566
	Issued capital	-	367,928,682	36,136,963	47,061,353	380,815,741	312,041,595	2,999,843	2,953,410	144,634,754	130,666,525	-	-	564,587,301	860,651,565
	Retained earnings	-	1,225,045,537	(35,791,771)	(20,697,376)	61,595,016	82,104,937	89,819,991	104,750,330	15,689,942	23,507,886	-	-	131,313,178	1,414,711,314
	Share premium	-	566,302	-	-	-	-	42,382,044	2,981,182	-	-	-	-	42,382,044	3,547,484
	Treasury shares	-	-	-	-	-	-	-	-	-	-	-	-	-	-
	Other reserves	-	(480,882,931)	1,453,651	1,893,097	640,058,958	536,245,139	431,113,855	414,952,491	191,722,164	175,690,407	-	-	1,264,348,628	647,898,203
Non-controlling interests		-	-	-	-	-	-	-	-	-	-	-	-	-	-
TOTAL LIABILITIES AND EQUITY		-	1,531,004,808	699,218,879	634,853,693	2,776,365,221	2,315,945,976	1,275,426,645	1,055,327,964	832,246,782	792,229,768	(2,004,708)	(4,417,595)	5,581,252,819	6,324,944,614

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

F-141

Line of business		Distribution
Country		Chile			Argentina			Brazil			Colombia			Peru			Holdings, eliminations and others			Total
ESTADO DE RESULTADOS INTEGRALES		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
REVENUES AND OTHER OPERATING INCOME		-	-	-	664,100,267	607,344,916	371,411,786	1,684,138,548	1,836,864,322	1,969,226,185	923,911,912	884,467,266	982,770,698	585,196,341	562,046,426	478,699,891	-	-	-	3,857,347,068	3,890,722,930	3,802,108,560
	Revenue	-	-	-	635,354,040	278,475,279	222,534,863	1,374,605,215	1,606,176,000	1,784,233,025	918,407,134	876,948,863	980,294,259	582,386,858	559,556,527	476,564,658	-	-	-	3,510,753,247	3,321,156,669	3,463,626,805
	Energy sales	-	-	-	593,736,386	261,053,382	204,714,773	1,280,345,633	1,509,823,358	1,696,855,326	762,602,031	723,092,894	808,454,612	547,358,682	528,051,398	447,642,884	-	-	-	3,184,042,732	3,022,021,032	3,157,667,595
	Other sales	-	-	-	139,001	460,133	523,507	1,424,402	16,073,260	16,820,481	109,606	217,554	15,149	544,419	2,772,195	3,781,787	-	-	-	2,217,428	19,523,142	21,140,924
	Other services rendered	-	-	-	41,478,653	16,961,764	17,296,583	92,835,180	80,279,382	70,557,218	155,695,497	153,638,415	171,824,498	34,483,757	28,732,934	25,139,987	-	-	-	324,493,087	279,612,495	284,818,286
	Other operating income	-	-	-	28,746,227	328,869,637	148,876,923	309,533,333	230,688,322	184,993,160	5,504,778	7,518,403	2,476,439	2,809,483	2,489,899	2,135,233	-	-	-	346,593,821	569,566,261	338,481,755
RAW MATERIALS AND CONSUMABLES USED		-	-	-	(303,352,490)	(157,387,237)	(161,995,240)	(1,142,263,697)	(1,386,390,872)	(1,313,723,580)	(532,281,721)	(500,570,712)	(547,593,754)	(395,535,703)	(379,015,102)	(315,115,521)	-	-	-	(2,373,433,611)	(2,423,363,923)	(2,338,428,095)
	Energy purchases	-	-	-	(267,275,505)	(155,612,243)	(160,940,088)	(783,387,248)	(1,068,487,043)	(1,029,857,439)	(397,230,120)	(375,946,940)	(416,564,592)	(372,197,012)	(351,596,619)	(292,686,474)	-	-	-	(1,820,089,885)	(1,951,642,845)	(1,900,048,593)
	Fuel consumption	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
	Transportation expenses	-	-	-	(812,463)	(720,575)	(1,055,152)	(63,608,227)	(63,516,659)	(78,999,828)	(89,967,670)	(82,836,069)	(88,136,414)	-	-	-	-	-	-	(154,388,360)	(147,073,303)	(168,191,394)
	Other miscellaneous supplies and services	-	-	-	(35,264,522)	(1,054,419)	-	(295,268,222)	(254,387,170)	(204,866,313)	(45,083,931)	(41,787,703)	(42,892,748)	(23,338,691)	(27,418,483)	(22,429,047)	-	-	-	(398,955,366)	(324,647,775)	(270,188,108)
CONTRIBUTION MARGIN		-	-	-	360,747,777	449,957,679	209,416,546	541,874,851	450,473,450	655,502,605	391,630,191	383,896,554	435,176,944	189,660,638	183,031,324	163,584,370	-	-	-	1,483,913,457	1,467,359,007	1,463,680,465
	Other works performed by the entity and capitalized	-	-	-	27,164,958	34,701,198	23,153,744	16,503,934	9,135,951	11,202,763	8,083,645	4,448,164	4,446,424	4,507,477	4,282,006	3,300,324	-	-	-	56,260,014	52,567,319	42,103,255
	Employee benefits expense	-	-	-	(177,539,906)	(226,741,261)	(142,343,373)	(74,766,059)	(79,431,903)	(83,882,323)	(35,633,854)	(36,740,363)	(35,616,518)	(23,387,610)	(22,398,764)	(21,542,237)	-	(371,072)	(254,169)	(311,327,429)	(365,683,363)	(283,638,620)
	Other expenses	-	-	-	(94,219,495)	(138,623,389)	(128,124,044)	(203,261,235)	(150,045,257)	(154,016,112)	(57,901,047)	(56,460,916)	(67,631,351)	(28,003,034)	(26,536,627)	(26,098,988)	-	(1,012,454)	(995,041)	(383,384,811)	(372,678,643)	(376,865,536)
GROSS OPERATING RESULTS		-	-	-	116,153,334	119,294,227	(37,897,127)	280,351,491	230,132,241	428,806,933	306,178,935	295,143,439	336,375,499	142,777,471	138,377,939	119,243,469	-	(1,383,526)	(1,249,210)	845,461,231	781,564,320	845,279,564
	Depreciation and amortization expense	-	-	-	(11,303,027)	(13,229,654)	(10,772,411)	(79,515,562)	(71,857,411)	(99,250,848)	(58,526,488)	(59,475,177)	(71,998,972)	(30,218,032)	(29,074,143)	(26,510,068)	-	-	-	(179,563,109)	(173,636,385)	(208,532,299)
	Impairment (losses) reversals recognized in profit or loss	-	-	-	(9,221,068)	(2,289,187)	(2,559,659)	(66,703,434)	(30,940,802)	(28,330,530)	(1,346,571)	(80,720)	(2,401,454)	(1,388,976)	(1,598,702)	(1,747,322)	-	-	-	(78,660,049)	(34,909,411)	(35,038,965)
OPERATING INCOME		-	-	-	95,629,239	103,775,386	(51,229,197)	134,132,495	127,334,028	301,225,555	246,305,876	235,587,542	261,975,073	111,170,463	107,705,094	90,986,079	-	(1,383,526)	(1,249,210)	587,238,073	573,018,524	601,708,300
FINANCIAL RESULTS		-	-	-	(109,572,952)	(3,942,519)	(38,408,032)	(100,703,120)	(48,588,988)	(174,878,226)	(35,066,292)	(27,459,740)	(26,624,088)	(16,501,174)	(16,772,560)	(11,494,113)	-	(1,116,602)	(1,304,056)	(261,843,538)	(97,880,409)	(252,708,515)
	Financial income	-	-	-	18,340,961	65,153,401	28,970,378	78,342,195	102,075,187	45,864,512	5,920,503	6,745,819	7,242,116	3,007,521	3,221,357	2,830,626	-	236,600	2,780	105,611,180	177,432,364	84,910,412
	Cash and cash equivalents	-	-	-	12,985,856	1,303,146	532,645	9,672,857	2,924,921	9,641,862	3,991,858	3,452,375	3,377,089	718,571	892,016	1,063,623	-	236,600	2,780	27,369,142	8,809,058	14,617,999
	Other financial income	-	-	-	5,355,105	63,850,255	28,437,733	68,669,338	99,150,266	36,222,650	1,928,645	3,293,444	3,865,027	2,288,950	2,329,341	1,767,003	-	-	-	78,242,038	168,623,306	70,292,413
	Financial costs	-	-	-	(127,083,732)	(70,851,224)	(66,547,390)	(183,299,326)	(150,058,877)	(221,272,601)	(40,786,634)	(34,773,430)	(33,912,253)	(19,750,077)	(19,294,082)	(14,065,160)	-	(475,563)	(16,277)	(370,919,769)	(275,453,176)	(335,813,681)
	Bank borrowings	-	-	-	(1,435,270)	(1,092,357)	(3,001,623)	(32,979,343)	(17,467,056)	(7,139,131)	(5,583,888)	-	(91,262)	718,571	(1,884,669)	(1,433,806)	-	(974)	-	(39,279,930)	(20,445,056)	(11,665,822)
	Secured and unsecured obligations	-	-	-	-	-	-	(39,355,313)	(49,470,132)	(43,100,513)	(28,112,094)	(26,704,160)	(24,014,571)	-	(14,449,262)	(13,458,940)	-	-	-	(67,467,407)	(90,623,554)	(80,574,024)
	Other	-	-	-	(125,648,462)	(69,758,867)	(63,545,767)	(110,964,670)	(83,121,689)	(171,032,957)	(7,090,652)	(8,069,270)	(9,806,420)	(20,468,648)	(2,960,151)	827,586	-	(474,589)	(16,277)	(264,172,432)	(164,384,566)	(243,573,835)
	Gains (losses) from indexed assets and liabilities	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-	1,240	1,579	-	1,240	1,579
	Foreign currency exchange differences	-	-	-	(830,181)	1,755,304	(831,020)	4,254,011	(605,298)	529,863	(200,161)	567,871	46,049	241,382	(699,835)	(259,579)	-	(878,879)	(1,292,138)	3,465,051	139,163	(1,806,825)
	Positive	-	-	-	1,193,999	4,114,836	728,964	23,019,947	1,794,515	833,954	1,581,643	1,558,367	347,721	2,255,051	976,614	775,194	-	1,093,142	1,617,533	28,050,640	9,537,474	4,303,366
	Negative	-	-	-	(2,024,180)	(2,359,532)	(1,559,984)	(18,765,936)	(2,399,813)	(304,091)	(1,781,804)	(990,496)	(301,672)	(2,013,669)	(1,676,449)	(1,034,773)	-	(1,972,021)	(2,909,671)	(24,585,589)	(9,398,311)	(6,110,191)
	Share of profit (loss) of associates and joint ventures accounted for using the equity method	-	-	-	92	34,434	34,721	-	-	-	975,844	752,622	2,561,039	-	-	-	-	-	-	975,936	787,056	2,595,760
	Other gains (losses)	-	-	-	38,164	113,216	-	(832,957)	(6,758,695)	-	(10,191,353)	(128,486)	46,514	21,687	602,594	31,910	-	-	-	(10,964,459)	(6,171,371)	78,424
	Gain (loss) from other investments	-	-	-	38,164	-	-	-	-	-	(9,304,643)	-	-	-	-	-	-	-	-	(9,266,479)	-	-
	Gain (loss) from the sale of property, plant and equipment	-	-	-	-	113,216	-	(832,957)	(6,758,695)	-	(886,710)	(128,486)	46,514	21,687	602,594	31,910	-	-	-	(1,697,980)	(6,171,371)	78,424
Income before tax		-	-	-	(13,905,457)	99,980,517	(89,602,508)	32,596,418	71,986,345	126,347,329	202,024,075	208,751,938	237,958,538	94,690,976	91,535,128	79,523,876	-	(2,500,128)	(2,553,266)	315,406,012	469,753,800	351,673,969
	Income tax	-	-		(6,942,666)	(463,471)	3,792,056	1,770,210	(10,849,463)	(18,559,097)	(91,004,375)	(84,883,204)	(82,240,147)	(32,818,344)	(27,924,718)	(19,790,239)	-	(11,228,559)	(7,668,386)	(128,995,175)	(135,349,415)	(124,465,813)
Net Income from continuing operations		-	-	-	(20,848,123)	99,517,046	(85,810,452)	34,366,628	61,136,882	107,788,232	111,019,700	123,868,734	155,718,391	61,872,632	63,610,410	59,733,637	-	(13,728,687)	(10,221,652)	186,410,837	334,404,385	227,208,156
	Net income from discontinued operations	-	-	-	-	-	-	-	-	-	-	-	-	-	-		-	-	-	-	-	-
NET INCOME		-	-	-	(20,848,123)	99,517,046	(85,810,452)	34,366,628	61,136,882	107,788,232	111,019,700	123,868,734	155,718,391	61,872,632	63,610,410	59,733,637	-	(13,728,687)	(10,221,652)	186,410,837	334,404,385	227,208,156
Country		Chile			Argentina			Brazil			Colombia			Peru			Holdings, eliminations and others			Total
STATEMENT OF CASH FLOWS		12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014	12-31-2016	12-31-2015	12-31-2014
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
	Net cash flows from (used in) operating activities	3,986,376	192,068,742	36,094,225	178,874,717	243,657,253	188,056,795	387,272,425	165,632,490	243,585,176	239,215,846	235,309,844	218,066,750	118,825,427	109,115,394	83,447,069	-	(184,396)	91,870	928,174,791	945,599,327	769,341,885
	Net cash flows from (used in) investing activities	(2,040,606)	(64,199,658)	13,004,063	(83,298,107)	(208,791,432)	(180,592,386)	(248,268,384)	(269,722,111)	(239,357,913)	(140,528,848)	(112,561,292)	(16,909,564)	(67,247,743)	(114,212,151)	(57,451,165)	-	(17,922,661)	(32,662,053)	(541,383,688)	(787,409,305)	(513,969,018)
	Net cash flows from (used in) financing activities	(31,067,507)	(106,554,830)	(64,578,477)	(528,752)	(8,169,660)	(9,632,579)	(100,794,282)	78,329,447	623,587	(47,601,487)	(165,636,704)	(169,208,067)	(20,634,468)	(41,319,512)	(10,068,877)	-	18,107,057	32,570,183	(200,626,496)	(225,244,202)	(220,294,230)

The eliminations column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

The accompanying notes are an integral part of these consolidated financial statements.

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33. THIRD PARTY GUARANTEES, CONTINGENT ASSETS, LIABILITIES, AND OTHER COMMITMENTS

33.1 Direct guarantees

Creditor of Guarantee	Debtor		Type of Guarantee	Assets Committed			Outstanding balance as of			Guarantees released
				Type	Currency	Carrying
	Company	Relationship				Amount	Currency	12-31-2016	12-31-2015	2016	Assets	2017	Assets	2018	Assets
Mitsubishi Corporation	Enel Generación Costanera	Creditor	Pledge	Combined cycle plant	ThCh$	7,187,284	ThCh$	34,146,495	35,254,202	-	-	-	-	-	-
Credit Suisse  First Boston	Enel Generación Costanera	Creditor	Pledge	Combined cycle plant	ThCh$	-	ThCh$	-	1,183,600	-	-	-	-	-	-
Citibank N.A.	Endesa Argentina	Creditor	Pledge	Cash deposit	ThCh$	-	ThCh$	-	435,681	-	-	-	-	-	-
Deutsche Bank  / Santander Benelux	Enel Américas	Creditor	Deposit accounts	Cash deposit	ThCh$	-	ThCh$	-	40,354,434	-	-	-	-	-	-
Various Creditors	Ampla S.A.	Creditor	Pledge on collection and others	Collection accounts	ThCh$	10,786,070	ThCh$	136,397,365	98,375,210	-	-	-	-	-	-
Various Creditors	Coelce S.A.	Creditor	Pledge on collection and others	Collection accounts	ThCh$	11,858,985	ThCh$	84,150,023	60,265,158	-	-	-	-	-	-
Banco Nacional de Desarrollo Económico y Social	Enel Cien	Creditor	Mortgage, pledge and others	Collection accounts	ThCh$	170,519	ThCh$	3,837,875	3,944,953	-	-	-	-	-	-

As of December 31, 2016 and 2015, the carrying amount of property, plant and equipment pledged as security for liabilities is ThCh$7,187,284 and ThCh$13,903,028, respectively (see Note 16.e.ii).

As of December 31, 2016, the Company had future energy purchase commitments amounting to ThCh$36,101,879,822 (ThCh$35,079,484,027 as of December 31, 2015).

33.2 Indirect guarantees

Type	Contract	Maturity	Creditor of Guarantee	Debtor		Type of Guarantee	Oustanding balance as of
				Company	Relationship		Currency	12-31-2016	12-31-2015
Secured	Bonds Serie H	October 2028	Bondholders of Endesa Chile's Bonds	Enel Generación Chile S.A.	Entities demerged from original debtor Endesa Chile (codebtor Endesa Américas and after merger Enel Américas) (1)	Codebtor	ThCh$	63,846,305	67,256,260
Secured	Bonds Serie M	December 2029	Bondholders of Endesa Chile's Bonds	Enel Generación Chile S.A.	Entities demerged from original debtor Endesa Chile (codebtor Endesa Américas and after merger Enel Américas) (1)	Codebtor	ThCh$	260,593,910	253,262,154
						Total		324,440,215	320,518,414

(1) Upon the demerger of the original issuer, Endesa Chile (currently Enel Generación Chile S.A.), and in accordance with the bond indenture, all entities arising from the demerger are liable for the debt, regardless that the payment obligation remains in Enel Generación Chile S.A. After the Merger, the Company became liable of Endesa Américas.

The accompanying notes are an integral part of these consolidated financial statements.

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33.3 Lawsuits and Arbitrations Proceedings

As of the date of these consolidated financial statements, the most relevant litigation involving the Company and its subsidiaries are as follows:

a) Arbitration Proceedings

Law No. 25,561 on Public Emergency and Reform to the Currency System, enacted on January 6, 2002 by the Argentine authorities, voided certain provisions of the concession agreement of the Company’s subsidiary Edesur. Law No. 25,561 also required that utility concession agreements be renegotiated within a reasonable timeframe to adjust them to the new conditions. However, the failure to renegotiate Edesur’s concession agreement prompted the Company, Enel Distribución Chile S.A. (formerly named Chilectra S.A.), Enel Generación Chile S.A. (formerly named Endesa Chile S.A.) and Elesur S.A. (now part of Enel Distribución Chile S.A.) (collectively, the “Claimants”) to file an arbitration petition in 2003 under the Treaty for the Promotion and Protection of Chilean-Argentine Investments before the International Center for Settlement of Investment Disputes (“CIADI” in its Spanish acronym). The statement of claim principally requested that the CIADI declare the investment expropriated for an amount of US$1,306,875,960 (approximately ThCh$874,914,249), and sought compensation for the damages caused to the investment due to lack of fair and equitable treatment, in the amount of US$318,780,600 (approximately ThCh$213,414,048). The Claimants also seek, with respect to both claims, compounded annual interest of 6.9% per annum. The Claimants also claimed the sums resulting from the damages caused from July 1, 2004. Finally, the Claimants also demanded US$ 102,164,683 (approximately ThCh$68,396,190) for Elesur S.A. (now part of Enel Generación Chile S.A.) due to a lower price received on the sale of its shares. In 2005, the Argentine authorities and Edesur signed a Letter of Understanding, in which the terms and conditions are established for amendments and supplements to the concession agreement, forecasting tariff modifications, first during a transitional period and then under an Integral Tariff Review, in which the conditions for an ordinary tariff period of 5 years will be set. The arbitration has been suspended since March 2006 in accordance with the terms of the Letter of Understanding, and the appointment of one of the arbitrators, to replace an arbitrator who resigned in 2010 has been suspended. As of December 31, 2014, the parties informed CIADI of their agreement to extend the suspension of the arbitration procedure for 12 months starting on the same date, informing also that any of the parties can request the renewal of the arbitration procedure with 30 calendar days prior notice. As a result of the spin-offs of Endesa Chile S.A. and Chilectra S.A., the arbitration rights were transferred to the new companies created from the spin-offs, Endesa Américas S.A. and Chilectra Américas S.A., which were subsequently merged with and into Enel Américas S.A., with the latter assuming the arbitration rights as the surviving company and the rights of Endesa Américas S.A. and Chilectra Américas S.A.

b) Litigation proceedings of the Subsidiaries

1.-   In 2013, a class action lawsuit was filed by residents of the Colombian Municipality of Garzón against our subsidiary Emgesa, alleging that the construction of the El Quimbo hydroelectric project had caused the plaintiffs’ income from handicrafts or entrepreneurial activities to decrease by an average of 30%. The lawsuit claims the decrease was not considered when the project’s social-economic impact report was drafted. Emgesa denied these allegations on the basis that (i) the social-economic impact report complied with all methodological criteria, including giving all interested parties the opportunity to be registered in the report, (ii) the plaintiffs are not residents and therefore, compensation is allowed only for those whose revenues are, in their majority, coming from of their activity in the direct area of influence of the El Quimbo hydroelectric project and (iii) compensation must not go beyond the “first link” of the production chain and must be based on the status of the income indicators of each affected person. A proceeding was filed in parallel by 38 inhabitants of the Municipality of Garzón, who are claiming compensation for being affected by the El Quimbo hydroelectric project since they were not included in the social-economic impact report. A mandatory settlement hearing was unsuccessful. The court ordered a test, which is currently in the preliminary phase. In the parallel proceeding, an exception previous of pending lawsuit was filed, based on the existence of the principal proceeding. The proposed exception is pending ruling. The amount involved in this proceeding is estimated to be approximately CPs 33 billion (approximately ThCh$7,362,428). The amount involved in the parallel proceeding is estimated to be approximately CPs 1.7 billion (approximately ThCh$381,508).

2.-   Emgesa (formerly named Central Betania) was granted a tax benefit known as “Ley Páez” applicable to the income tax on corporations. The law states that those entities located in a geographical area affected by a natural catastrophe are exempted from taxation. The Colombian tax authority (DIAN) rejected the method used by Emgesa to determine the tax base applicable to the tax benefit. The DIAN believes that certain revenues of Emgesa, such as inflation adjustments and non-operating income do not qualify for the exemption since they are not related to the electricity generation activity. On the other hand, Emgesa believes that, in accordance with the law, this special benefit is applicable to it as an entity and not only to certain revenues of Emgesa. It is pending resolution before the Administrative Court. The proceedings have not been active since final arguments were filed in

The accompanying notes are an integral part of these consolidated financial statements.

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June 2010 due to the Huila Court not having a tax expert. In February 2016, a process was begun to activate the proceedings. The amount involved in this proceeding is estimated to be approximately CPs 96 billion (approximately ThCh$21,505,746).

3.-   The Corporación Autónoma Regional de Cundinamarca (CAR) through Resolution No. 506, enacted on March 28, 2005 and Resolution No. 1189, enacted on July 8, 2005, imposed on Emgesa, Empresa de Energía de Bogotá (EEB) and Empresa de Acueducto y Alcantarillado de Bogotá (EAAB) the execution of construction works on the El Muña dam reservoir, whose effectiveness, among others things, depends on maintaining Emgesa’s water concession. Emgesa filed an action for annulment and reestablishment of law against these resolutions before the Administrative Court of Law of Cundinamarca, Section One. The court of first instance denied the nullity of these resolutions. Appeals were filed by Emgesa, EEB and EAAB, and are pending resolution.

Emgesa filed another action for annulment and reestablishment against CAR for annulment of Article 2 of Resolution No. 1318 of 2007 and Article 2 of Resolution No. 2000 of 2009, both of which required Emgesa to implement a Contingency Plan and to carry out study on “Air Quality” for the potential suspension of water pumping in the dam reservoir. This action seeks to annul the administrative acts imposed due to impracticability of anticipating the “Air Quality” and implementing the Contingency Plan. In this action a favorable accountant expert report was presented, for which it was requested clarification to Emgesa. Clarification of previous expert report and a second expert report to value the projects anticipated by Emgesa is still pending. The amount involved in this proceeding is undetermined.

4.-   In February 2015, Emgesa was notified of a Popular Action filed by Comepez S.A. and other fish farming companies located near the Betania dam, on the grounds of protection of the right to a healthy environment, public health and food safety in order to prevent, in the opinion of the plaintiffs, the danger of a massive fish mortality among other damages from the filling of the reservoir for the El Quimbo hydroelectric project dam, also located at the basin of the Magdalena River. Regarding the status of the proceeding, the Huila administrative court issued in February 2015 a preliminary injunction that prevents the filling of the El Quimbo dam reservoir until the river has reached the optimal flow, among other requirements. Emgesa filed a motion for reversal against this decision requesting a probation order and the release of such measure, which motion was denied by the court. The appeal filed by Emgesa was granted only in the remand effect. The preliminary injunction was amended, allowing Emgesa to start filling the dam reservoir. Nevertheless, the Regional Environmental Authority (CAM) in Resolution No. 1503 issued on July 3, 2015 directed Emgesa to temporarily stop filling the El Quimbo dam reservoir. The Colombian government, through Decree No. 1979 requested the lifting of the generation suspension and reported that Emgesa must abide by such Decree. On December 15, 2015, the Constitutional Court decided that Decree No. 1979 was unenforceable, and as a result, Emgesa suspended at midnight of that date the generation of energy at El Quimbo. Emgesa presented the corresponding arguments.

On December 24, 2015, the Colombian Ministry of Energy and Mining and the National Authority of Aquaculture and Fishing (“AUNAP”) filed a writ of protection of constitutional rights to the Civil Courts of Circuito de Neiva as a transitional mechanism to avoid irreparable damage, while the Huila administrative court decides on releasing the precautionary measure, and requested that the generation of energy at El Quimbo be permitted. They have requested such generation to be authorized as an interim measure until a ruling on the writ of protection is made. On January 8, 2016, Emgesa was notified of the decision of the Civil Court of Circuito de Neiva which authorized Emgesa to immediately restore the generation of energy as a transitional measure until the Huila administrative court decides on releasing the precautionary measure. On December 19, 2016, the Court extended the generation for six more months, provided that the oxygenation system works properly. The amount involved in this proceeding is undetermined.

5.-   A class action was filed in Colombia against Codensa in which plaintiffs seek reimbursement for excess charges for not applying the tariff benefit that according to them would have applied to them as users of the Voltage One Level and owners of the infrastructure, as established by Resolution No. 082 of 2002, amended by Resolution No. 097 of 2008. Regarding the proceeding status, Codensa filed a plea against the lawsuit rejecting it entirely. A conciliation hearing was held between the parties, without success. The writ of proof is pending. The amount involved in this proceeding is estimated to be approximately CPs 337 billion (approximately ThCh$75,186,003).

6.-   In Colombia, upon incorporating our electrical distribution subsidiary, Codensa, in 1997, EEB contributed all public lighting infrastructures and other sale and distribution assets to Codensa in exchange for 51.5% of Codensa’s shares. However, there was no certainty regarding the inventory of lights in Bogotá and this generated subsequently differences regarding invoicing and settlement of the energy value that Codensa supplied to the municipality. In 2005, a geo-reference inventory of the lights was performed, which resulted in 8,661 fewer lights than those that Codensa considered in its billing and settlement to the Federal District of Bogotá (the District). In order to solve the conflict, the parties carried out round-table discussion to come to an agreement. However, in 2009 a private citizen filed a derivative action requesting that the court of law: (i) declare the rights of the administrative morality and public property violated; (ii) order Codensa to carry out the settlement that includes delinquent interest due to the higher values paid between 1998 and 2004; and (iii) recognize the incentive due to administrative morality for

The accompanying notes are an integral part of these consolidated financial statements.

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the claimant (15% of the amount the District recovered). The first instance judgment, which was subsequently confirmed by the second instance judgment, ordered the Administrative Special Public Utilities Unit (the UAESP) and Codensa to, within a time period of two months starting from the date of issuance of the judgment, carry out all necessary negotiations to establish in a definitive manner the balances either in favor or against Codensa, duly adjusted, plus additional interest. If no agreement is reached, the UAESP itself may make a unilateral judgment within two months and deliver it to Codensa for its consideration. Codensa may also exercise remedies through the relevant government channels and, in the event of non-payment, must proceed to execute the judgment. On September 6, 2013, the Comptroller sent a communication to Codensa announcing future control actions against it and the UAESP for an alleged detriment to the District of CPs 95.1 billion (approximately ThCh$ 21,226,723), due to payments owed to the District for public lighting between 1998 and 2004. On September 20, 2013, Codensa responded, disagreeing with the amount and proposing a technical group to resolve the issue. This resulted in several meetings being held. Based on Codensa’s documents and the declarations presented, the Comptroller issued a new report that supports the figure obtained by common accord by UAESP and Codensa of CPs 14.4 billion (approximately ThCh$ 3,220,003). The Comptroller recommended in its report that UAESP send the agreement for judicial review in order to resolve the lawsuit with Codensa, which occurred on December 13, 2013. Subsequently, the Comptroller, in Bogotá, issued a report questioning the agreement with the UAESP; such report was presented at Court. It is pending resolution from the Tenth Administrative Court of Bogotá, either for notifying the report or issuing final decision on the agreement subscribed between Codensa and the UAESP. The amount involved in this proceeding is estimated to be approximately CPs 72.9 billion (approximately ThCh$ 16,275,187).

7.-   To counter the impact in prices as a result of the climate phenomena “El Niño”, the Colombian Energy and Gas Regulatory Commission (“CREG”), through CREG Resolution No. 168 of 2008, established the Optional Tariff, which allows deferral of the increase in the electrical energy tariff for up to two years, mitigating the impact of the increase to end users. Codensa voluntarily discontinued the application of the Optional Tariff and determined the difference between the actual values of the tariff and the invoiced value from the Optional Tariff, based on the balances and the historical values transferred to the tariff for end users, in compliance with CREG Resolution No. 168 of 2008. The resulting difference in amounts from comparing tariffs must be returned to the end users due to the Optional Tariff values, as accumulated balances, are always higher than the values that would have been invoiced had Codensa not opted for that alternative. In terms of process status, a demand was issued on October 1, 2015 and was answered on November 23, 2015. Colombian regulations do not establish the mechanism for returning the difference in amounts from the Optional Tariff to end users; however, Codensa has previously decided to return it. There is a discrepancy between the amounts that Codensa expects to return and the amount that the CREG expects. The conciliation hearing was declared unsuccessful.  In the evidence period, the Chief Executive Officer of Codensa presented a report on the application of the regulatory mechanism as requested by the judge. On September 20, 2016, final arguments were presented. On November 29, 2016, a first instance ruling favorable to Codensa was issued. This resolution is subject to appeal. The amount involved in this proceeding is estimated to be approximately CPs 163 billion (ThCh$36,365,930).

8.-   In 2001, the fiscal authority in Peru, the Superintendencia Nacional de Administración Tributaria (SUNAT), questioned Enel Generación Perú (formerly named Edegel) for deducting as a tax expense the portion of the depreciation related to the revalued amount added to the assets during its voluntary appraisal carried out in the 1996 fiscal year. The amount rejected by SUNAT was related to financial interest paid during the construction phase of the power plants. SUNAT claimed (i) that Enel Generación Perú had not demonstrated that it was necessary to obtain financing to build the power plants and (ii) that such financing was actually incurred. Enel Generación Perú responded that SUNAT could not request such evidence because an appraisal values the assets at market value when the appraisal is performed, instead of the historical value of the assets. In this case, the appraisal methodology considered that the power plants of such scale were built with financing. In addition, Enel Generación Perú claimed that if SUNAT disagreed with the valuation, it should have conducted its own appraisal, which it failed to do. On February 2, 2012, the Tax Court (“TF” in its Spanish acronym) issued a ruling for the 1999 fiscal year in favor of two of Enel Generación Perú’s power plants, and against four power plants, based on the fact that a verified financing was only evidenced for the first two power plants. Consequently, TF ordered SUNAT to recalculate the taxes due by Enel Generación Perú, which amounted to ThCh$8,233,243 (€11 million) and were paid in June 2012. This amount will be reimbursed if Enel Generación Perú obtains favorable rulings in the following claims it has subsequently filed:

i) an administrative contentious claim before the judicial system against TF’s ruling, filed in May 2012 (which would result in a total reimbursement of the taxes paid); and

ii) a partial appeal against the recalculation that SUNAT performed according to TF’s ruling, on the basis that the recalculation was incorrect, filed in July 2012 (which would result in partial reimbursement of the taxes paid).

In August 2013, Enel Generación Perú received notice of an unfavorable ruling with respect to claim i). Enel Generación Perú filed an annulment appeal against the ruling, since the resolution violated its motivation right and was untimely. In May 2015, Enel Generación Perú received notice of the Court of Appeal’s resolution which: (i) annulled the resolution from the Justice Department (“JD”) that rejected the demand petitions of Enel Generación Perú; (ii) declared the claims previously rejected

The accompanying notes are an integral part of these consolidated financial statements.

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admitted; and (iii) ordered the JD to return to the stage of determination of the controversy points. In June 2015, Enel Generación Perú received notice from the JD that it had declared the claims previously rejected admitted and that it had submitted to the attorney general’s office a request for the issuance of a new pronouncement (in Peru, when the government is engaged as a party in a judicial process, an attorney general designated by the Public Ministry must be involved, in order for him to be informed and to state an opinion regarding the controversy, which opinion is not binding on the judge or the court that must resolve the litigation). In November 2015, Enel Generación Perú presented its verbal report.

For the 2000 to 2001 fiscal years, Enel Generación Perú paid ThCh$3,742,383 (€5 million) and made a provision of ThCh$748,477 (€1 million).

In November 2015, Enel Generación Perú was notified of Resolution No. 15281-8-2014, which declared that the TF had ruled with respect to the indicated appeal by annulling the resolution. SUNAT objected the loss deductions related to the financial derivative instruments. The TF ruling also revoked the objections related to the non-deductibility of depreciation of the non-accredited technical assistance services rendered to Generandes and the financial interests accrued on the loans for the acquisition of treasury shares. It is important to note that, although the TF’s resolution revoked the objections related to the excess in depreciation of the revalued assets, it also stated that SUNAT shall apply what is resolved by Enel Generación Perú’s appeal of income taxes filed for the fiscal year 1999 (Exp. No. 10099 of 2012), which is still pending resolution.

As of the reporting date of these consolidated financial statements, SUNAT had yet to recalculate the debt based on the established criteria.

In February 2016, Enel Generación Perú filed an appeal with the JD against the TF’s resolution (Resolution No. 15281-8-2014) in order to partially revoke the stated criterion, specifically the determination that SUNAT shall apply the decision related to the income tax for the fiscal year 1999 and avoid applying any other pronouncement.

During the same month, the JD accepted Enel Generación Perú’s appeal. In March 2016, the TF and SUNAT answered the appeal, meaning that the JD must resolve against Enel Generación Perú because the resolution did not “cause status” as the TF did not rule on the claimed concept. Also, in March 2016, Edegel was notified of the procedural corrective measures (Resolution on Procedural Correction). In June 2016, Enel Generación Perú was notified of the JD’s District Attorney Opinion and was requested to provide a verbal report, which was presented in September 2016.

For the 1999 fiscal year claim, it is anticipated that the judicial system will enact a new resolution regarding Enel Generación Perú’s lawsuit and that the TF will decide on the partial appeal filed by Enel Generación Perú. For the 2000 and 2001 fiscal years claim, SUNAT’s recalculation of the debt based on the established criteria is still pending. Both SUNAT and TF responded to the demand, which is pending before the Public Ministry.

The amount involved in these proceedings is estimated to be approximately S/.64.4 million (approximately ThCh$ 12,832,704).

9.-  SUNAT rejected the commercial energy losses that Enel Distribución Perú S.A. (formerly named Edelnor) recognized from 2006 to 2010, equivalent to approximately 2% of the total purchases and self-generated energy, and questioned the cost of sales of that energy since the losses were generated from an energy theft not confirmed in a court of justice. SUNAT believes that the infeasibility of a legal action can only be demonstrated through a police report and a resolution, duly noted, issued by the General Attorney (Public Ministry) acknowledging, on a final or temporary basis, the filing of a criminal action for energy theft. TF has issued certain prior rulings stating that such resolution is necessary. The position of Enel Distribución Perú is that the law does not establish a specific mechanism on how to demonstrate the infeasibility of a legal action; therefore, it is plausible to present any available evidence that is appropriate and reasonable for this situation (free review of the evidence). Enel Distribución Perú presented expert reports prepared by specialized engineers, reports issued by the Electricity General Directorate (“DGE”) of the Ministry of Energy and Mining and certain other reports of OSINERGMIN to demonstrate that it was pointless to prosecute these crimes through legal actions, as the reports demonstrated that it was of no use to file an action and proceed to trial for a crime where the perpetrators, the exact time of occurrence of the theft, the specific location of the occurrence and the quantity stolen could not be identified. TF has allowed this type of accreditation in case of theft for water distribution companies (an entity similar to an electric distributor), but it has not indicated that the resolution issued by the General Attorney is the only admissible evidence to demonstrate the infeasibility of prosecution through legal action. The development of the process is as follows:

For the year 2006: TF ruled against Enel Distribución Perú’s appeal although it agreed to the position about the substance of the controversial matter. Thus, TF concluded that Enel Distribución Perú was not able to demonstrate the quantity of commercial losses attributable to the theft. Such conclusion is based on the fact that the commercial energy loss does not consist exclusively

The accompanying notes are an integral part of these consolidated financial statements.

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of stolen energy, but also of energy losses due to other reasons, such as incorrect meter readings, incorrect invoicing and incorrect estimates of physical losses. Due to the immediate execution of TF’s ruling, Enel Distribución Perú paid the entire amount of the debt to SUNAT (ThCh$2,993,907). In 2013, Enel Distribución Perú filed an appeal to the JD against TF’s decision in order to revoke it and to request full deduction of the commercial energy loss, sustaining that: (i) in theory energy losses consist of the components previously indicated, and (ii) according to SUNAT’s own inspection performed in 2006, the total amount of the commercial loss was due to stolen energy. In June 2014, Enel Distribución Perú was notified of the findings of the District Attorney (Fiscal Resolution). In August 2014, Enel Distribución Perú presented a verbal report and final written arguments. In October 2014, Enel Distribución Perú was notified of the unfavorable resolution from the JD, and in November 2014, it filed an appeal. In June 2015, the court ruled to revoke the resolution and requested the issuance of a new resolution. In December 2015, Enel Distribución Perú was notified that the JD again ruled against it, and in the same month, it filed an appeal.

For the years 2007 and 2008: Considering the outcome obtained in 2016 for the income tax, Enel Distribución Perú initiated a new defense strategy: (i) in theory, commercial energy losses could consist of errors in meter readings, invoicing and estimates of physical losses; (ii) since such losses are determined by “subtraction” (the energy entered in the system “less” energy supplied to customers and “less” the physical loss of energy”), the commercial energy loss might, in fact, be composed of such errors only in cases of understated meter readings, understated invoicing or understated estimates of physical losses; (iii) if no such errors exist, the quantity of commercial energy loss would only be made up of theft losses; (iv) during its inspection, SUNAT reviewed the invoicing and the report of physical losses without questioning or inquiring on them; therefore, at this point, the errors in invoicing or the errors in physical losses estimates cannot be argued by SUNAT as components of the commercial energy loss, (v) regarding the errors in meter readings, and taking into account that the electric energy distribution is a regulated business, the occurrence of this type of error is remote. For the year 2007, Enel Distribución Perú presented evidence corroborating that a small portion of the loss was attributable to understated meter readings. Therefore, the commercial energy losses mainly consist of stolen energy (95%) and to a minor extent (5%) to an error in meter readings. Enel Distribución Perú presented a verbal report and filed its arguments. The appeal is still pending resolution by TF. For the year 2008, Enel Distribución Perú presented evidence demonstrating an excess in measurement. Thus, the commercial energy losses are only originated from theft. For these two years, Enel Distribución Perú presented a verbal report to TF and filed its final written arguments. The appeal is pending resolution by TF.

For the year 2009, SUNAT rejected the deduction of the commercial energy losses based on the same reasons as prior years. In November 2013, Enel Distribución Perú filed a claim reiterating the reasons for considering as deductible the commercial energy losses and presented evidence that demonstrated that the energy losses mainly originated from theft (93%) and to a minor extent (7%) to errors in meter readings. In June 2014, the SUNAT requested detailed information about the calculation to determine the “standard energy loss”. In July 2014, Enel Distribución Perú responded to the request of SUNAT. In August 2014, Enel Distribución Perú received notice from SUNAT and a resolution ruling on its claim. In the resolution, SUNAT revoked the objection related to the commercial energy loss on the matter related to the standard energy loss and confirmed the part related to the excess of such quantity. In September 2014, Enel Distribución Perú paid S/. 5.3 million (ThCh$1,050,157) related to the debt owed to SUNAT, and filed an appeal to with the TF, which is still pending resolution.

For the year 2010, SUNAT rejected the commercial energy loss deduction in the portion related to the excess over the standard energy loss. In July 2015, Enel Distribución Perú paid S/. 5.1 million (ThCh$1,012,299) related to the debt owed to SUNAT, and filed a claim. In April 2016, Enel Distribución Perú was notified of SUNAT’s resolution sustaining the objections, in the same month it filed an appeal.

For the year 2011, SUNAT again objected to the commercial energy loss deduction in the portion related to the excess over the standard energy loss. In July 2016, Enel Distribución Perú paid S/. 3.1 million (ThCh$622,462) related to the debt owed to SUNAT. In September 2016, Enel Distribución Perú was notified of a settlement for taxes and fines. In October 2016, Enel Distribución Perú filed a claim against taxes and fines.

The following steps are: For the year 2006, the court’s resolution on Enel Distribución Perú’s appeal is pending. For the years 2007, 2008, 2009 and 2010, TF’s resolution is pending. For the year 2011, Enel Distribución Perú is expecting resolution of the claim filed against taxes and fines.

The amount involved in these proceedings is estimated to be approximately S/. 77.7 million (approximately ThCh$15,483,885).

10.- In 1997, Enel Generación Perú, Perené and Simsa entered into a joint venture agreement for the development of Yanango and Chimay power plants, and agreed to make a payment of US$ 13 million (ThCh$8,703,110) to Enel Generación Perú. In 1998, Enel Generación Perú signed a contract with its parent company Generandes for supervision services for the construction

The accompanying notes are an integral part of these consolidated financial statements.

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of the power plants to be provided by the latter, agreeing to a payment of US$ 13 million to Generandes. In turn, Generandes signed contracts with its shareholders, Entergy Peru and Conosur, transferring to them its commitments with Edegel and agreeing to a payment of US$ 3 million (ThCh$2,008,410) for each party. SUNAT questioned this transaction: (i) in Enel Generación Perú for using as tax credit the VAT charged by Generandes; and (ii) in Generandes for treating expenses for the services provided by shareholders as tax deductible expenses and using as a tax credit the VAT charged by its shareholders. The position of SUNAT was that these transactions were not valid, because Generandes and its shareholders are a holding entity that does not have staff to provide such services. Supervision services were provided directly by Enel Generación Perú using its staff. The position of Enel Generación Perú was that TF already issued Resolution No. 15281-8-2014 with respect to Enel Generación Perú’s appeal related to its 2000-2001 income tax, the resolution stated that the technical assistance provided by Generandes qualified as non-existent. As a result of the direct implications of this statement is in this proceeding, the TF will issue a ruling against Generandes. In this regard, it is expected that TF will instruct SUNAT to recalculate the income tax of Enel Generación Perú, taking into consideration that Generandes’s costs and revenues (invoices issued to Enel Generación Perú) are invalid. According to this expected new determination, the recalculation would result in an additional income tax that would exceed the amount already paid, but such excess would be offset by the VAT, and consequently, it would eliminate the contingency for this proceeding. The appeal is pending resolution by the Tax Court. The resolution is expected the first half of 2017. The amount involved in this proceeding is estimated to be approximately S/. 85.8 million (approximately ThCh$ 17,099,380).

11.- On July 5, 2016, Electroperú filed an arbitration petition against Enel Generación Perú due to the existence of discrepancies related to the interpretation of certain technical aspects (capacity committed, initial date of the second stage of the contract, determination of the Base Gas Price) of an energy supply contract signed by the parties in 2003. Currently, an Arbitral Court has not yet been established. The amount involved in this proceeding is estimated to be approximately US$41.2 million (approximately ThCh$27,575,469). On the other hand, the discrepancies also contain claims from Enel Generación Perú against Electroperú for US$18.9 million (approximately ThCh$12,417,359).

12.-   In September 2012, the Company received notice from the Chilean Internal Revenue Service (“SII” in its Spanish acronym) regarding a settlement and resolution related to withholding taxes on dividends paid in fiscal years 2008 and 2009 (tax years 2009 and 2010) to non-Chilean resident or domiciled shareholders of the Company. Despite the fact that there is no difference in owed taxes, and no fines have been applied, the SII is requesting the Company correct the calculation methodology used for its tax return. In addition, SII notified the Company of settlements and resolutions on the same concept for fiscal years 2010 and 2011 (tax years 2011 and 2012). The position of SII is that the methodology used by the Company to determine the difference between the final tax credit and the provisional tax credit was incorrect, because the Company would have been paid the total amount of the tax credit used in the calculation of the provisional withholding and only the shareholders could have requested the refund from the amount paid in excess by the Company. The position of the Company is that the interpretation of SII is based on the wording of an article in the tax law that seems to require the “payment of credits in excess”, but it did not consider the existence of a resolution issued by SII indicating the description of this process with which the Company has complied. Moreover, if the methodology of SII is used, the amount to be paid on behalf of the shareholders would have been the same as the amount that the shareholders would have requested from SII as a refund. The only difference is that the amounts paid to SII are price-level restated by CPI and include an interest (1.5%), while the amounts that the SII would reimburse are only price-level restated by CPI. On March 13, 2014, the Company filed in the first instance a tax claim with the Tax and Customs Court (“TTA” in its Spanish acronym) for fiscal years 2008 and 2009. On August 18, 2014, a tax claim was filed for fiscal year 2010 (tax year 2011), and lastly, on August 29, 2014, a tax claim was filed for fiscal year 2011 (tax year 2012). The three tax claims are pending a response from SII, and on October 10, 2014, the Company requested their consolidation, which was granted by the court on October 16, 2014. On September 21, 2015, TTA opened the evidence period. On October 15, 2015, the Company presented its evidence. On December 31, 2015, TTA issued an unfavorable ruling against the Company. On January 4, 2016, the Company received notice of the resolution and filed an appeal with the Appeal Court of Santiago. On April 28, 2016, the Appeal Court issued an unfavorable ruling against the Company and it filed an appeal with the Supreme Court. On December 29, 2016, the Company paid ThCh$19,566,576 to SII, and received condonation for a total amount of ThCh$13,842,256, ending the discrepancy. On January 11, 2017, the Company requested that the Supreme Court close the proceeding, which is still pending resolution.

c) Litigation proceedings of Associates and Joint Ventures

1.-   The Brazilian IRS claims an alleged overstated payment of dividends by Enel Brasil. The Brazilian IRS claims that the total amortization of goodwill (greater value) recorded by Enel Brasil in 2009 in equity, should have been recorded against income. As a result, the accounting procedure performed was inadequate and resulted in a greater net income and consequently, a higher amount distributed as dividends. The alleged surplus in dividends was interpreted by the Brazilian IRS as payments to non-residents, which would be subject to a 15% withholding tax. Enel Brasil responded that all the accounting procedures adopted by Enel Brasil were based on Enel Brasil’s interpretation and in accordance with Brazilian accounting standards (Brazilian GAAP),

The accompanying notes are an integral part of these consolidated financial statements.

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and confirmed by the external auditor and by a legal opinion from Souza Leão Advogados. In December 2014, Enel Brasil filed its defense in the administrative court. In July 2016, the tax authorities issued an unfavorable ruling against Enel Brasil. Enel Brasil will file an appeal to the second instance Administrative Court, and will use an expert opinion on the accounting entries recorded in 2009. The amount involved in this proceeding is estimated to be approximately R$255.8 million (approximately ThCh$52,544,079).

2.-   In Brazil, Basilus S/A Serviços, Empreendimentos e Participações (hereinafter “Basilus”) is the holder of the litigation rights that it acquired from the construction companies Mistral and CIVEL, which had a civil works contract with Centrais Elétricas Fluminense S.A. (“CELF”). This contract was terminated before CELF’s privatization process. Since CELF’s assets were transferred to Ampla during the privatization process, Basilus sued Ampla in 1998, arguing that the transfer of the referred assets was done in detriment of its rights. Ampla only acquired assets from CELF, but is not its legal successor since CELF, a state-owned company, still exists and maintains its legal personality. Basilus demanded payment of pending invoices and contractual penalties for termination of the civil works contract. In March 2009, the court decided in favor of Basilus, and Ampla and the State of Río de Janeiro filed the corresponding appeals. On December 15, 2009, the State Court accepted the appeal and overturned the lower court’s decision obtained by Basilus, in Ampla’s favor. Basilus filed an appeal against the resolution, which was denied. In July 2010, Basilus filed an Appeal under Specific Court Regulations (Agravo Regimental) before the Superior Court of Justice of Brazil, which also rejected the appeal in August 2010. Seeking to overturn such decision, Basilus filed a Petition for Writ of Mandamus (Mandado de Seguranca), which was also rejected. In June 2011, Basilus filed an Appeal to Amendment of Judgement (Embargos de Declaração) in order to clarify a supposed omission by the Superior Court of Justice in the decision on the Petition for Writ of Mandamus, which was not accepted by the court. Against this decision, Basilus filed an Ordinary Appeal (Recurso Ordinario) before the Superior Court of Justice (in Brasilia). On March 28, 2012 the Reporting Justice decided the Ordinary Appeal in favor of Basilus. Ampla and the State of Río de Janeiro filed an Appeal under Specific Court Regulations against the Reporting Justice’s decision, which was accepted by the First Court Room of the Superior Court of Justice on August 28, 2012, determining that the Ordinary Appeal of the Petition for Writ of Mandamus must be submitted to the decision by an en banc session and not by a single Reporting Justice. Basilus challenged the decision. The decision of August 28, 2012, was published on December 10, 2012, and the Appeal to Amendment of Judgment had been filed by Ampla and the State of Río de Janeiro to remedy the existing error in its publication, in order to avoid future divergence. Basilus filed its arguments and on May 27, 2013, the Appeal to Amendment of Judgment filed by Ampla and the State of Río de Janeiro were accepted and the error corrected. On August 25, 2015, the appeal filed by Basilus was rejected. The decision was published on December 10, 2015, and Basilus filed an appeal to Amendment of Judgment. On March 3, 2016, the Superior Court of Justice began its judgement of the appeal and the first vote (Minister Rapporteur) was favorable to the appeal, resulting in the next Minister suspending its resolution to perform a detailed analysis of the arguments. The Superior Court issued an (three votes against two) unfavorable resolution to Ampla, which is subject to appeal. Consequently, the proceeding will return to the court of second instance (State Court of Río de Janeiro) and the appeal filed by Basilus in the original claim shall be ruled on. As previously discussed, Basilus’ claims have already been rejected in first and second instance. The amount involved in this proceeding is estimated to be approximately R$1.4 billion (approximately ThCh$286,554,770).

3.-  In December 2001, the Brazilian Federal Constitution was amended to apply the CONFINS tax (Contribuicao para o Financiamento da Seguridade Social), a tax levied on revenues, to electricity energy sales. The Constitution states that the changes on social contributions are effective 90 days after their publication. Ampla started to pay this COFINS tax in April 2002. However, the Brazilian Internal Revenue Service notified Ampla that the 90-day delay of entry into force is applied to statutory amendments, but are not applicable to constitutional amendments, which are effective immediately. In November 2007, the appeal filed before the Taxpayers Council (Consejo de Contribuyentes), the administrative appeals level, ruled against Ampla. In October 2008, Ampla filed a special appeal that was rejected. On December 30, 2013, Ampla was notified of the decision to reject its position that the COFINS tax payments were not due for the period from December 2001 to March 2002 based on the Constitution providing that legislative changes are effective 90 days after their publication. Ampla filed a judicial proceeding to obtain a certification of fiscal good standing in order to continue receiving public funds and was required to post a bond for the tax debt. Under the new standard on surety bonds published in March 2014, the bond amount must be 20% rather than the previous 30%, of the tax debt and the bond was reduced to € 44 million. Ampla submitted the new surety bond, complying with the new requirements. The Brazilian Treasury accepted the surety bond and granted the certification of fiscal good standing. The Brazilian Treasury submitted the fiscal execution and Ampla opposed its defense in July 2014. It is not necessary to submit a new surety bond since the bond posted to obtain the certification of fiscal good standing can be used for this proceeding. There is a first instance ruling unfavorable to Ampla, which was published in August 2015. In the same month, Ampla filed an appeal to the court of second instance. The amount involved in this case is estimated to be approximately R$156.7 million (approximately ThCh$ 32,192,734).

4.- Companhia Brasileira de Antibióticos (Cibran) filed suit against Ampla in order to receive compensation for the loss of products and raw materials, and machinery breakdown, among other things that occurred as a consequence of poor service

The accompanying notes are an integral part of these consolidated financial statements.

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provided by Ampla between 1987 and May 1994 and compensation for moral damages. This litigation is related to five other actions filed by Cibran against Ampla based on power outages allegedly caused by Ampla in the period from 1987 to 1994, 1994 to 1999 and part of 2002. The judge decided to conduct a single expert assessment of these various claims, which was in part adverse to Ampla. Ampla challenged such assessment and requested a new expert assessment. On September 5, 2013, the judge rejected the prior petition, whereupon Ampla filed a Petition for Clarification of the Decision (Embargo de Aclaración) and subsequently a Special Appeal (Agravo de Instrumento), both of which were rejected by the court. Against the latter, Ampla filed a Special Appeal before the Superior Court of Justice, which was unanimously accepted, therefore the claims from Cibran were rejected, since the judges understood that no causal relationship between the damages and Ampla’s actions had been proved. Such resolution is subject to an appeal from Cibran. In September 2014, a first instance judgment in one of these proceedings ordered Ampla to pay compensation of R$ 200,000 (approximately ThCh$ 41,083) for moral damages, in addition to the payment of material damages caused due to failures in supply of service, which have to be assessed by an expert in the sentence execution stage. Ampla filed a Clarification Attachment against this ruling that was rejected. In December 2014, Ampla filed an appeal. On September 21, 2016, the appeal was accepted, therefore the claims from Cibran were rejected since the judges understood that no causal relationship between the damages and Ampla’s actions had been proved. On October 4, 2016, Cibran filed Embargos de Aclaración which was rejected. On December 16, 2016, Cibran filed a Special Appeal before the Superior Court of Justice, which is pending acceptance. On June 1, 2015, a judgement in another of the proceedings ordered Ampla to pay moral damages of R$ 80,000 (approximately ThCh$16,433), in addition to material damages for Ampla’s failures in supply of service of R$ 95.5 million (approximately ThCh$ 19,610,022) (plus price-level restatement and interest). Ampla filed a Petition for Clarification of the Decision (Embargo de Aclaración) against this judgement, which was rejected by the court. Ampla has filed an appeal. In the remaining proceedings, a first instance court ruling is pending. The amount involved in this proceedings is estimated to be approximately R$394.5 million (approximately ThCh$ 81,036,456).

5.-  In August 1996, Ampla obtained a favorable ruling granting it an exemption from paying the COFINS tax for the period prior to the 2001 amendment of the Brazilian Federal Constitution which expressly made electric power operations subject to the COFINS tax. Following the definite decision in favor of Ampla issued in 2010, the Brazilian Treasury attempted to overturn the 1996 decision favorable to Ampla through a rescission action. Ampla refiled a suit originally filed in 1996 seeking a refund of its COFINS tax payments from April 1992 to June 1996, based on the favorable ruling in the first lawsuit described above. The suit seeking a refund of the COFINS tax had been suspended pending the resolution of the first lawsuit above. In June 2013, Ampla received a favorable decision entitling it to a refund of its COFINS tax payments for the periods requested. The Brazilian Treasury appealed the decision. In October 2014, the Court of the State of Río de Janeiro ordered a new trial since it considered that the Brazilian Treasury did not have the opportunity to appear in the prior decision judgment. In May 2015, the Brazilian Treasury presented its final plea and in July 2015 a new favorable first instance ruling entitling Ampla to a refund of its COFINS tax payments made from 1992 to 1996 was issued. In August 2015, the tax authorities filed an appeal with the Court of the State of Río de Janeiro. In July 2016, a favorable second instance ruling was issued, confirming Ampla’s entitlement to a refund of its COFINS tax payments made from 1992 to 1996. The tax authorities filed an appeal at the same court to clarify the criteria used by the Court to determine the loss of the appeal. Subsequent to resolution of the appeal, the tax authorities can still file an appeal before both Supreme Courts (Superior Court of Justice and Supreme Federal Court) to discuss the right to the refund. The reimbursement requested by Ampla is R$172.2 million (approximately ThCh$35,372,567).

6.- The Trade Union of Niterói, representing 2,841 employees, filed a labor claim against Ampla, requesting the payment of salary differences of 26.05% retroactive to February 1989, pursuant to the Economic Plan instituted by Law Decree No. 2,335/87. In the court of first instance, the decision was partially unfavorable for Ampla. The court ordered payment of the salary differences requested retroactive to February 1, 1989, and legal fees of 15% of such amount. Ampla filed several appeals, among them an Extraordinary Appeal which is currently pending. A mandatory mediation was unsuccessful. In parallel, Ampla has filed a motion for Advanced Dismissal of Enforcement (Exceção de Pré-Executividade) based on the jurisprudence of the Federal Supreme Court, which has previously declared the non-existence of a right acquired on the Unidade de Referência de Preços (URP) readjustment of Law Decree No. 2,335/87. In addition, Ampla alleged the exception of the payment for these readjustments and, alternatively, requested the limitation of this readjustment using October 1989 salaries as a baseline. In the court of first instance, Ampla obtained the declaration of unenforceability of legal title, against which the applicant filed an appeal (Agravo de Petição). The decision was partly favorable regarding the exception of payment, but not regarding the limitation of the salary differences, using October 1989 salaries as a baseline. On September 10, 2014, the court rejected the Special Appeals (Agravo de Instrumento) presented by both parties, who filed a Petition for Clarification of the Decision (Embargos de Aclaración) against this judgment. In June 2015, Ampla presented its arguments to the Court regarding the Extraordinary Appeal filed by the Union, which were rejected by the Court. On December 16, 2015, the Extraordinary Appeal was submitted to the Federal Superior Court of Law for its judgment. On August 29, 2016, a resolution was issued to suspend execution of the sentence. In December 2016, the resolution of the Extraordinary Appeal was unfavorable to Ampla, who will

The accompanying notes are an integral part of these consolidated financial statements.

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file an appeal. The amount involved in this proceeding is estimated to be approximately R$77.2 million (approximately ThCh$15,852,949).

7.-  In order to fund the purchase of Coelce in 1998, Ampla issued long-term debt abroad through securities called Fixed Rate Notes (FRNs) which were governed by a special tax regime whereby interest payments received by non-resident holders were exempt from taxation in Brazil, as long as the debt was issued with a minimum maturity of 8 years. In 2005, the Brazilian Internal Revenue Service (responsible for tax collection and compliance with tax laws) IRS notified Ampla the special tax regime did not apply based on its understanding that prepayments were made before the stated maturity, due to the fact that Ampla had received financing in Brazil which was allocated to repay the FRN holders. Ampla argues that these two transactions are independent and legally valid. The non-application of the special tax regime means that Ampla would have failed to comply with its obligation to retain the tax and to record it as interest payments made to non-resident holders. The tax resolution was appealed and in 2007 the Taxpayers Council (Consejo de Contribuyentes), the administrative appeals level, annulled it. However, the Brazilian IRS contested this decision before the Superior Chamber of Fiscal Resources (Cámara Superior de Recursos Fiscales), the final administrative appeals level, and on November 6, 2012, it ruled against Ampla. The decision was notified to Ampla on December 21, 2012. On December 28, 2012, Ampla filed a Petition for Clarification of the Decision (Embargo de Aclaración) before the Superior Chamber of Fiscal Resources in order to obtain a final resolution regarding contradictory points of the decision and to incorporate in it the relevant defense arguments that were omitted. The petition was denied. As a consequence, Ampla filed a judicial proceeding to obtain a certification of fiscal good standing in order to continue receiving public funds. Ampla was required to post a bond for the tax debt. Under the new standard on surety bonds published in March 2014, the bond amount must be 20%, rather than the previous 30%, of the tax debt. Ampla submitted the new surety bond, complying with the new requirements. The Brazilian Treasury accepted the surety bond and granted the certification of fiscal good standing. The Brazilian Treasury submitted the fiscal execution and Ampla opposed its defense on June 27, 2014. It is not necessary to submit a new surety bond since the bond posted to obtain the certification of fiscal good standing can be used for this proceeding. A legal investigation will be carried out by an expert designated by the judge. A first instance resolution is expected upon investigation by the expert to be designated by the judge. The amount involved in this case is estimated to be approximately R$ 1.2 billion (approximately ThCh$ 244,859,099).

8.-The State of Rio de Janeiro filed complaints against Ampla for the periods 1996 to 1999 and 2007 to 2014, as a result of considering the Imposto sobre Circulação de Mercadorias e Prestações de Serviços (ICMS) calculation for the acquisition of fixed assets to be incorrect. Specifically, the State of Rio de Janeiro believes that Ampla does not have all necessary supporting documentation and that the fixes assets were not used for electric energy generation and distribution activities. In its defense, Ampla states that (i) the corresponding legislation does not specify the different types of fixed assets that could be used for ICMS credit purposes; and (ii) such fixed assets are related to the main activity of the companies, even if they are used at the offices and administrative premises. It also intends to compare the credits with the purchase invoices. Ampla filed its administrative and judicial defense in all the processes. Certain administrative process rulings were favorable to Ampla and appeals were filed for the others, which are pending resolution. The favorable ruling confirmed the right of Ampla to use the ICMS credit for the assets acquired for the period from 2007 to 2012. The amount involved in this proceeding is estimated to be R$ 113 million (approximately ThCh$ 23,207,444).

9.-   In October 2009, Tractebel Energía S.A. sued Enel CIEN S.A. (formerly named CIEN S.A.) claiming an alleged breach of the contract “Purchase & Sale Agreement for 300 MW of Firm Capacity and associated Energy originating from Argentina” signed in 1999 between Enel CIEN and Tractebel Energía (formerly named Centrais Geradoras do Sul do Brasil S.A). Tractebel Energía requested the court to order Enel CIEN to pay a rescission penalty of R$ 117.7 million (approximately ThCh$ 24,170,633) plus other fines due to unavailability of energy. The breach allegedly occurred due to a failure by Enel CIEN to ensure sufficient capacity as contracted with Tractebel Energía under the 20-year term contract, such insufficiency allegedly took place as of March 2005. In May 2010, Tractebel Energía notified Enel CIEN via a written statement, but not judicially, its intention to exercise step-in rights of Line I (30%). The proceeding is currently at the first instance. Enel CIEN petitioned to join this proceeding with the lawsuit filed by it against Tractebel Energía in 2001, which involves a dispute relative to exchange rates and tax issues. The petition to join both proceedings was rejected by the court. Subsequently, Enel CIEN filed a request to suspend the proceeding for 180 days in order to avoid potentially divergent decisions. The court ordered the suspension of proceedings for one year pending the outcome of the other lawsuit of Enel CIEN against Tractebel Energía. The court issued a resolution extending this suspension until July 9, 2015. As of the reporting date of these consolidated financial statements, the proceeding has not had any developments.

10.-   In 2010, Furnas Centrais Eletricas S.A. filed a suit against Enel CIEN, based on Enel CIEN’s alleged breach of the contract “Firm Capacity Purchase with associated Energy” for the purchase of 700 MW of firm capacity with related energy originating from Argentina, which was signed in 1998 for a 20-year term effective in June 2000. In its claim, Furnas requested a compensation of R$520.8 million (approximately ThCh$ 106,980,583) corresponding to a rescission penalty included in the

The accompanying notes are an integral part of these consolidated financial statements.

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contract, plus adjustments and default interests, from the date of filing of the claim until actual payment. Furnas also requested for additional penalties based on the lack of availability of the “firm power and related energy” and for other damages to be determined upon the final decision. The first trial judgment denied the claims of Furnas for Enel CIEN’s responsibility for breach of its contractual obligations. The Court recognized the existence of force majeure because of the energy crisis in Argentina. The claimant filed an appeal against this sentence. In July 2015, Enel CIEN presented its arguments to the Court regarding the appeal filed by Furnas. Moreover, regarding the foreign language documents presented by Enel CIEN, the judge of first instance determined that those documents would be excluded from the lawsuit, which decision was confirmed by the 12th Civil Section of the State Court. Enel CIEN has filed a Special Appeal (Recurso Especial) against this decision, which will be decided by the Superior Court of Justice. In addition to the foregoing, Enel CIEN received a notice from Furnas, not at the judicial headquarters, indicating that in case of rescission due to Enel CIEN’s breach, Furnas would have the right to acquire 70% of Line I.

The accompanying notes are an integral part of these consolidated financial statements.

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11.-   In 1982 under the framework of an electricity supply network expansion in Brazilian rural areas, which was financed principally by international development banks (IDBs), the then-state-owned Companhia Energética do Ceará S.A. (Coelce) signed contracts with 13 cooperatives at the request of the Brazilian government and the IDBs to implement this project. Under the contracts, Coelce operated and maintained the assets and paid a monthly fee, which was price-level restated for inflation. These contracts were of indefinite length and failed to clearly identify the networks that were under their scope due the public nature of Coelce and the fact that they were often repaired, creating confusion between the assets that were operated and maintained by Coelce, and the assets that were owned by it. From 1982 until June 1995 Coelce regularly paid rent for the use of the electric system to cooperatives, adjusted monthly by the relevant rate of inflation. However, from June 1995, Coelce, while it was still state-owned, decided not to continue adjusting the payments for inflation. In 1998 Coelce was privatized and acquired by the Group, and continued to pay rent to the network cooperatives in the same manner as before its privatization, that is, without adjusting the rent for inflation. As a consequence, some of these cooperatives have brought legal action against Coelce, including the two actions initiated by Cooperativa de Eletrificacao Rural do V do Acarau Ltda (Coperva) and other action initiated by Cooperativa de Energia Telefonia e Desenvolvimento Rural do Sertão Central Ltda (Coerce) and Cooperativa de Energia Telefonia e Desenvolvimento (Coperca). Coelce’s defense is basically grounded on the argument that the adjustment is not applicable, since the assets lacked value due to their much extended useful lives, taking into consideration their depreciation; or, alternatively, if the assets were deemed to have any value, it would be very low since Coelce performed their replacement, extension and maintenance. The amount involved in this litigation is approximately R$ 187.8 million (approximately ThCh$ 38,577,049).

In one of the actions initiated by Coperva, an expert evaluation of the issue was requested, which Coelce claimed there were technical inconsistencies therein and requested a new evaluation to be conducted, but the court denied the claim and ruled the “anticipated execution of the decision”, which entails the preliminary determination of the adjusted monthly payments Coelce should have made and ordering the immediate payment of the difference between such adjusted values and the values Coelce actually paid. An appeal has been filed and a precautionary measure has been obtained in favor of Coelce, staying the anticipated execution of the decision. On April 7, 2014 a court of first instance denied Coperva’s claims. Coperva filed an appeal which was rejected. Coperva filed a Petition for Clarification of the Decision (Embargos de Aclaración) which was rejected on January 11, 2016. On February 3, 2016, Coperva filed a Special Appeal to the Superior Court of Justice.

On the other hand, in relation to the claim filed by Coperca related to a review action in 2007, through which Coperca is attempting to readjust the lease value of its distribution lines (in the central region of the State of Ceará), to be calculated at 1% of the value of the asset leased, estimated by Coperva to be at R$ 15.6 million (approximately ThCh$ 3,204,483). This proceeding is in a first instance and has not yet started the evidence presenting stage. The amount involved in this proceeding is estimated to be approximately R$101.7 million (approximately ThCh$ 20,890,766). In Coerce’s case, the review action was filed in 2006 and Coerce is attempting to readjust the lease value of its distribution lines (in the central region of the State of Ceará), to be calculated at 2% of the value of the asset leased. The amount involved in this proceeding is approximately R$ 117 million (approximately ThCh$ 24,033,626). This proceeding, as well as the one for Coperca, has not been advanced by the plaintiff and both are in their first instance.

12.-   In February 2004, two Brazilian taxes, Contribuição para o Financiamento da Seguridade Social (“COFINS”) and Programas de Integração Social (“PIS”) were amended from an accrued regime (rate of 3.65% without credit deduction) to a non-accrued regime (9.25% with credit). According to legislation, long-term assets and service supply agreements performed before October 31, 2003, under “predetermined price” could remain in the accrued regime. Endesa Fortaleza had entered into energy purchase agreements that complied with the requirements, and as a result, the revenues for such agreements were initially taxed under the accrued regime, which is more advantageous. In November 2004, an administrative order was released which defines the concept of “predetermined price”. According to it, CGTF (Endesa Fortaleza) agreements must be subject to the non-accrued regime. In November 2005, a new Law clarified the “predetermined price” concept. On the basis of the 2005 legislation, the regime that should be applied to the agreements was the accrued regimen (more advantageous). The ANEEL issued a (Administrative Law) Technical Note indicating that the agreements entered into by virtue of its standards and with its approval comply with the legislative requirement. PIS and COFINS tax paid in excess under the non-accrued regime by Endesa Fortaleza and Enel CIEN between November 2004 and November 2005 generate tax credits which were used to pay other taxes due. Nevertheless, in 2009 the tax authorities rejected the compensation procedures. In February 2007, the Brazilian tax authorities audited Endesa Fortaleza regarding the payment of PIS/COFINS tax during December 2003 and from February 2004 to November 2004. The audit resulted in a claim alleging differences between the amounts stated in Endesa Fortaleza’s annual tax return (where the PIS/COFINS tax amounts were reported under the new non-accrued regime) and the amounts stated in monthly tax returns (where the amounts due were reported under an older accrual system). Endesa Fortaleza filed an appeal to the second instance administrative court which was unfavorable and confirmed the first instance resolution. Endesa Fortaleza filed an appeal with the Superior Chamber of Fiscal Resources, which is pending resolution. In relation to the other proceedings against CGTF, these were favorably ruled on and the tax

The accompanying notes are an integral part of these consolidated financial statements.

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authorities filed appeals before the Superior Chamber of Fiscal Resources. The amount involved in this proceeding is estimated to be approximately R$ 150 million (approximately ThCh$ 31,015,497).

The accompanying notes are an integral part of these consolidated financial statements.

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13.- Coelce bills “low income” consumers with a social discount that determines a final rate called “baja renta” (low income). The State of Ceará compensates Coelce for this discount as a state subsidy. The ICMS (a tax similar to the Chilean Value Added Tax) is transferred (deducted) by Coelce over the amount of the normal rate (without the discount). On the other hand, the State of Ceará establishes that the ICMS does not apply to billings that fluctuate between 0 and 140 kW/h. Also, Coelce, in order to calculate the ICMS deductible amount in reference to the total ICMS supported in energy purchases must apply the “pro rata” rule, which uses the percentage that represents revenues subject to ICMS over the total income (whether or not subject to ICMS). Coelce considers, for the purpose of its inclusion in the pro rata denominator, that the revenue not subject to ICM is the result of applying the end sales price of energy (price after the subsidy is discounted) and the Brazilian IRS holds that the income not subject to ICMS is the price of the normal rate (without discounting the subsidy). The Brazilian IRS’s position implies a lower ICMS deduction percentage. The Brazilian Treasury’s view is that the “ICMS pro rata” calculation should be based on the normal rate value in “low income” energy sales cases, instead of the reduced rate that Coelce uses. The Brazilian Treasury’s criteria results in a greater ICMS non-recoverable percentage, which results in a higher ICMS payable. Coelce argues that its calculation is correct, since it must be used in the “ICMS pro rata” calculation, reducing the value of the ICMS rate since that is the accurate value of the energy sales transaction (the ICMS’s base is the transaction value of the merchandise sold). In reference to the claims for the years 2005 and 2006, the rulings were unfavorable to Coelce. In reference to the claims for the years 2007, 2008 and 2009, the rulings were unfavorable to Coelce but some of them resulted in a reduction of the amounts due to expiration. Coelce filed legal claims in order to ensure its certification of a regular tax status, which will allow it to continue receiving public funding, having previously guaranteed its tax debt. The State of Ceará filed Fiscal Executions (legal collection procedures) for the years 2005, 2006, 2007, 2008 and 2009, and Coelce will file its first instance administrative defense. In reference to the claims for the years 2010 and 2011, the complaints were received in January 2015 and January 2016, respectively, and Coelce filed its first instance administrative defense. The first instance administrative rulings were unfavorable to Coelce. On July 27, 2016, Coelce filed appeals before the administrative second instance for the year 2010, and on August 15, 2016, for the year 2011. The second instance administrative rulings issued on December 7 and December 8, 2016, respectively, for the years 2010 and 2011, were unfavorable to Coelce. Consequently, the fiscal executions for the years 2005 to 2011 were also unfavorable to Coelce, which has given bank guarantees to obtain the Certificado de Regularidad Tributaria (Certificate of Regular Tax Status). The State of Ceará presented its corresponding collection procedure. Coelce will file its first instance administrative defense. The amount of these litigations is estimated to be approximately R$ 114.3 (approximately ThCh$ 23,742,430).

14.- The State of Ceará filed complaints against Coelce for the periods 2003, and 2004 to 2010, since it considered that the ICMS calculation for the acquisition of fixed assets was incorrect. Specifically, the State of Ceará states that Coelce does not have all the necessary supporting documents and that certain fixed assets were not used for the activity of electric energy production or distribution. In its defense, Coelce explained that (i) the relevant legislation does not specify the different types of fixed assets that could be used for the ICMS credit purposes; and (ii) such fixed assets are related to the main activity of the companies, even if they are used at the offices and administrative premises. It also intends to compare the credits with the purchase invoices. Coelce filed its administrative defense in all administrative processes and is awaiting final resolutions. The amount of this proceeding is estimated to be approximately R$ 130.5 million (approximately ThCh$ 26,816,391).

15.- In July 2016, three public civil actions were initiated against Coelce and ANEEL, questioning the percentage of tariff adjustment of Coelce, and in particular, the difference between the rate of adjustment and the inflation rate. The plaintiffs in each action are (i) Procon de Fortaleza, (ii) the Instituto Brasileiro de Defesa do Consumidor (Institute for Consumer Protection) and, (iii) jointly, the Defensoría Pública, the Comité de Protección de los Consumidores-Asamblea Legislativa de Ceará, and the Comité de Defensa y Protección de los Consumidores. The actions initiated by (i) and (ii) are in the initial stages of discussion, and the preliminary (precautionary) measures requested by the plaintiffs were rejected. In the case of action (ii), after Coelce’s request, the decision was transferred from the State Court to Federal Court, as well as for the inclusion of ANEEL in the lawsuit. The precautionary measure requested by the plaintiff was rejected. In relation to action (iii), the precautionary measures requested were also rejected, and in addition a resolution was issued on September 6, 2016, rejecting the claim of these institutions. On October 27, 2016, the institutions filed an appeal which was responded to by Coelce on November 25, 2016. The court has not issued a resolution on the matter. The amount involved in these proceedings is undetermined.

The accompanying notes are an integral part of these consolidated financial statements.

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16.- In 2016, the Instituto Brasileiro de Defesa do Consumidor(“IDEC”) filed a public civil action against Coelce, alleging improper incorporation of energy theft losses as a component of tariff charged by energy distributors. In summary, the IDEC claims that consumers should not pay for energy theft losses and it is responsibility of the distribution companies to take the necessary actions to reduce it, as it is a risk of the business. Coelce’s defense is based on the argument that the adjustment in the tariff related to energy theft losses is as defined in the regulations. It also argues that ANEEL, through its tariff rules, does not make sufficient investments to reduce energy theft and does not have the structure to take the necessary actions to fight such crime. An unfavorable decision for Coelce would lead to the reimbursement of the amounts improperly charged to consumers, possibly implemented through tariff reviews.  The claim is at the preliminary stage and a conciliation hearing was scheduled for March 3, 2017. In addition, Coelce has requested to include ANEEL in the claim, which might result in transferring the decision from State Court to Federal Court. The amount involved in this proceeding is estimated to be approximately R$ 501.6 million (approximately ThCh$103,036,468).

The management of the Company considers that the provisions recorded in the Consolidated Financial Statements are adequate to cover the risks resulting from litigation described in this Note. It does not consider there to be any additional liabilities other than those specified.

Given the characteristics of the risks covered by these provisions, it is not possible to determine a reasonable schedule of payment dates if there are any.

33.4 Financial restrictions

A number of the Company’s loan agreements, and those of some of its subsidiaries, include the obligation to comply with certain financial ratios, which is normal in contracts of this nature. There are also affirmative and negative covenants requiring the monitoring of these commitments. In addition, there are restrictions in the events-of-default clauses of the agreements which require compliance to avoid acceleration of such debt.

1. Cross Default

Some of the financial debt contracts of the Company contain cross default clauses. The credit line agreements governed by Chilean law, which the Company signed in March 2016 for U.F. 2.8 million, stipulate that cross default is triggered only in the event of non-compliance by the borrower itself, with no reference made to its subsidiaries, i.e. the Company, respectively. In order for debt acceleration to occur in these credit lines due to cross default originating from other debt, the amount overdue of a debt must exceed US$50 million, or its equivalent in other currencies, and other additional conditions must be met such as the expiry of grace periods. These credit lines have not been disbursed.

For a substantial number of the bonds issued by the Company that are registered with the United States Securities and Exchange Commission (the “SEC”), commonly called “Yankee bonds”, a cross default might be triggered by another debt of the Company or of any significant subsidiary, for any amount overdue provided that the principal of the debt giving rise to the cross default exceeds US$150 million, or its equivalent in other currencies. Debt acceleration due to cross default does not occur automatically but has to be demanded by the holders of at least 25% of the bonds of a certain series of Yankee bonds. In addition, events of bankruptcy or insolvency of foreign subsidiaries have no contractual effects on the Yankee bonds of the Company. The Yankee bonds of the Company mature in 2026. As of December 31, 2016, the outstanding amount for the Yankee Bonds was ThCh$391,909,680.

The Company’s bonds issued in Chile state that cross default can be triggered only by the default of the issuer, either on a stand-alone or on an aggregate debt basis, when the amount in default exceeds 3% of total consolidated assets. Debt acceleration requires the agreement of at least 50% of the bondholders of a certain series. As of December 31, 2016, the outstanding amount for the domestic bonds was ThCh$22,393,639.

2. Financial covenants

Financial covenants are contractual commitments with respect to minimum or maximum financial ratios that the Company is obliged to meet at certain periods of time (quarterly, annually, etc.). Most of the financial covenants of the Company limit the level of indebtedness and evaluate the ability to generate cash flows in order to service the companies’ debts. Certain companies are also required to periodically certify these covenants. The types of covenants and their respective limits vary according to the type of debt.

The accompanying notes are an integral part of these consolidated financial statements.

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The Series B2 domestic bonds of the Company include the following financial covenants, whose definitions and calculation formulas are set out in the respective contract:

- Consolidated Equity: Minimum Equity of Ch$645,604 million must be maintained, a limit adjusted at the end of each year as established in the indenture. Equity is the sum of Equity attributable to the shareholders of Enel Américas and non-controlling interests. As of December 31, 2016, the Company’s equity was Ch$5,275,249 million.

- Debt to Equity Ratio: A debt to equity ratio, defined as Total liabilities to Equity, shall not be more than 2.24. Total liabilities are the sum of Total current liabilities and Total non-current liabilities, while Equity is the sum of Equity attributable to the shareholders of Enel Américas and non-controlling interests. As of December 31, 2016, the Debt Ratio was 1.14.

- Unsecured Assets: The ratio of Unsecured assets to Unsecured total liabilities must be at least 1. Total Unsecured or free assets is the difference between Total assets and Total secured assets. Total unsecured or free assets consists of Total Assets less the sum of Cash, Bank balances, Current accounts receivable from related parties, Current payments in advance, Non-current accounts receivable from related entities, and Gross identifiable intangible assets, while Total secured assets relates to assets pledged as security. On the other hand, Total unsecured liabilities consist of the sum of Total current liabilities and Total non-current liabilities, less liabilities secured by collateral. As of December 31, 2016, this ratio was 1.46.

The undisbursed credit lines in Chile include the following covenants, whose definitions and calculation formulas are set out in the respective contract:

- Debt to Equity Ratio: A debt to equity ratio shall not be more than 1.3. Debt is defined as the sum of current and non-current interest-bearing borrowings, while Equity is the sum of Equity attributable to the shareholders of Enel Américas and non-controlling interests. As of December 31, 2016, the debt to equity ratio was 0.55.

- Debt repayment capacity (Debt/EBITDA ratio): A debt to EBITDA ratio shall not be more than 3.5. Debt is defined as the sum of current and non-current interest bearing borrowings, while EBITDA is defined as operating income less depreciation and amortization expenses and impairment losses (or reversals) for the four moving quarters ended at the time of calculation. As of December 31, 2016, the Debt/EBITDA ratio was 1.75.

On the other hand, the Yankee bonds or any other debt of the Company on a stand-alone basis are not subject to financial covenants.

As of December 31, 2016, the most restrictive financial covenant for the Company was the Unsecured Assets ratio with respect to Series B2 domestic bonds.

In Peru, the debt of Enel Generación Perú only has a single covenant:

- Second, Third and Fourth local bond issues, whose outstanding amount as of December 31, 2016 was ThCh$255,726,728 and final maturity in January 2033, are subject to Debt to Equity Ratio which is calculated by dividing Total liabilities less deferred liabilities by Equity.

On the other hand, the debt of Enel Distribución Perú includes the following covenants:

- Local bonds whose outstanding amount as of December 31, 2016 was ThCh$36,304,516 and final maturity in January 2028, are subject to Debt to Equity Ratio which is calculated by dividing Debt less cash by Equity.

- Finance lease agreement with Banco Scotiabank whose outstanding amount as of December 31, 2016 was ThCh$14,744,589 and final maturity in March 2017, is subject to the Debt ratio calculated by dividing Debt by Equity and the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA.

- Bank borrowings of Chinango, a Enel Generación Perú’s subsidiary, with Bank of Nova Scotia, whose outstanding amount as of December 31, 2016 was ThCh$4,234,540 and final maturity in January 2019, is subject to the covenants, calculated on an stand-alone basis, Debt to Equity Ratio calculated by dividing Net debt less Cash by Net Equity and Debt Repayment Capacity calculated by dividing Debt by EBITDA.

- As of December 31, 2016, the most restrictive financial covenant for Enel Generación Perú was the Debt ratio corresponding to the financial lease agreement with Banco Scotiabank.

The accompanying notes are an integral part of these consolidated financial statements.

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Finally, in Peru, the debt of Enel Generación Piura includes the following covenants:

- Finance lease arrangement with Banco de Crédito del Perú whose outstanding amount as of December 31, 2016 was ThCh$40,714,168 and final maturity in June 2020, is subject to the covenants, Debt Repayment Capacity Ratio calculated by dividing Cash Flows for Debt Service by Debt Service, and Debt to Equity Ratio calculated by dividing Total liabilities less Deferred Liabilities by Equity.

- Finance lease arrangement with Banco Scotiabank whose outstanding amount as of December 31, 2016 was ThCh$23,278,628 and final maturity in March 2022, is subject to the same financial covenants as those for the finance lease arrangement with Banco de Crédito del Perú.

- As of December 31, 2016, the most restrictive financial covenant for Enel Generación Piura was the Debt to Equity Ratio.

In Brazil, the debt of Ampla includes the following covenants:

- Sixth and Seventh local bond issue whose outstanding amount as of December 31, 2016 was ThCh$134,687,654 and final maturity in June 2019, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt Coverage Ratio calculated by dividing EBITDA by Interest Expense.

- Eighth local bond issue whose outstanding amount as of December 31, 2016 was ThCh$66,129,084 and final maturity in July 2019, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and Debt to Equity Ratio calculated by dividing Debt by Net Equity.

- Loan with Banco Nacional de Desenvolvimiento (“BNDES”) whose outstanding amount as of December 31, 2016 was ThCh$136,449,040 and final maturity in December 2023, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt to Equity Ratio calculated by dividing Debt by Net Equity.

- Loan with Banco Citibank whose outstanding amount as of December 31, 2016 was ThCh$25,903,254 and final maturity in December 2018, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt to Equity Ratio calculated by dividing Debt by Net Equity.

- As of December 31, 2016, the most restrictive financial covenant for Ampla was the Debt/EBITDA ratio corresponding to the local bonds and bank borrowings with BNDES and Citibank.

In addition, the debt of Coelce includes the following covenants:

- Loans with Electrobrás and Banco do Brasil whose outstanding amount as of December 31, 2016 was ThCh$54,898,231 and final maturity in October 2023, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA.

- Loans with BNDES and Banco Itaú whose outstanding amount as of December 31, 2016 was ThCh$96,856,357 and final maturity in June 2023, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and Debt to Equity Ratio calculated by dividing Debt and Net Equity.

- Third local bond issue whose outstanding amount as of December 31, 2016 was ThCh$58,385,007 and final maturity in October 2018, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt Coverage Ratio calculated by dividing EBITDA by Interest Expense.

- As of December 31, 2016, the most restrictive financial covenant for Coelce was the Debt/EBITDA ratio corresponding to the third local bond issue.

Finally, in Brazil, the debt of Enel Cien includes the following covenants:

- Syndicated Loan, whose outstanding amount as of December 31, 2016 was ThCh$3,839,330 and final maturity in June 2020, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA and the Debt to Equity Ratio calculated by dividing Debt by Net Equity.

- As of December 31, 2016, the most restrictive financial covenant for Enel Cien was the Debt to Equity Ratio.

In Colombia, the debt of Empresa Generadora de Energía Eléctrica S.A. (“Emgesa”) includes the following covenants:

The accompanying notes are an integral part of these consolidated financial statements.

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- Loan with the Bank of Tokyo whose outstanding amount as of December 31, 2016 was ThCh$29,052,603 and final maturity in June 2017, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA. However, the obligation to comply with this covenant is subject to a downgrade in the credit rating of Emgesa that could result in losing is Investment Grade quality, as stated in the debt agreement. As of December 31, 2016, the covenant was not triggered.

Also, in Colombia, the debt of Codensa S.A. (“Codensa”) includes the following covenant:

- Loan with the Bank of Tokyo whose outstanding amount as of December 31, 2016 was ThCh$81,760,157 and final maturity in June 2020, is subject to the Debt Repayment Capacity Ratio calculated by dividing Debt by EBITDA.

All of our subsidiaries not mentioned in this note are not subject to compliance with financial covenants.

Lastly, in most of the contracts, debt acceleration for non-compliance with these covenants does not occur automatically but is subject to certain conditions, such as a cure period.

As of December 31, 2016 and 2015, neither the Company nor any of its subsidiaries were in default under their financial obligations summarized herein or other financial obligations whose defaults might trigger the acceleration of their financial commitments.

33.5 Other Information

Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)

Availability Agreements for Combined Cycles and Turbosteam

On March 18, 2015, the Undersecretary of Electric Energy issued its Note SS.EE. 476/2015, which established the procedure to coordinate the remuneration according to SE Resolution No. 95/2013 and the “Availability Agreements for Combined Cycles and Turbosteam” (hereinafter the “Availability Agreements”) entered into between Central Costanera and CAMMESA, effective on February 2014. As established in Note SS.EE. 476/2015, Central Costanera shall temporarily relinquish to receive, except for those already committed, the “Additional Remuneration Trust” established under SE Resolution No. 95/2013, its amendments and supplements, as well as, the “Remuneration for Non-Recurrent Maintenance” as established in Res. SE No. 529/2014, its amendments and supplements.

The procedure led to the reversal of the deductions made and applied to Central Costanera as established in Notes S.E. No. 7594/2013 and No. 8376/2013. Since January 2015, the concepts that Central Costanera relinquished were applied to compensate for the funds received from CAMMESA from that date on to perform the works provided for in the agreements. If the accumulated amount for the concepts relinquished is not sufficient to offset the total funds that Central Costanera received from CAMMESA, they shall be accrued and accumulated in a special account called “Availability Agreements Account”.

On June 29, 2015, the Secretary of Energy issued Note S.E. No. 1210/2015 instructing CAMMESA on the methodology to adapt the remuneration conditions set forth in the respective terms of the Availability Agreements, taking into account the concepts defined in SE Resolution Nos. 95/2013 and 529/2014 and any applicable regulation.

On July 3, 2015, Central Costanera and CAMMESA signed an addendum to the Availability Agreements. The initial terms and those in the addendum shall rule the agreement between the parties and shall be understood as entirely valid until the expiration date referred to in the agreements.

As a consequence of the above, during the year ended December 31, 2015, a decrease in revenue from sales of Ar$14.4 million (ThCh$606,885) and a net loss of Ar$59.2 million (ThCh$2,492,766) in other operating expense were recognized. As of the reporting date of these consolidated financial statements, the concepts relinquished by Costanera under the addendums to the Availability Agreements were approximately Ar$902.4 million (ThCh$26,380,577).

On December 16, 2016, the fifth addendum to the Availability Agreement for Turbosteam Equipment was signed, which approved (i) the re-allocation of US$ 5.3 million (ThCh$3,536,277) plus taxes of the funds required to perform the supplementary works on TurboSteam (“TV” in its Spanish acronym) unit No. 6, and (ii) the increase of up to US$ 10,575,000 (ThCh$7,072,190) plus taxes of the funds required to perform the supplementary works on TVs No. 6 and No. 7.

The Availability Agreement for Combined Cycle Equipment expired on October 31, 2016. Nonetheless, Central Costanera has currently requested to increase the funding established in the availability agreement for combined cycles and to increase by US$ 4.4 million (ThCh$2,924,933) the funds to perform the maintenance of the generation unit No. 10 of the Mitsubishi Combined Cycle.

The accompanying notes are an integral part of these consolidated financial statements.

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Resolution No. 482/2015 of the Secretary of Energy

On July 17, 2015, the Secretary of Energy issued Resolution No. 482/2015 replacing Resolution No. 529/2014, which is applicable to transactions carried out from February 2015. Resolution No. 482/2015, among other aspects, updated the remuneration of the MEM’s generating agents of thermal conventional or hydraulic national (with the exception of the hydraulic bi-national) types, and added a new remuneration concept called “Source for investments FONINVEMEM 2015-2018”, applicable from February 2015 until December 2018, to those generating companies participating in investment projects approved or to be approved by the Secretary of Energy. In this context, each generation unit built within the framework of the FONINVEMEM 2015-2018 investments is granted a Direct FONINVEMEM 2015-2018 Remuneration equal to 50% of the Direct Additional Remuneration for a period of up to ten years from its commercial implementation.

Resolution No. 22/2016 of the Secretary of Electrical Energy

On March 30, 2016, the Secretary of Electrical Energy through Resolution No. 22/2016 increased the remuneration established in Resolution No. 482/2015. The increases were applied to the remuneration concepts that are charged by the energy generating companies. The increases in the remuneration for fixed costs are applicable to thermal power plants (70% increase) and hydroelectrical power plants (120% increase). For the remuneration of variable costs, an increase of 40% is applicable to both thermal and hydroelectrical generating companies. The non-recurrent maintenance remuneration was increased by 60% for thermal and 25% for hydroelectrical, respectively. The additional remuneration was not increased. The resolution is applicable retrospectively to February 2016, and is a temporary measure that was effective until the new regulatory framework announced by the government in February 2017.

Resolution No. 19/2017 of the Secretary of Electrical Energy

On February 2, 2017, the Secretary of Electrical Energy (“S.E.E.”) issued Resolution No. 19/2017 replacing Resolution No. 22/2016, which sets remuneration guidelines applicable to power generating plants. Resolution No. 19/2017 defines the minimum remuneration for the energy capacity of technology and scale, and allows thermal units to offer equal remuneration for availability energy contracts for all technologies. Thermal generators may declare the price of firm capacity to be committed for a three-year period per unit each summer period, and may also provide the information by summer and winter periods (adjustments could be made during the period). As an exception applicable to 2017, Resolution No. 19/2017 authorized the declaration of the Guaranteed Availability Commitments (Compromisos de Disponibilidad Garantizada, in Spanish) in conjunction with the information required for the Winter Seasonal Programming, effective from May 1, 2017 to October 31, 2017. Generators will sign a Guaranteed Availability Commitment contract with CAMMESA, which may be transferred to demand as defined by SEE. The remuneration will be received by each generation unit with a committed capacity and will be in proportion to its compliance, with the minimum remuneration calculated based on the minimum price.

Resolution No. 19/2017, sets the following remunerations for generators, which are denominated in U.S. dollars (will be translated to Argentine pesos using the last business day exchange rate published by the Argentine Central Bank) for the term established in CAMMESA’s procedures:

Energy Capacity Remuneration for Thermal Power Plants:

Minimum Price (from February 2017)

• Large Cycle: US$ 3,050 per MW-monthly.

• Large Turbo Steam: US$ 4,350 per MW-monthly

• Large Turbo Generator: US$ 3,550 per MW-monthly

Base Price for remuneration with commitment

• May 2017 - October 2017: US$ 6,000 per MW-monthly

• November 2017 onwards: US$ 7,000 per MW-monthly

Additional price for remuneration with commitment (Maximum) (*)

• May 2017 – October 2017: US$1,000 MW-monthly

• November 2017 onwards: US$2,000 MW-monthly

(*) It is a maximum price because CAMMESA will carry out bidding processes based on the system needs upon facing critical requirements.

The accompanying notes are an integral part of these consolidated financial statements.

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Energy Remuneration:

Generated Energy

Combined Cycles and Turbosteam:

• Gas: US$5 per MWh

• LNG: US$8 per MWh

Operated Energy:

Thermal generators: US$2 per MWh.

The energy prices are applied at each Node. A charge of US$1 per MWh per energy generated at the power plant will be deducted in order to pay outstanding financing balances related to major or extraordinary maintenance.

Central Costanera is currently assessing the effects the implementation of Resolution No. 19/2017 will have on its business.

Central Vuelta de Obligado (VOSA)

On November 25, 2010, our principal generating subsidiaries in Argentina, Endesa Costanera, El Chocón and Dock Sud, entered into the “Agreement of Management and Operation of Projects to Increase the Availability of Thermal Generation and Adjustment of the Generation Remuneration 2008-2011” (the “Agreement”) with the Argentine Secretary of Energy. Under this Agreement, our subsidiaries were required to contribute their receivables from uncollected energy sales, known as Sales Settlements with Unspecified Due Dates (“LVFVD” in its Spanish acronym), between January 2008 and December 2011 to a trust for the construction of new generation plants. These receivables would be paid once the applicable tax rate defined in Article 3 of SE Resolution No. 406/03 is applied and converted into U.S. dollars (or “dollarized”) at the exchange rate of the date on which the Agreement was executed and would be repaid in 120 equal monthly installments starting with the first day of commercial operations with interest at a rate of 30-day LIBOR plus 5%.

Under an agreement dated May 11, 2011, the generating companies organized Central Vuelta de Obligado S.A. (“VOSA”), with an initial capital of Ar$ 500 thousand.

On October 24, 2012, VOSA entered into a turnkey contract for the supply and construction of the VOSA power plant with General Electric International Inc. and General Electric International Inc. Argentina branch (collectively, “GE”). On August 26, 2013, GE and the VOSA power plant trust amended the turnkey contract to provide for the supply, construction, start of operations and maintenance of a combined-cycle plant.

During the second half of 2015, after having finalized the corresponding tests, the operations of an open-cycle power plant with two gas turbine units of 270 MW each started. After several delays in the construction, the combined-cycle plant is expected to be completed in the forthcoming months, following a settlement agreement reached with GE.

According to a technical report issued by VOSA, the gas turbines of the open-cycle power plant passed all the operational tests and their operating performance was outstanding, and it only remained pending a few components and equipment to be imported in order to finish the second stage of the construction (combined-cycle power plant). Therefore, the Company concluded in 2015 that it was virtually certain that the whole project was to be fully completed.

Therefore, given the certainty that the combined-cycle will be operational in the near future, the Company concluded that recognition of the asset was appropriate because it was probable that the future economic benefits would flow to the entity.

In this sense, the Company recorded the effects of the dollarization of the LVFVD obligations in 2015. The income recorded was related to the following concepts:

- An update for the dollarization of the LVFVD obligations considering the exchange rate applicable at the date of the Agreement for a total of ThCh$ 141,559,960.

- Accrued interest on the dollarized LVFVD obligations, after the addition of interest rates referred to above, at a 30-day LIBOR rate plus 5%, amounting to ThCh$ 57,079,871.

On February 12, 2016, General Electric International Inc. (“GE”) the supplier in charge of the plant construction, made a claim for recognition of cost increases (overruns incurred) to the VOSA Trust. As of the end of the reporting date of these consolidated financial statements, the negotiation period has ended and based on the agreement terms, an arbitration process has been initiated

The accompanying notes are an integral part of these consolidated financial statements.

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before the Stock Exchange of Buenos Aires. VOSA believes that the claims are unfounded and unjustified. Nonetheless, the claims may have an effect on the timeline for completion of the power plant, despite the fact that GE has not complied with certain milestones for the project. VOSA, on behalf of the VOSA Trust, has executed and will continue executing the contractual guarantees for such non-compliance.

Management believes that the claims may have an effect on the completion timeline of the power plant, however, there is certainty that the whole project will be fully completed.

Loans with CAMMESA

As a result of certain financial constraints, Central Costanera requested funds in advance (“the Advances”) of future revenues from CAMMESA in order to cope with its cash needs for the operation of its power plant. During the period from March 2016 to May 2016, Central Costanera has received funds from CAMMESA for Ar$835.9 million (ThCh$35,941,122), subject to the commitment to sign an agreement to formalize the funds transferred and the payment terms.

Likewise, Central Costanera requested additional funds for Ar$ 464 million (ThCh$$ 19,532,550). On August 10, 2016, the Undersecretary of Electrical Energy, authorized the funds in advance and instructed CAMMESA to subscribe the necessary documents to formalize the transfers of the Advances and the payment terms.

On August 18, 2016, CAMMESA and Central Costanera signed a loan for consumption (mutuum) contract for Ar$ 1.3 billion (ThCh$54,716,064) to fund the operations of the power plant. The payment will be made in 48 equal monthly installments with a 12-month grace period, at the earlier of the last partial funds advance or December 31, 2016. The loan will accrue interest at the interest rate equivalent to the monthly return obtained for CAMMESA in its time deposits.

As of the reporting date of these consolidated financial statements, Central Costanera has received funds from CAMMESA for Ar$ 953.9 million (ThCh$ 40,150,050) to fund its operational needs. As of December 31, 2016, the outstanding balance owed to CAMMESA was Ar$ 1.27 billion (ThCh$ 53,621,742) which is classified as “Trade and other non-current payables” (as of December 31, 2015, the funds received from CAMMESA were Ar$ 570.9 million (ThCh$ 24,029,855), and the outstanding balance owed to CAMMESA was Ar$ 632.1 million (ThCh$$ 26,604,587) which is classified as “Trade and other current payables”).

Central Costanera has pledged its turbosteam units Nos. 1, 2, 3, 4, 6 and 7 and transferred its rights for the receivables with the Wholesale Electricity Market as security for is obligations with CAMMESA.

Edesur S.A.

Resolution No. 32/2015 of the Secretary of Energy

On March 11, 2015, the Secretary of Energy issued Resolution No. 32/2015, which among other things: (i) approves a transitory increase for Edesur with validity as from February 1, 2015 exclusively to pay for the energy acquired from the electricity market, salaries and assets and services supply; such increase, on account of the Integral Tariff Review (RTI) which to date has not been defined, arises from the difference between a theoretical tariff framework and the tariff framework in force for each category of user, according to the calculations of the Ente Nacional Regulador de la Electricidad (ENRE), which shall not be converted into tariff but it will be covered by means of transfers from CAMMESA with funds of the Argentine National Government; (ii) provided that as from February 1, 2015 the funds of the Program for Rational Use of Electric Energy (PUREE) shall be considered part of Edesur revenues, also on account of the RTI; (iii) confirms the procedure of the Cost Monitoring Mechanism (MMC) until January 31, 2015; and (iv) instructs CAMMESA to issue LVFVD in the amounts determined by the ENRE by virtue of the higher salary costs of the Company originated by the application of Resolution No. 836/2014 of the Secretary of Labor. In addition, Resolution No. 32/2015 allows for payment of remaining balances in favor of the Wholesale Electricity Market (MEM) by means of a payment plan to be defined and instructs ENRE to initiate actions prior to the RTI process. As a consequence of the above, during the year ended December 31, 2015, revenues were recognized for Ch$ 352,108 million, which are presented in the statement of comprehensive income as follows: for point (i), Ch$ 264,987 million in the line item “Other operating income” and Ch$ 644 million in the line “Financial income”; for point (ii), Ch$ 33,972 million within “Revenues” (Energy Sales); and for points (iii) and (iv), Ch$ 52,505 million in “Other operating income”.

As a consequence of Resolution No. 32/2015 and subsequent notes from the SE, the amount for concept (i) above was updated such that during the year ended December 31, 2016, revenues of Ar$395 million (ThCh$ 18,091,302) were recognized, which are presented in the statement of comprehensive income as “Other operating income”.

The accompanying notes are an integral part of these consolidated financial statements.

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SE Resolution No. 32/2015 covered operational costs, while investments continued to be financed through loan agreements with CAMMESA. At the same time, it allowed the repayment of the remaining balances due to MEM to the definition of a payment schedule, which as of the reporting date of these financial statements is still pending.

Emergency in the Argentine Electrical System

On December 16, 2015, the new national authorities declared through Decree 134/2015, the emergency at the National Electrical Sector effective until December 31, 2017. The Decree instructed to the Ministry of Energy and Mining (“MEyM” in its Spanish acronym) to elaborate and implement an action plan with the necessary activities for the generation, transmission and distribution segments within national jurisdiction, aimed to adapt the quality and safety of the energy supply and to ensure the rendering of electrical public services under appropriate technical and economic conditions.

MEyM Resolution No. 6/2016

On January 25, 2016, MEyM issued Resolution No. 6/2016, which approved the Summer Quarterly Re-Programming (“Reprogramación Trimestral de Verano”) applicable to the Wholesale Electricity Market (“MEM” in its Spanish acronym) and established the seasonal reference prices for energy and capacity for the February-April 2016 period.

Additionally, in order to move towards proper management of demand through incentives for saving and rational use of electricity of residential end users (“Plan Estímulo”), implemented through the MEM, an incentive system that will result in a mechanism of decreasing energy prices as counterpart of the effort of each residential user to reduce unnecessary consumption, which will be determined by comparing the monthly energy consumption with the one recorded in the same month of 2015.

Moreover, given the social significance of the electricity service, Resolution No. 6/2016 defined an energy volume at a price named Social Tariff (“Tarifa Social”), to be transferred at a minimum price to those included in the population of end users who, based on the criteria of classification communicated by the Ministry of Social Development of the Nation (“Ministerio de Desarrollo Social de la Nación”), lacks sufficient payment capacity to afford the general established prices.

Access to reduced wholesale prices for Social Tariff and incentive for saving is subject to the compliance with, in the case of distribution companies, the payment obligations in the MEM due from the effective date of Resolution No. 6/2016. Likewise, those distribution companies with outstanding debts with CAMMESA as of issuance date of the resolution, as in the case of Edesur, shall agree to, in no less than 30 business days, a payment plan for the past due debt and, also, to ensure payment of its purchases in the MEM through transferring its accounts receivables or other equivalent alternative mechanism at CAMMESA’s satisfaction, so as to ensure both the collection on current billing and the payment of the installments in the agreement to sign related to the past due debt. On March 21, 2016, Edesur presented a proposal of payment, which is conditioned on the results of the RTI process conducted under Resolution No. 6/2016. Subsequently, CAMMESA requested that all distribution companies modify their proposal of payments presented. As of the reporting date of these consolidated financial statements, the amended proposal is under analysis.

MEyM Resolution No. 7/2016

On January 27, 2016, MEyM Resolution No. 7/2016 was issued, instructing ENRE to:

i. Adjust the VAD in the tariff tables of the Company, on account of the RTI within the framework of the Transitional Tariff Regime established in the Agreement Act (“Acta Acuerdo”).

ii. Apply a Social Tariff to the population of end users resulting from the application of certain eligibility criteria, namely: be a retiree or pensioner for an amount equivalent to twice minimum salary; employed persons in a dependency relationship earning a gross remuneration lower or equal to two minimum salaries; be beneficiary in social programs; be enrolled in the Social Monotributo Regime; be incorporated in the Social Security Special Regime for domestic service workers; receiving unemployment insurance; or have a disability certificate, being excluded from the benefit those owners of more than real estate, motor vehicles whose models are up to 15 years old, or luxury aircrafts and boats.

iii. Include in the tariff tables the saving of electrical energy plan as stated in MEyM Resolution No. 6/2016.

iv. Carry out all necessary activities to proceed to the RTI, which must be effective before December 31, 2016.

The accompanying notes are an integral part of these consolidated financial statements.

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v. Take the necessary actions to implement the monthly payment of the distribution public service rendered by the distribution companies to allow users to better plan their domestic financing.

vi. Discontinue the Energy Efficiency Program (“PUREE” in its Spanish acronym) from the effective date of the new tariff prices and discontinue the application of the financing mechanism for distributors’ investment plan through loan agreements with CAMMESA.

Finally, the resolution established that the dividend distribution must agree the Agreement Act, which subordinate to verification from the ENRE of compliance with the investment plan.

ENRE Resolutions

On January 29, 2016, ENRE issued Resolution Nos. 1/2016 and 2/2016. The first resolution approves the tariff table for Edesur for the invoicing of meter readings beginning on February 1, 2016. The second resolution terminated the actual trust scheme called “Fondo para Obras de Concolidación y Expansión de Distribución Eléctrica, FOCEDE” which was in place to administer the funds from the application of ENRE Resolution No.347/2012 as of January 31, 2016.

The aforementioned resolutions will have a significant effect in several business areas of Edesur. In addition, besides the increases in the invoiced amounts that has been reflected in revenues from rendering of services, the resolutions led to another significant effect in the update of the amount of the fines that are adjusted in line with the changes in the valued added from distribution (VAD). During the year ended December 31, 2016, the update in the amount of fines resulted in a financial loss of approximately Ar$1 billion (ThCh$47,110,667), which is included in the “Finance cost” line item (see Note 31) in the consolidated statement of comprehensive income.

On March 21, 2016, ENRE issued Resolution No. 31/2016, instructing Edesur to indemnify all residential users that may have been affected by the energy supply interruption that occurred during the period from February 12 to February 18 of 2016. The indemnification amounts varied based on the number of hours of energy disruption. The total effect was Ar$ 88 million (ThCh$3,710,843).

On April 5, 2016, ENRE issued Resolution Nos. 54 and 55. Resolution No. 54 approved the tender specifications for contracting an advisor for the RTI of Edesur.

On the other hand, Resolution No. 55 approved the 2016 program for the RTI. The resolution defined the criteria, methodology and work plan that Edesur must follow to carry out its tariff studies. To elaborate on the tariff proposals, ENRE informed Edesur of the parameters for quality objectives and management, and the rate of return to be used in determining its own distribution cost.

On April 27, 2016, SE Resolution No. 41/2016 was issued, which approved the Seasonal Winter Programming for MEM effective for the period from May 1, 2016 to October 31, 2016, with tariffs equivalent to those established under MEyM Resolution No. 6/2016 dated January 27, 2016.

ENRE, through Resolution No. 290/2016, instructed Endenor S.A. and Edesur S.A. to eliminate the six per thousand (6‰) charge set by Article No. 1 of Law No. 23.681, from the invoicing date of meter readings subsequent to the effective date of Decree No. 695/2016.  

On July 7, 2016, Court Room II of the La Plata Federal Chamber issued a preliminary injunction suspending for three months the application of the provisions of MEyM Resolution Nos. 6/2016 and 7/2016 and ENRE Resolution No. 1/2016 for the Buenos Aires Province geographical area, until resolution by the Supreme Court.

On July 15, 2016, ENRE notified Edesur that beginning on that date and for a three-month period, unless the Supreme Court issued a resolution before that date, the tariffs and existing conditions as of January 31, 2016 would be applied. The application of the Social Tariff was delayed.

On September 6, 2016, the Supreme Court issued a resolution revoking the preliminary injunction of Court Room II of the La Plata Federal Chamber. Consequently, on September 12, 2016, CAMMESA was instructed to apply the tariff table approved by ENRE Resolution No. 1/2016 to the invoicing from that date, in the Gran Buenos Aires concession zone, except for those areas where a preliminary injunction was still effective.

The accompanying notes are an integral part of these consolidated financial statements.

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On September 27, 2016, MEyM instructed CAMMESA to pay the amounts (either billed or unbilled as of the instruction date) to MEM’s agents that were not received due to the temporary suspension of Resolution Nos. 6/2016 and 7/2016. The payment will be made in four monthly consecutive installments, with no interest or penalties. The first installment was paid in October 2016.

On September 28, 2016, ENRE, through Resolution No. 522/2016, summoned a public audience for a hearing intended to notify of and allow comments on tariff proposals presented by distribution companies for the next five-year period. Also, on that date, ENRE issued Resolution No. 523/2016, which stated that the unpaid amounts owed to users of any category (either billed or unbilled as of the resolution date), as a result of the preliminary injunction, will be paid in four consecutive monthly installments without interest and penalties. The first monthly installment was paid in October 2016.

On October 6, 2016, San Martín’s Federal Court No. 1 issued a ruling stating that the tariff table under MEyM Resolution Nos. 6/2016 and 7/2016 would not be applied to the users classified as T1 (low demand users).

On October 25, 2016, Edesur received notice from ENRE that compliance with San Martín’s Federal Court No. 1 ruling was suspended, pursuant to the appeals filed by ENRE, MEyM and other agents. Therefore, until the resolution of the appeals, the application of MEyM Resolution Nos. 6/2016 and 7/2016 and ENRE Resolution No. 1/2016 continues to be effective.  

On October 28, 2016, in relation to the RTI process, a hearing was held to notify and allow comments on tariff proposals presented by distribution companies under ENRE Resolution No. 55/2016.

Edesur presented a summary of its proposal for the next five years, which highlighted the projected significant investments for the period 2017 – 2021. Likewise, it stated its focus on improving the quality of service through the reduction of supply restitution timing, optimization of customer service and the incorporation of technology in all of its operating processes.

On November 14, 2016, ENRE published a note in relation to the public hearing, and committed to issuing a final resolution on the hearing 30 days after November 11, 2016.

On December 30, 2016, ENRE issued Resolution No. 626, which approved the document titled “Final Resolution Public Audience” (Resolución Final Audiencia Pública, in Spanish) prior to defining the tariffs to be applied. Likewise, it transferred to MEyM’s Undersecretary for Coordination of Tariff Policy (Subsecretaría de Coordinación de Política Tarifaria in Spanish) the topics discussed at the hearing that fall within the purview of that regulatory body.

On January 31, 2017, the Ministry of Energy and Mining issued increases in tariffs for electric energy services applicable to Edesur’s users effective February 1, 2017. The increase for residential customers will increase by a 61% - 148% range, based on level of consumption. It also considered encouraging energy savings by applying lower increases for those users consuming less energy compared to 2015.

On February 1, 2017, ENRE issued Resolution No. 64/2017 that was subsequently amended by ENRE Resolution Nos. 83/2017 and 97/2017, which approved new prices for the tariff table.

A delay in complying with certain milestones stated in the Agreement Act has affected Edesur’s Liquidity Ratio. Edesur believes that the adverse effects resulting from the lack of timely application of the rights to adjust its revenues will be reversed through the new composition of tariffs.

Enel Generación Argentina S.A. (formerly named Endesa Argentina)

Transfer of Shares

The Company transferred to its subsidiary Enel Generación Argentina S.A. (formerly named Endesa Argentina) all of its shares owned in (i) Edesur, a total of 387,263,754 shares equivalent to 43.10% of ownership interest; (ii) Enel Generación Costanera, a total of 174,414,427 shares equivalent to 24.85% of ownership interest; (iii) Enel Generación Hidroeléctrica El Chocón, a total of 7,405,768 shares equivalent to 2.48% of ownership interest; and (iv) Central Dock Sud, a total of 290,535,500 shares equivalent to 0.24% of ownership interest.

The transaction was accounted for as a business combination of entities under common control in accordance with accounting policy described in Note 2.7.6, and resulted in a charge of ThCh$12,174 in other reserves within equity.

The accompanying notes are an integral part of these consolidated financial statements.

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34. PERSONNEL FIGURES

The Group personnel, including that of subsidiaries and jointly-controlled companies in the five Latin American countries where the Group is present, is distributed as follows as of December 31, 2016 and 2015:

Country	12-31-2016				Annual Average
	Managers and key executives	Professionals and Technicians	Staff and others	Total
Chile	8	49	5	62	55
Argentina	50	3,748	1,137	4,935	4,902
Brazil	25	1,888	586	2,499	2,548
Peru	43	887	-	930	935
Colombia	37	1,820	41	1,898	1,910
Total	163	8,392	1,769	10,324	10,350
Country	12-31-2015				Annual Average
	Managers and key executives	Professionals and Technicians	Staff and others	Total
Chile	68	1,911	266	2,245	2,364
Argentina	46	3,609	1,168	4,823	4,724
Brazil	26	2,174	459	2,659	2,686
Peru	42	889	-	931	941
Colombia	36	1,480	28	1,544	1,633
Total	218	10,063	1,921	12,202	12,348

It is important to note that the Group’s operations in Chile, beginning on March 1, 2016, are part of the new company named Enel Chile (see Note 5.1), which has been classified as held for distribution to owners.

35. SANCTIONS

There are no sanctions that could materially affect the financial statements for the years ended December 31, 2016, 2015 and 2014.

The accompanying notes are an integral part of these consolidated financial statements.

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36. ENVIRONMENT

Environmental expenses for the years ended December 31, 2016, 2015 and 2014, are as follows:

Company incurring the cost	Project Name	Description	Project Status	12-31-2016						12-31-2015
				Costs incurred	Capitalized cost	Expense amount	Cost to be incurred in the future	Expected date of incurring the cost	Total expenditures	Costs incurred in prior period
				ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
EMGESA	Environmental resource management HIDRA	Environmental partner plan - Thermal power plants	In progress	989,582	989,582	-	-	-	989,582	135,659
		Environmental partner plan - Hydro power plants	In progress	4,280,036	4,280,036	-	72,259,750	12-31-2020	76,539,786	104,785,831
ENEL GENERACIÓN PERÚ	Preventing activities	Biodiversity protection, sewage water treatment	In progress	37,390	-	37,390	-	12-31-2016	37,390	100,570
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	In progress	125,947	-	125,947	-	12-31-2016	125,947	-
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	In progress	266,073	-	266,073	-	12-31-2016	266,073	205,882
	Waste mangement	Hazardous waste management	In progress	204,982	-	204,982	-	12-31-2016	204,982	189,528
	Environmental studies	Environmental studies	In progress	7,041	-	7,041	-	12-31-2016	7,041	21,373
	Mitigation and restoration	Soil and water protection and recovery	In progress	-	-	-	-	12-31-2016	-	2,549
	Impact compensations	Compensations, increasing gardents	Completed	-	-	-	-	12-31-2015	-	144,590
CHINANGO	Preventing activities	Biodiversity protection, sewage water treatment	In progress	-	-	-	-	12-31-2016	-	71,560
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	In progress	10,198	-	10,198	-	12-31-2016	10,198	8,487
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	In progress	335,969	-	335,969	-	12-31-2016	335,969	277,223
	Waste mangement	Hazardous waste management	In progress	41,525	-	41,525	-	12-31-2016	41,525	34,960
	Environmental studies	Environmental studies	In progress	751	-	751	-	12-31-2016	751	19,703
EDESUR	Preventing activities	Investment in environmental protection	In progress	44,214	44,214	-	-	12-31-2016	44,214	-
	Contaminating material	Contaminating material management	In progress	71,295	-	71,295	-	12-31-2016	71,295	44,281
	Transformers recovery	Project to invest in environment	In progress	-	-	-	-	12-31-2015	-	30,005
CODENSA	PCBs dismantling	Dismantling transformers with PCBS residues	In progress	792,848	836,224	(43,376)	4,654,504	12-31-2027	5,447,352	489,659
	Nueva Esperanza archaelogical rescue	Rescue of archaeological B.C. remains of culture Herrera at substation Nueva Esperanza construction site	In progress	64,812	64,812	-	-	12-31-2019	64,812	432,514
	Nueva Esperanza environmental compensation	Environmental compensation for construction of Nueva Esperanza substation	In progress	1,160,202	1,044,507	115,695	497,057	12-31-2019	1,657,259	458,328
	Dismantling power plant of Negro River	Contingency power plant of Negro River	In progress	338,126	-	338,126	2,430,519	12-31-2036	2,768,645	-
Total				8,770,991	7,259,375	1,511,616	79,841,830		88,612,821	107,452,702

Company incurring the cost	Project Name	Description	Project Status	12-31-2015						12-31-2014
				Costs incurred	Capitalized cost	Expense amount	Cost to be incurred in the future	Expected date of incurring the cost	Total expenditures	Costs incurred in prior period
				ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
EMGESA	El Quimbo hydro electrical plant project	Environmental management - El Quimbo plant construction	In progress	135,659	135,659	-	-	-	135,659	-
	Environmental resource management HIDRA	Plants environmental resource management	In progress	45,987,062	45,987,062	-	58,798,769	12-31-2020	104,785,831	45,490,454
ENEL GENERACIÓN PERÚ	Preventing activities	Biodiversity protection, sewage water treatment	Finalized	100,570	-	100,570	-	12-31-2015	100,570	76,405
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	Finalized	205,882	-	205,882	-	12-31-2015	205,882	156,570
	Waste management	Hazardous waste management	Finalized	189,528	-	189,528	-	12-31-2015	189,528	206,909
	Environmental studies	Environmental studies	Finalized	21,373	-	21,373	-	12-31-2015	21,373	16,722
	Mitigation and restoration	Soil and water protection and recovery	Finalized	2,549	-	2,549	-	12-31-2015	2,549	8,045
	Impact compensation	Compensations, gardens expansion	Finalized	144,590	-	144,590	-	12-31-2015	144,590	6,823
CHINANGO	Preventing activities	Biodiversity protection, sewage water treatment	Finalized	71,560	-	71,560	-	12-31-2015	71,560	5,974
	Landscaping and gardens	Gardens, landscaping and fauna maintenance	Finalized	8,487	-	8,487	-	12-31-2015	8,487	5,935
	Environmental monitoring	Air and climate protection, noise reduction, protection from radiation	Finalized	277,223	-	277,223	-	12-31-2015	277,223	239,904
	Waste management	Hazardous waste management	Finalized	34,960	-	34,960	-	12-31-2015	34,960	31,460
	Environmental studies	Environmental studies	Finalized	19,703	-	19,703	-	12-31-2015	19,703	5,229
EDESUR	Contaminating material	Contaminating material management	In progress	44,281	-	44,281	-	-	44,281	18,018
	Transformers recovery	Environmental investment project	In progress	30,005	30,005	-	-	-	30,005	-
CODENSA	PCBs dismantling	Dismantling transformers with PCBs residues	In progress	489,659	489,659	-	-	-	489,659	811,655
	Nueva Esperanza environmental compensatoin	Environmental compensation for construction of Nueva Esperanza substation	Finalized	458,328	458,328	-	-	12-31-2015	458,328	1,933,259
	Nueva Esperanza archaelogical rescue	Rescue of archaeological B.C. remains of culture Herrera at substation Nueva Esperanza construction site	In progress	432,514	432,514	-	-	-	432,514	-
Total				48,653,933	47,533,227	1,120,706	58,798,769		107,452,702	49,013,362

The accompanying notes are an integral part of these consolidated financial statements.

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37. FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED

As of December 31, 2016 and 2015, summarized financial information of our principal subsidiaries prepared under IFRS is as follows:

	12-31-2016
	Financial Statements	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Liabilities and Equity	Revenue	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income Before Taxes	Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chilectra Américas S.A. (1)	Consolidated	-	-	-	-	-	-	-	-	-	-	(1,723,792)	(1,723,792)	1,573,002	11,128,916	(128,641)	11,000,275	49,690,946	60,691,221
Inversiones Distrilima S.A.	Separate	17,950,619	47,930,837	65,881,456	70,732	-	65,810,724	65,881,456	-	-	-	(5,319)	(5,319)	1,059,895	14,277,620	(295,498)	13,982,122	(2,676,924)	11,305,198
Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Separate	127,455,526	699,734,546	827,190,072	197,041,479	295,981,622	334,166,971	827,190,072	585,196,341	(395,535,704)	189,660,638	142,777,471	111,170,462	(16,501,175)	94,690,975	(32,818,344)	61,872,631	(13,391,245)	48,481,386
Endesa Américas S.A. (1)	Separate	-	-	-	-	-	-	-	1,619	-	1,619	(6,784,321)	(6,784,321)	1,481,627	60,898,327	(49,589)	60,848,738	(4,895)	60,843,843
Enel Argentina S.A. (formerly named Endesa Argentina S.A.)	Separate	4,265,706	45,089,825	49,355,531	2,794,939	-	46,560,592	49,355,531	-	-	-	(81,113)	(81,113)	580,708	499,595	(142,211)	357,383	(9,618,076)	(9,260,693)
Enel Generación Costanera S.A (formerly named  Central Costanera S.A.)	Separate	42,859,190	144,780,468	187,639,658	66,627,887	99,471,471	21,540,300	187,639,658	92,632,650	(5,156,282)	87,476,369	49,370,918	32,449,101	(22,406,259)	10,244,681	1,046,607	11,291,288	(4,615,316)	6,675,972
Enel Generación El Chocón S.A. (formerly named  Hidroeléctrica El Chocón S.A.)	Separate	55,905,580	211,727,232	267,632,812	71,822,321	51,695,361	144,115,130	267,632,812	28,241,388	(3,210,487)	25,030,901	17,406,134	15,387,714	32,635,072	48,926,894	(16,864,740)	32,062,153	(37,305,897)	(5,243,744)
Emgesa S.A. E.S.P.	Separate	194,055,840	1,815,876,769	2,009,932,609	283,131,788	949,335,325	777,465,496	2,009,932,609	778,880,285	(293,212,188)	485,668,097	437,281,486	372,080,071	(98,230,552)	273,896,707	(106,927,731)	166,968,976	7,315,732	174,284,708
Generandes Perú S.A.	Separate	734,997	215,178,719	215,913,716	55,706	-	215,858,010	215,913,716	1,584	-	1,584	(17,282)	(17,282)	192,009	16,138,486	(50,275)	16,088,211	(9,597,187)	6,491,024
Enel Generación S.A. (formerly named Edegel S.A.A.)	Separate	175,056,196	649,569,786	824,625,982	130,676,656	174,864,322	519,085,004	824,625,982	360,186,708	(199,691,902)	160,494,806	109,999,691	71,730,290	(4,346,879)	89,733,743	(46,951,085)	42,782,658	(22,301,333)	20,481,325
Chinango S.A.C.	Separate	22,816,274	95,578,757	118,395,031	10,691,419	34,063,755	73,639,857	118,395,031	36,618,249	(9,631,376)	26,986,873	22,418,898	19,381,222	(549,157)	26,507,384	(9,117,602)	17,389,783	(2,351,750)	15,038,033
Enel Brasil S.A.	Separate	181,693,589	873,309,864	1,055,003,453	64,246,546	8,025,612	982,731,295	1,055,003,453	-	(5,827)	(5,827)	(26,661,221)	(30,031,760)	45,759,306	100,022,771	7,461,644	107,484,415	119,491,897	226,976,312
Central Generadora Termoeléctrica Fortaleza S.A.	Separate	46,490,027	135,143,181	181,633,208	41,167,056	738,663	139,727,489	181,633,208	159,476,559	(96,350,024)	63,126,535	54,553,159	48,976,122	561,507	49,537,629	(17,987,864)	31,549,765	18,153,737	49,703,502
EGP Cachoeira Dourada S.A. (formerly named Cachoeira Dourada)	Separate	91,524,584	88,624,824	180,149,408	78,568,361	924,648	100,656,399	180,149,408	192,911,834	(100,796,289)	92,115,545	84,209,590	79,153,401	4,344,793	83,498,194	(28,556,439)	54,941,755	13,203,660	68,145,415
Enel Cien S.A. (formerly named Compañía de Interconexión Energética S.A.)	Separate	39,273,098	196,462,075	235,735,173	43,742,031	26,526,373	165,466,769	235,735,173	52,179,099	(1,981,269)	50,197,831	44,550,050	34,000,180	(5,419,368)	28,580,811	(9,763,193)	18,817,618	19,718,197	38,535,815
Compañía de Transmisión del Mercosur S.A.	Separate	11,532,662	679,232	12,211,894	10,043,390	18,002,743	(15,834,239)	12,211,894	1,051,182	-	1,051,182	660,287	562,748	(6,180,970)	(5,618,222)	-	(5,618,222)	3,681,261	(1,936,961)
Compañía Energética Do Ceará S.A.	Separate	323,273,919	702,073,551	1,025,347,470	280,764,077	228,207,112	516,376,281	1,025,347,470	804,639,771	(537,142,974)	267,496,796	163,849,051	106,962,177	(14,201,772)	92,946,508	(16,050,849)	76,895,659	60,070,811	136,966,470
Enel Solucoes S.A. (formerly named EN-Brasil Comercio e Servicios S.A.)	Separate	4,107,546	3,310,406	7,417,952	8,352,136	-	(934,184)	7,417,952	6,523,345	(4,036,707)	2,486,638	(1,402,416)	(1,587,341)	(293,519)	(1,880,860)	36,470	(1,844,390)	21,986	(1,822,404)
Ampla Energía E Servicios S.A.	Separate	356,103,637	1,306,962,929	1,663,066,566	429,527,099	755,397,217	478,142,250	1,663,066,566	879,498,778	(605,120,722)	274,378,056	116,502,441	27,170,319	(86,501,348)	(60,350,089)	17,821,058	(42,529,031)	60,487,366	17,958,335
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	275,367,269	1,000,054,356	1,275,421,625	367,437,624	341,673,262	566,310,739	1,275,421,625	928,620,576	(532,281,720)	396,338,856	310,887,600	251,014,541	(35,066,291)	211,330,904	(91,004,375)	120,326,529	(87,853)	120,238,676
Inversora Codensa S.A.	Separate	489	63	552	25	-	527	552	-	-	-	(14)	(14)	-	(14)	(8)	(21)	(3)	(24)
Empresa Distribuidora Sur S.A.	Separate	253,221,877	445,997,003	699,218,880	497,137,195	200,282,842	1,798,843	699,218,880	664,100,267	(303,352,490)	360,747,777	116,153,334	95,629,238	(109,572,953)	(13,905,458)	(6,942,666)	(20,848,124)	(5,610,106)	(26,458,230)
Generalima S.A.C.	Separate	5,834,984	39,048,294	44,883,278	22,264,813	6,593,516	16,024,949	44,883,278	980	-	980	(9,184,119)	(9,185,311)	(1,316,611)	(10,501,921)	-	(10,501,921)	(1,163,946)	(11,665,867)
Endesa Cemsa, S.A.	Separate	17,208,360	128,253	17,336,613	16,143,845	-	1,192,768	17,336,613	2,158,429	(232,151)	1,926,278	(179,408)	(265,687)	32,671	(213,715)	(115,586)	(329,301)	(425,377)	(754,678)
Grupo Dock Sud, S.A.	Consolidated	32,326,301	106,518,467	138,844,768	28,697,131	36,535,241	73,612,396	138,844,768	86,363,052	(52,964,973)	33,398,079	24,297,233	12,931,802	7,586,902	20,535,482	(7,169,616)	13,365,865	(19,623,374)	(6,257,509)
Eléctrica Cabo Blanco, S.A.C.	Consolidated	64,980,868	110,487,098	175,467,966	34,277,483	60,115,035	81,075,448	175,467,966	65,145,450	(28,326,441)	36,819,009	29,709,679	24,217,244	(1,636,402)	22,578,731	(6,989,082)	15,589,649	(3,009,957)	12,579,692
Grupo Distrilima	Consolidated	132,512,236	699,734,546	832,246,782	184,218,301	295,981,622	352,046,859	832,246,782	585,196,341	(395,535,704)	189,660,637	142,772,152	111,165,143	(15,441,279)	95,745,552	(33,113,841)	62,631,710	(14,191,110)	48,440,600
Grupo Endesa Américas (1)	Consolidated	495,139,988	3,531,318,252	4,026,458,240	565,316,117	1,307,898,393	2,153,243,730	4,026,458,240	1,059,710,034	(414,536,751)	645,173,283	516,744,797	409,068,322	(97,898,919)	381,491,880	(138,083,079)	243,408,801	133,135,660	376,544,461
Grupo Enel Brasil	Consolidated	922,063,106	2,467,478,599	3,389,541,705	827,019,387	808,602,605	1,753,919,713	3,389,541,705	1,881,901,783	(1,130,554,813)	751,346,970	436,678,765	265,494,448	(68,168,235)	196,493,255	(47,044,832)	149,448,423	222,513,095	371,961,518
Grupo Generandes Perú	Consolidated	198,576,626	732,464,532	931,041,158	141,392,940	208,928,077	580,720,141	931,041,158	396,572,660	(209,089,398)	187,483,263	132,401,308	91,094,231	(4,704,026)	111,186,081	(56,118,962)	55,067,119	(12,887,172)	42,179,947
Grupo Enel Argentina (formerly named Endesa Argentina)	Consolidated	102,611,825	358,180,334	460,792,159	140,747,156	149,634,991	170,410,012	460,792,159	119,855,164	(8,366,769)	111,488,395	66,677,481	47,737,245	10,531,539	59,226,545	(15,973,902)	43,252,643	(54,219,733)	(10,967,090)

(1) Entities merged with Enel Américas, on December 1, 2016.

The accompanying notes are an integral part of these consolidated financial statements.

F-169

	12-31-2015
	Financial Statements	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Liabilities and Equity	Revenue	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income Before Taxes	Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Continuing Operations:
Inversiones Distrilima S.A.	Separate	18,246,316	50,156,404	68,402,720	325,792	-	68,076,928	68,402,720	-	-	-	(5,028)	(5,028)	959,095	21,003,199	(266,930)	20,736,269	1,311,144	22,047,413
Empresa de Distribución Eléctrica de Lima Norte S.A.A.	Separate	98,125,347	675,858,105	773,983,452	192,215,161	269,823,997	311,944,294	773,983,452	562,046,426	(379,015,102)	183,031,324	138,377,938	107,705,092	(16,772,560)	91,535,126	(27,924,718)	63,610,408	6,877,338	70,487,746
Endesa Argentina S.A.	Separate	1,814,204	32,328,045	34,142,249	616,318	-	33,525,931	34,142,249	-	-	-	(64,074)	(64,074)	1,023,419	959,344	(336,372)	622,972	(10,352,540)	(9,729,568)
Central Costanera S.A.	Separate	27,559,412	142,918,106	170,477,518	102,001,988	53,611,202	14,864,328	170,477,518	100,856,664	(4,598,130)	96,258,534	41,604,328	20,372,179	(24,944,190)	(4,012,455)	3,013,645	(998,809)	(4,729,767)	(5,728,576)
Hidroeléctrica El Chocón S.A.	Separate	44,240,854	240,460,115	284,700,969	71,433,902	63,908,193	149,358,874	284,700,969	40,004,655	(4,574,336)	35,430,319	28,820,101	27,009,175	141,308,348	169,850,815	(59,047,935)	110,802,880	(44,667,506)	66,135,374
Emgesa S.A. E.S.P.	Separate	172,918,511	1,803,546,987	1,976,465,498	349,736,334	831,187,906	795,541,258	1,976,465,498	778,768,426	(321,664,855)	457,103,571	412,046,148	372,828,429	(39,872,136)	332,845,961	(120,949,697)	211,896,264	(91,252,276)	120,643,988
Generandes Perú S.A.	Separate	1,945,582	225,170,087	227,115,669	1,364,513	-	225,751,156	227,115,669	-	-	-	(32,396)	(32,396)	172,406	42,094,142	(50,002)	42,044,140	4,890,902	46,935,042
Edegel S.A.A.	Separate	111,421,412	723,995,979	835,417,391	117,775,269	188,814,672	528,827,450	835,417,391	343,761,564	(143,234,611)	200,526,953	164,344,988	116,593,374	(9,260,148)	122,550,483	(31,389,446)	91,161,037	4,059,334	95,220,371
Chinango S.A.C.	Separate	7,647,526	112,688,111	120,335,637	8,369,365	40,621,719	71,344,553	120,335,637	39,114,967	(8,235,270)	30,879,697	26,280,972	23,095,212	(1,057,861)	22,037,351	(6,827,262)	15,210,089	(708,295)	14,501,794
Enel Brasil S.A.	Separate	110,127,302	736,398,772	846,526,074	51,310,987	15,859,063	779,356,024	846,526,074	-	-	-	(21,299,668)	(21,417,232)	26,840,323	122,982,000	(8,959,080)	114,022,920	(194,845,796)	(80,822,876)
Central Generadora Termoeléctrica Fortaleza S.A.	Separate	36,820,903	114,401,115	151,222,018	35,746,585	638,562	114,836,871	151,222,018	159,051,928	(111,228,593)	47,823,335	40,544,633	34,866,986	3,245,644	38,112,630	(13,299,903)	24,812,727	(26,130,490)	(1,317,763)
Centrais Elétricas Cachoeira Dourada S.A.	Separate	43,483,356	77,906,552	121,389,908	33,306,336	3,370,881	84,712,691	121,389,908	91,563,206	(17,395,858)	74,167,348	66,975,312	61,972,753	3,514,857	65,487,610	(22,519,731)	42,967,879	(13,348,590)	29,619,289
Compañía de Interconexión Energética S.A.	Separate	29,310,056	185,030,817	214,340,873	57,239,098	30,170,820	126,930,955	214,340,873	55,533,872	(3,125,790)	52,408,082	45,152,292	34,319,511	15,559,865	49,879,376	(17,387,165)	32,492,212	(27,600,284)	4,891,928
Compañía de Transmisión del Mercosur S.A.	Separate	13,944,906	934,689	14,879,595	10,880,864	17,896,009	(13,897,278)	14,879,595	1,644,146	-	1,644,146	922,095	770,315	(17,579,292)	(16,801,955)	(998,283)	(17,800,238)	4,199,017	(13,601,221)
Compañía Energética Do Ceará S.A.	Separate	267,538,669	569,364,164	836,902,833	219,528,371	223,842,286	393,532,176	836,902,833	810,184,252	(581,689,470)	228,494,782	136,443,771	100,911,453	(12,650,857)	85,012,938	(12,997,078)	72,015,860	(97,029,555)	(25,013,695)
EN-Brasil Comercio e Servicios S.A.	Separate	2,673,792	1,448,487	4,122,279	3,234,058	-	888,221	4,122,279	5,603,633	(3,041,559)	2,562,074	(614,126)	(782,696)	136,846	(645,850)	(735,808)	(1,381,657)	(163,062)	(1,544,719)
Ampla Energía E Servicios S.A.	Separate	385,803,702	1,016,536,280	1,402,339,982	333,276,269	608,907,379	460,156,334	1,402,339,982	1,026,680,070	(804,701,402)	221,978,668	93,688,470	26,422,575	(35,938,130)	(13,026,593)	2,147,615	(10,878,978)	(139,016,506)	(149,895,484)
Compañía Distribuidora y Comercializadora de Energía S.A.	Separate	207,553,184	841,585,897	1,049,139,081	247,749,853	281,940,697	519,448,531	1,049,139,081	884,467,266	(500,570,712)	383,896,554	295,143,439	235,587,544	(27,459,741)	207,999,316	(84,883,205)	123,116,111	(61,679,252)	61,436,859
Inversora Codensa S.A.	Separate	491	63	554	3	-	551	554	-	-	-	(189)	(189)	-	(189)	(8)	(198)	(91)	(289)
Empresa Distribuidora Sur S.A.	Separate	191,441,460	443,412,232	634,853,692	431,630,045	174,966,573	28,257,074	634,853,692	607,344,916	(157,387,237)	449,957,679	119,294,227	103,775,386	(3,942,519)	99,980,518	(463,471)	99,517,047	(8,266,492)	91,250,555
Generalima, S.A.C.	Separate	5,697,317	50,472,490	56,169,807	20,328,170	8,150,819	27,690,818	56,169,807	-	-	-	(375,459)	(376,682)	(2,233,357)	(412,473)	(285,187)	(697,659)	727,779	30,120
Endesa Cemsa, S.A.	Separate	22,954,619	91,195	23,045,814	21,098,368	-	1,947,446	23,045,814	2,269,586	(1,017,940)	1,251,646	(1,206,493)	(1,255,814)	897,816	(357,998)	(1,466,245)	(1,824,243)	(626,380)	(2,450,623)
Grupo Dock Sud, S.A.	Consolidated	46,722,732	126,188,103	172,910,835	25,736,485	67,304,445	79,869,905	172,910,835	69,962,810	(43,265,695)	26,697,115	14,806,741	3,309,477	53,770,197	57,229,446	(18,102,752)	39,126,694	(24,156,874)	14,969,820
Eléctrica Cabo Blanco, S.A.C.	Consolidated	54,357,844	81,815,037	136,172,881	19,831,659	47,845,465	68,495,757	136,172,881	58,092,640	(26,124,119)	31,968,521	23,168,206	17,663,200	(5,755,667)	12,013,784	(4,166,389)	7,847,394	720,031	8,567,425
Grupo Distrilima	Consolidated	116,371,663	675,858,105	792,229,768	192,540,953	269,823,997	329,864,818	792,229,768	562,046,426	(379,015,102)	183,031,324	138,372,910	107,700,064	(15,813,466)	92,489,193	(28,191,648)	64,297,545	7,349,620	71,647,165
Grupo Enel Brasil	Consolidated	796,102,019	1,994,170,372	2,790,272,391	653,756,270	725,006,817	1,411,509,304	2,790,272,391	2,016,488,833	(1,385,921,254)	630,567,579	363,360,618	238,408,123	(36,592,248)	195,064,201	(76,715,148)	118,349,053	(370,529,946)	(252,180,893)
Grupo Generandes Perú	Consolidated	120,047,319	808,405,916	928,453,235	126,541,945	229,436,392	572,474,898	928,453,235	382,452,709	(151,046,058)	231,406,651	190,593,564	139,656,190	(10,145,603)	133,321,519	(38,266,710)	95,054,809	(9,131,696)	85,923,113
Grupo Endesa Argentina	Consolidated	73,348,681	385,562,798	458,911,479	173,663,474	115,955,351	169,292,654	458,911,479	140,398,933	(9,172,466)	131,226,467	70,334,513	47,291,438	117,190,764	165,754,140	(56,407,124)	109,347,016	(50,970,094)	58,376,922
Discontinued Operations:
Chilectra S.A.	Consolidated	764,264,413	766,740,395	1,531,004,808	363,516,173	54,831,044	1,112,657,591	1,531,004,808	1,257,732,164	(983,732,902)	273,999,262	185,114,892	149,293,693	12,669,568	176,628,861	(36,956,051)	188,750,734	(111,222,756)	77,527,978
Grupo Servicios Informaticos e Inmobiliarios Ltda.	Consolidated	54,816,036	11,561,339	66,377,375	5,586,878	1,305,133	59,485,364	66,377,375	8,660,778	-	8,660,778	(397,888)	(511,775)	2,260,216	6,041,979	(765,180)	5,276,799	(76,578)	5,200,221
Empresa Nacional de Electricidad S.A.	Separate	563,422,232	3,601,559,005	4,164,981,237	807,918,132	1,027,287,096	2,329,776,009	4,164,981,237	1,407,824,978	(1,061,507,980)	346,316,998	225,230,207	143,639,730	(126,334,330)	246,255,963	(32,834,204)	213,421,760	(92,076,119)	121,345,641
Empresa Eléctrica Pehuenche S.A.	Separate	63,745,589	201,366,300	265,111,889	64,820,897	51,972,920	148,318,072	265,111,889	193,189,705	(28,569,912)	164,619,793	159,244,283	150,615,199	2,049,116	152,664,315	(34,647,895)	118,016,421	33,526	118,049,947
Compañía Eléctrica Tarapacá S.A.	Separate	82,875,363	509,275,829	592,151,192	115,138,485	44,379,433	432,633,274	592,151,192	230,852,534	(139,555,849)	91,296,685	73,665,446	64,306,244	24,323,943	88,341,669	(18,079,279)	70,262,390	(624)	70,261,766
Grupo Endesa Chile	Consolidated	4,412,561,440	2,866,208,895	7,278,770,335	2,527,875,495	1,207,004,760	3,543,890,080	7,278,770,335	1,543,810,316	(880,891,223)	662,919,093	516,860,724	401,818,817	(114,252,182)	300,487,081	(76,655,819)	635,020,813	(347,578,686)	287,442,127
Grupo Inversiones GasAtacama Holding Ltda.	Consolidated	245,456,212	207,236,190	452,692,402	24,048,629	49,959,438	378,684,335	452,692,402	183,015,183	(110,330,364)	72,684,819	57,943,644	46,360,426	10,304,578	56,660,371	(10,444,811)	46,215,560	(3,059,806)	43,155,754

The accompanying notes are an integral part of these consolidated financial statements.

F-170

38. SUBSEQUENT EVENTS

Dividend

On January 11, 2017, the Company re-submitted Form No. 1 required by Circular No. 660 of the SVS, which had been previously submitted on November 24, 2016, to communicate the distribution of an interim dividend equivalent to 15% of the net income for the nine-month period ended September 30, 2016 to be paid on January 27, 2017. The updated information referred to the number of shares entitled to receive such dividend, as the total number of 57,453,055,120 shares fluctuated since the communication made on November 24, 2016 to a total number of 57,387,251,604 shares as a result of the withdrawal rights exercised by the minority shareholders of the Company and the merged entities, Endesa Américas S.A. and Chilectra Américas S.A. The updated total number of shares did not modify the total amount of the interim dividend of Ch$54,387,251,604 to be paid.

New Energy Tariffs in Argentina

Energy Generation:

On February 2, 2017, the Secretary of Electrical Energy (“SEE”) issued Resolution No. 19/2017 replacing Resolution No. 22/2016, which sets remuneration guidelines applicable to power generating plants. Resolution No. 19/2017 defines the minimum remuneration for the energy capacity of technology and scale, and allows thermal units to offer equal remuneration for availability energy contracts for all technologies. Thermal generators may declare the price of firm capacity to be committed for a three-year period per unit each summer period, and may also provide the information by summer and winter periods (adjustments could be made during the period). As an exception applicable to 2017, Resolution No. 19/2017 authorized the declaration of the Guaranteed Availability Commitments (Compromisos de Disponibilidad Garantizada, in Spanish) in conjunction with the information required for the Winter Seasonal Programming, effective from May 1, 2017 to October 31, 2017. Generators will sign a Guaranteed Availability Commitment contract with CAMMESA, which may be transferred to demand as defined by SEE. The remuneration will be received by each generation unit with a committed capacity and will be in proportion to its compliance, with the minimum remuneration calculated based on the minimum price.

Resolution No. 19/2017, sets the following remunerations for generators, which are denominated in U.S. dollars (will be translated to Argentine pesos using the last business day exchange rate published by the Argentine Central Bank) for the term established in CAMMESA’s procedures:

Energy Capacity Remuneration for Thermal Power Plants:

Minimum Price (from February 2017)

• Large Cycle: US$ 3,050 per MW-monthly.

• Large Turbo Steam: US$ 4,350 per MW-monthly

• Large Turbo Generator: US$ 3,550 per MW-monthly

Base Price for remuneration with commitment

• May 2017 - October 2017: US$ 6,000 per MW-monthly

• November 2017 onwards: US$ 7,000 per MW-monthly

Additional price for remuneration with commitment (Maximum) (*)

• May 2017 – October 2017: US$1,000 MW-monthly

• November 2017 onwards: US$2,000 MW-monthly

(*) It is a maximum price because CAMMESA will carry out bidding processes based on the system needs upon facing critical requirements.

Energy Remuneration:

Generated Energy

Combined Cycles and Turbosteam:

• Gas: US$5 per MWh

• LNG: US$8 per MWh

Operated Energy:

Thermal generators: US$2 per MWh.

The energy prices are applied at each Node. A charge of US$1 per MWh per energy generated at the power plant will be deducted in order to pay outstanding financing balances related to major or extraordinary maintenance.

The accompanying notes are an integral part of these consolidated financial statements.

F-171

Central Costanera is currently assessing the effects the implementation of Resolution No. 19/2017 will have on its business.

Energy Distribution:

On January 31, 2017, the Ministry of Energy and Mining issued increases in tariffs for electric energy services applicable to Edesur’s users effective February 1, 2017. For residential customers, the tariffs will increase by a 61% - 148% range, based on level of consumption. It also considered encouraging energy savings by applying lower increases for those users consuming less energy compared to 2015.

On February 1, 2017, ENRE issued Resolution No. 64/2017 that was subsequently amended by ENRE Resolution Nos. 83/2017 and 97/2017, which approved new prices for the tariff table.

The Group is currently assessing the effect that the implementation of the new tariffs in Argentina will have on their businesses.

Business Combination

On February 14, 2017, our subsidiary Enel Brasil S.A., obtained the appropriate authorizations from the antitrust authorities, Conselho Administrativo de Defensa Econômica (“CADE”) and the sector regulator, Agência Antimonopólica de Energía Eléctrica (“ANEEL”) to acquire approximately a 94.8% of the equity interest of Celg Distribuição S.A. (“CELG”). The purchase agreement has been signed for a total price of R$ 2.2 billion (approximately US$ 640 million).

CELG was incorporated in 1956 and its headquarters are located at Goiana. CELG operates in a concession zone of approximately 337,000 square kilometers providing services to 2.9 million of customers. The concession matures in 2045.

The acquisition of CELG was financed with resources raised by the Company’s capital increase approved at the end of 2012. This acquisition increases the customers of Enel Brasil from a base of 7 to 10 million, which increases the number of the Group’s customers at a Global level to approximately 65 million.

Given that the acquisition of CELG is recent, the initial accounting of the business combination is incomplete as of the issuance date of these financial statements. Consequently, the disclosures about the fair value of assets acquired and liabilities assumed and other disclosures required by IFRS 3 Business Combinations for the acquisition of CELG cannot be provided.

Change in functional and presentation currency of the consolidated financial statements of Enel Américas

As a result of the corporate reorganization process completed during the year ended December 31, 2016, the currency of the primary economic environment and generation and use of cash flows of the Company will principally be the United States dollar. Consequently, effective on January 1, 2017, the Company will change both its functional currency and the currency in which it presents its consolidated financial statements, from Chilean Pesos (“CLP”) to the United States dollar (“USD”).

This change in functional currency will be accounted for prospectively from the date of the change by translating all items of the financial statements into the new functional currency using the exchange rate at the date of the change.

The change in presentation currency will be accounted for as a change in accounting policy and is applied retrospectively, as if the new presentation currency had always been the presentation currency. Consequently, comparative figures for years prior to the effective date of January 1, 2017 will be restated to be presented in USD using average exchange rates for income and expenses and the closing rate at the balance sheet date for assets and liabilities. Issued capital, retained earnings and other reserves within equity will be translated using historic rates. Resulting exchange differences will be recognized within equity.

There are no additional subsequent events that have occurred between January 1, 2017 and the issuance date of these financial statements.

The accompanying notes are an integral part of these consolidated financial statements.

F-172

APPENDIX 1 ENEL AMÉRICAS GROUP ENTITIES:

This appendix is part of Note 2.4, “Subsidiaries.”

Taxpayer ID No. (RUT)	Company	Functinal Currency	% Ownership as of 12/31/2016			% Ownership as of 12/31/2015			Relationship	Country	Business Activity
			Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Ampla Energía E Serviços S.A.	Real	31.73%	67.91%	99.64%	13.68%	85.95%	99.63%	Subsidiary	Brazil	Electric energy production, transportation and distribution
Foreign	EGP Cachoeira Dourada S.A.	Real	0.00%	99.75%	99.75%	0.00%	99.61%	99.61%	Subsidiary	Brazil	Generation and sale of electricity
Foreign	Central Dock Sud, S.A.	Argentine peso	0.00%	70.24%	70.24%	0.00%	69.99%	69.99%	Subsidiary	Argentina	Electric energy generation, transmission and distribution
Foreign	Central Generadora Termoeléctrica Fortaleza S.A.	Real	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Development of a thermoelectric project
Foreign	Chinango S.A.C.	Peruvian Soles	0.00%	80.00%	80.00%	0.00%	80.00%	80.00%	Subsidiary	Peru	Electric energy generation, sales and distribution
Foreign	Enel Cien S.A. (formerly named Cien S.A.)	Real	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Electric energy generation, transportation and distribution
Foreign	Compañía de Transmisión del Mercosur S.A.	Argentine peso	0.00%	100.00%	100.00%	0.00%	99.99%	99.99%	Subsidiary	Argentina	Electric energy generation, transportation and distribution
Foreign	Compañía Distribuidora y Comercializadora de Energía S.A. (3)	Colombian peso	48.41%	0.00%	48.41%	21.14%	36.01%	57.15%	Subsidiary	Colombia	Electric energy distribution and sales
Foreign	Compañía Energética Do Ceará S.A.	Real	15.18%	58.87%	74.05%	15.18%	58.87%	74.05%	Subsidiary	Brazil	Complete electric energy cycle
Foreign	Distrilec Inversora S.A.	Argentine peso	51.50%	0.00%	51.50%	27.19%	24.31%	51.50%	Subsidiary	Argentina	Portfolio company
Foreign	Enel Generación Perú (formerly named Edegel S.A.A.)	Peruvian Soles	29.40%	54.20%	83.60%	0.00%	83.60%	83.60%	Subsidiary	Peru	Electric energy generation, sales and distribution
Foreign	Electrica Cabo Blanco, S.A.C.	Peruvian Soles	80.00%	20.00%	100.00%	80.00%	20.00%	100.00%	Subsidiary	Peru	Portfolio company
Foreign	Emgesa S.A. E.S.P. (1)	Colombian peso	48.48%	0.00%	48.48%	21.60%	34.83%	56.43%	Subsidiary	Colombia	Electric energy generation
Foreign	Emgesa Panama S.A. (1)	U.S. dollar	0.00%	48.48%	48.48%	0.00%	56.43%	56.43%	Subsidiary	Panama	Purchase/Sale of electric energy
Foreign	Enel Distribución Perú S.A. (formerly named Edelnor S.A.A.)	Peruvian Soles	24.00%	51.68%	75.68%	24.00%	51.68%	75.68%	Subsidiary	Peru	Electric energy distribution and sales
Foreign	Empresa Distribuidora Sur S.A.	Argentine peso	0.00%	99.45%	99.45%	22.25%	77.20%	99.45%	Subsidiary	Argentina	Electric energy distribution and sales
Foreign	Enel Generación Piura (formerly named Empresa Eléctrica Piura S.A.)	Peruvian Soles	0.00%	96.50%	96.50%	0.00%	96.50%	96.50%	Subsidiary	Peru	Electric energy generation (thermal and natural gas)
Foreign	Enel Argentina S.A. (formerly named Endesa Argentina S.A.)	Argentine peso	99.88%	0.12%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Argentina	Portfolio company
Foreign	Enel Brasil S.A.	Real	90.06%	9.94%	100.00%	50.09%	49.91%	100.00%	Subsidiary	Brazil	Portfolio company
Foreign	Enel Trading Argentina S.R.L.	Argentine peso	55.00%	45.00%	100.00%	55.00%	45.00%	100.00%	Subsidiary	Argentina	Wholesale purchase and sale of electric energy
Foreign	Enel Generación Costanera S.A.	Argentine peso	0.00%	75.68%	75.68%	0.00%	75.68%	75.68%	Subsidiary	Argentina	Electric energy generation and sales
Foreign	Enel Soluciones S.A. (formerly named EN-Brasil Comercio e Servicios S.A.)	Real	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Rendering of services for energy industry and others
Foreign	Eólica Fazenda Nova-Geracao e Comercializacao de Energia S.A.	Real	0.00%	99.95%	99.95%	0.00%	99.95%	99.95%	Subsidiary	Brazil	Energy generation, transmission, distribution and sales
Foreign	Generalima S.A.C.	Peruvian Soles	100.00%	0.00%	100.00%	100.00%	0.00%	100.00%	Subsidiary	Peru	Portfolio company
Foreign	Generandes Perú S.A.	Peruvian Soles	100.00%	0.00%	100.00%	39.00%	61.00%	100.00%	Subsidiary	Peru	Portfolio company
Foreign	Enel Generación El Chocón S.A. (formerly named Hidroeléctrica El Chocón S.A.)	Argentine peso	0.00%	67.67%	67.67%	0.00%	67.67%	67.67%	Subsidiary	Argentina	Electric energy production and sales
Foreign	Hidroinvest S.A.	Argentine peso	41.94%	54.15%	96.09%	0.00%	96.09%	96.09%	Subsidiary	Argentina	Portfolio company
Foreign	Ingendesa do Brasil Ltda.	Real	1.00%	0.00%	1.00%	0.00%	100.00%	100.00%	Subsidiary	Brazil	Project engineering consulting
Foreign	Inversiones Distrilima S.A.	Peruvian Soles	100.00%	0.00%	100.00%	34.99%	50.21%	85.20%	Subsidiary	Peru	Portfolio company
Foreign	Inversora Dock Sud, S.A.	Argentine peso	57.14%	0.00%	57.14%	57.14%	0.00%	57.14%	Subsidiary	Argentina	Portfolio company
Foreign	Inversora Codensa S.A.S.	Colombian peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Colombia	Investment in domestic public energy services
Foreign	Sociedad Portuaria Central Cartagena S.A.	Colombian peso	0.00%	99.85%	99.85%	0.00%	100.00%	100.00%	Subsidiary	Colombia	Investment, construction and maintenance of public or private wharves and ports
Foreign	Southern Cone Power Argentina S.A. (2)	Argentine peso	0.00%	0.00%	0.00%	0.00%	100.00%	100.00%	Subsidiary	Argentina	Portfolio company
Foreign	Transportadora de Energía S.A.	Argentine peso	0.00%	100.00%	100.00%	0.00%	100.00%	100.00%	Subsidiary	Argentina	Electric energy production, transportation and distribution

(1) See Note 2.4.2.

(2) In May 2016, this company was merged with Enel Argentina, with the latter as the surviving company.

(3) In October 1, 2016, Codensa merged with Distribuidora Eléctrica de Cundinamarca S.A.

The accompanying notes are an integral part of these consolidated financial statements.

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APPENDIX 2 CHANGES IN THE SCOPE OF CONSOLIDATION:

This appendix is part of Note 2.4.1 “Changes in the scope of consolidation”.

There were no incorporations into the scope of consolidation as of December 31, 2016 and 2015.

The following companies were eliminated from the scope of consolidation:

Company	% Ownership				% Contro$ Ownership
	December 31, 2016 (*)				December 31, 2015
	Direct	Indirect	Total	Consolidation method	Direct	Indirect	Total	Consolidation Method
Central Eólica Canela S.A.	-	-	-	Full integration	0.00%	75.00%	75.00%	Full integration
Centrales Hidroeléctricas De Aysén S.A.	-	-	-	Full integration	0.00%	51.00%	51.00%	Full integration
Enel Distribución Chile S.A. (formerly named Chilectra S.A.)	-	-	-	Full integration	99.08%	0.01%	99.09%	Full integration
Compañía Eléctrica Tarapacá S.A.	-	-	-	Full integration	3.78%	96.21%	99.99%	Full integration
Empresa Eléctrica de Colina Ltda.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
Empresa Eléctrica Pehuenche S.A.	-	-	-	Full integration	0.00%	92.65%	92.65%	Full integration
Enel Generación Chile S.A. (formerly named Endesa Chile S.A.)	-	-	-	Full integration	59.98%	0.00%	59.98%	Full integration
Inversiones GasAtacama Holding Ltda.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
GasAtacama S.A.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
GasAtacama Chile S.A.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
Gasoducto TalTal S.A.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
Gasoducto Atacama Argentina S.A.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
GNL Norte S.A.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
Servicios Informáticos e Inmobiliarios Ltda.	-	-	-	Full integration	99.00%	1.00%	100.00%	Full integration
Inmobiliaria Manso de Velasco Ltda.	-	-	-	Full integration	99.99%	0.00%	99.99%	Full integration
Luz Andes Ltda.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
Progas S.A.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
Sociedad Agrícola de Cameros Ltda.	-	-	-	Full integration	0.00%	57.50%	57.50%	Full integration
Sociedad Concesionaria Túnel El Melón S.A.	-	-	-	Full integration	0.00%	100.00%	100.00%	Full integration
Transmisora Eléctrica de Quillota Ltda.	-	-	-	Full integration	0.00%	50.00%	50.00%	Full integration
Electrogas S.A.	-	-	-	Equity method	0.00%	42.50%	42.50%	Equity method
GNL Chile S.A.	-	-	-	Equity method	0.00%	33.33%	33.33%	Equity method
GNL Quintero S.A.	-	-	-	Equity method	0.00%	20.00%	20.00%	Equity method
Aysén Transmisión S.A.	-	-	-	Equity method	0.00%	51.00%	51.00%	Equity method
Aysén Energía S.A.	-	-	-	Equity method	0.00%	51.00%	51.00%	Equity method

(*) Beginning on March 1, 2016, all these companies are no longer within the scope of consolidation of the Company.

The accompanying notes are an integral part of these consolidated financial statements.

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APPENDIX 3 ASSOCIATES AND JOINT VENTURES:

This appendix is part of Note 3.h, “Investments accounted for using the equity method”.

Taxpayer ID No. (RUT)	Company	Functional Currency	% Ownership as of 12/31/2016			% Ownership as of 12/31/2015			Relationship	Country	Business Activity
			Direct	Indirect	Total	Direct	Indirect	Total
Foreign	Sacme S.A.	U.S. dollar	0.00%	50.00%	50.00%	0.00%	50.00%	50.00%	Associate	Argentina	Monitoring and Control of Electric System
Foreign	Yacylec S.A.	Argentine peso	22.22%	0.00%	22.22%	22.22%	0.00%	22.22%	Associate	Argentina	Electric energy transportation
Foreign	Distribuidora Eléctrica de Cundinamarca S.A. (1)	Colombian peso	0.00%	0.00%	0.00%	0.00%	49.00%	49.00%	Joint Venture	Colombia	Electric energy distribution and sales
Foreign	Empresa de Energía de Cundinamarca S.A. (1)	Colombian peso	0.00%	0.00%	0.00%	0.00%	49.00%	49.00%	Joint Venture	Colombia	Electric energy distribution and sales
Foreign	Central Termica Manuel Belgrano	Argentine peso	0.00%	25.60%	25.60%	0.00%	25.60%	25.60%	Associate	Argentina	Electric energy distribution and sales
Foreign	Central Térmica San Martin	Argentine peso	0.00%	25.60%	25.60%	0.00%	25.60%	25.60%	Associate	Argentina	Electric energy distribution and sales
Foreign	Central Vuelta Obligado S.A.	Argentine peso	0.00%	40.90%	40.90%	0.00%	40.90%	40.90%	Associate	Argentina	Electric energy distribution and sales

(1) Entities merged with our subsidiary Codensa S.A. on October 1, 2016 (see Note 6).

The accompanying notes are an integral part of these consolidated financial statements.

F-175

APPENDIX 4 ADDITIONAL INFORMATION ON FINANCIAL DEBT:

This appendix is part of Note 18, “Other financial liabilities.” The following tables present the contractual undiscounted cash flows by type of financial debt:

a) Bank borrowings

a. Summary of bank borrowings by currency and maturity

Country	Currency	Nominal Interest Rate	Current			Non-Current						Current			Non-Current
			Maturity		Total Current 12/31/2016	Maturity					Total Non-Current 12/31/2016	Maturity		Total Current 12/31/2015	Maturity					Total Non-Current 12/31/2015
			One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years		One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	Ch$	5.19%	-	-	-	-	-	-	-	-	-	64	-	64	-	-	-	-	-	-
Peru	US$	2.79%	1,084,969	17,778,753	18,863,722	18,196,844	282,401	-	-	-	18,479,245	26,707,131	3,241,137	29,948,268	4,229,306	19,295,795	299,648	-	-	23,824,749
Peru	Soles	5.53%	2,443,335	1,324,941	3,768,276	32,417,120	-	-	-	-	32,417,120	12,864,568	1,001,767	13,866,335	3,285,202	23,309,058	-	-	-	26,594,260
Argentina	US$	13.83%	-	-	-	-	-	-	-	-	-	3,901,216	-	3,901,216	-	-	-	-	-	-
Argentina	Ar$	32.50%	446,499	480,064	926,563	-	-	-	-	-	-	2,290,653	6,194,569	8,485,222	1,162,844	-	-	-	-	1,162,844
Colombia	CP	8.21%	7,038,974	57,472,142	64,511,116	29,953,840	85,277,306	33,979,247	12,675,864	20,269,755	182,156,012	35,832,030	84,128,905	119,960,935	43,831,876	12,832,869	12,194,900	11,556,930	30,842,974	111,259,549
Brazil	US$	3.60%	608,685	1,826,054	2,434,739	28,104,548	51,313,622	82,652	82,652	2,049,705	81,633,179	-	-	-	-	-	-	-	-	-
Brazil	Real	11.56%	32,226,742	77,733,555	109,960,297	96,353,504	80,205,575	38,389,218	25,403,215	7,923,151	248,274,663	12,842,515	24,480,763	37,323,278	42,171,314	37,904,161	33,637,009	-	-	113,712,484
Total			43,849,204	156,615,509	200,464,713	205,025,856	217,078,904	72,451,117	38,161,731	30,242,611	562,960,219	94,438,177	119,047,141	213,485,318	94,680,542	93,341,883	46,131,557	11,556,930	30,842,974	276,553,886

The accompanying notes are an integral part of these consolidated financial statements.

F-176

b. Identification of bank borrowings by company

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Nominal Interest Rate	December 31, 2016									December 31, 2015
								Current			Non-Current						Corriente			No Corriente
								Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
								ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Ampla Energía  S.A.	Brazil	Foreign	Banco do Brazil	Brazil	Real	13.71%	-	-	-	-	-	-	-	-	-	816,511	2,449,533	3,266,044	11,051,818	9,963,136	8,874,455	-	-	29,889,409
Foreign	Ampla Energía  S.A.	Brazil	Foreign	Citibank	Brazil	US$	3.52%	225,576	676,727	902,303	26,572,112	-	-	-	-	26,572,112	-	-	-	-	-	-	-	-	-
Foreign	Ampla Energía  S.A.	Brazil	Foreign	Banco Santander	Brazil	US$	2.85%	362,446	1,087,338	1,449,784	1,449,784	51,230,970	-	-	-	52,680,754	-	-	-	-	-	-	-	-	-
Foreign	Ampla Energía  S.A.	Brazil	Foreign	Bndes	Brazil	Real	11.40%	12,248,128	35,308,054	47,556,182	39,782,488	32,652,150	24,889,420	16,515,051	5,370,142	119,209,251	-	-	-	-	-	-	-	-	-
Foreign	Chinango S.A.C.	Peru	Foreign	Banco de Credito del Peru	Peru	US$	2.56%	297,133	884,446	1,181,579	17,042,784	-	-	-	-	17,042,784	296,974	884,973	1,181,947	1,166,085	18,073,119	-	-	-	19,239,204
Foreign	Chinango S.A.C.	Peru	Foreign	Bank Of Nova Scotia	Peru	US$	3.57%	431,261	1,272,048	1,703,309	-	-	-	-	-	-	468,030	1,384,969	1,852,999	1,802,011	-	-	-	-	1,802,011
Foreign	Chinango S.A.C.	Peru	Foreign	Bank Of Nova Scotia	Peru	US$	3.40%	301,967	891,226	1,193,193	1,154,060	282,401	-	-	-	1,436,461	328,549	971,195	1,299,744	1,261,210	1,222,676	299,648	-	-	2,783,534
Foreign	Enel Cien S.A. (formerly named Cien S.A.)	Brazil	Foreign	Bndes	Brazil	Real	9.54%	361,878	1,046,571	1,408,449	1,304,281	1,200,111	560,992	-	-	3,065,384	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Bank of Tokio-Mitsubishi UFJ	Colombia	CP	8.57%	1,753,928	5,261,785	7,015,713	7,015,713	66,001,423	18,863,047	-	-	91,880,183	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Banco de Bogotá S.A	Colombia	CP	9.08%	738,975	2,106,948	2,845,923	2,113,677	672,955	-	-	-	2,786,632	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	AVVILLAS	Colombia	CP	8.87%	365,797	1,042,715	1,408,512	902,366	210,022	-	-	-	1,112,388	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Banco Popular	Colombia	CP	8.80%	603,245	1,723,856	2,327,101	1,693,935	1,398,939	-	-	-	3,092,874	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	BBVA Colombia SA	Colombia	CP	7.71%	1,570,147	4,507,652	6,077,799	4,235,724	3,858,775	2,838,241	1,255,138	-	12,187,878	-	-	-	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Banco Itaú Brazil	Brazil	Real	15.19%	11,428,725	2,337,521	13,766,246	12,207,899	10,649,551	-	-	-	22,857,450	980,672	2,942,017	3,922,689	12,030,283	10,722,720	9,415,157	-	-	32,168,160
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Brazil	Brazil	Real	14.51%	1,675,020	20,228,894	21,903,914	19,670,554	17,437,194	-	-	-	37,107,748	1,870,908	19,089,213	20,960,121	19,089,213	17,218,305	15,347,397	-	-	51,654,915
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	Real	7.71%	1,271,359	3,688,159	4,959,518	4,623,738	1,103,469	-	-	-	5,727,207	-	-	-	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Banco Santander	Brazil	Real	15.76%	-	-	-	-	-	-	-	-	-	9,174,424	-	9,174,424	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Bndes	Brazil	Real	11.01%	5,241,632	15,124,356	20,365,988	18,764,544	17,163,100	12,938,806	8,888,164	2,553,009	60,307,623	-	-	-	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Brazil	Brazil	US$	4.44%	20,663	61,989	82,652	82,652	82,652	82,652	82,652	2,049,705	2,380,313	-	-	-	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Bank  Nova Scotia	Peru	US$	1.62%	54,608	14,731,033	14,785,641	-	-	-	-	-	-	25,613,578	-	25,613,578	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	6.73%	2,001,688	-	2,001,688	-	-	-	-	-	-	35,470	106,410	141,880	2,091,393	-	-	-	-	2,091,393
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	5.71%	60,905	182,714	243,619	4,220,384	-	-	-	-	4,220,384	63,633	190,899	254,532	254,532	4,409,519	-	-	-	4,664,051
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.01%	37,877	113,631	151,508	3,048,686	-	-	-	-	3,048,686	39,574	118,722	158,296	158,296	3,185,312	-	-	-	3,343,608
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.01%	63,128	189,384	252,512	5,081,144	-	-	-	-	5,081,144	65,973	197,919	263,892	263,892	5,308,880	-	-	-	5,572,772
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.01%	60,602	181,805	242,407	4,877,896	-	-	-	-	4,877,896	63,317	189,952	253,269	253,269	5,096,497	-	-	-	5,349,766
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.01%	63,126	189,379	252,505	5,081,141	-	-	-	-	5,081,141	65,955	197,865	263,820	263,820	5,308,850	-	-	-	5,572,670
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	5.07%	-	-	-	-	-	-	-	-	-	12,530,646	-	12,530,646	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Santander	Peru	Soles	6.20%	156,009	468,028	624,037	10,107,869	-	-	-	-	10,107,869	-	-	-	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Provincia de Buenos Aires	Argentina	Ar$	30.67%	-	-	-	-	-	-	-	-	-	85,423	-	85,423	-	-	-	-	-	-
Foreign	Edesur S.A.	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	37.88%	-	-	-	-	-	-	-	-	-	184,364	277,164	461,528	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA Colombia	Colombia	CP	9.21%	1,105,721	9,845,271	10,950,992	10,319,151	9,687,310	9,055,470	8,423,629	14,951,737	52,437,297	894,845	6,064,899	6,959,744	9,982,170	9,504,920	9,027,670	8,550,419	22,787,755	59,852,934
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Bogota	Colombia	CP	9.24%	394,436	3,504,230	3,898,666	3,673,274	3,447,882	3,222,489	2,997,097	5,318,018	18,658,760	301,348	2,105,951	2,407,299	3,488,668	3,327,949	3,167,230	3,006,511	8,055,219	21,045,577
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	AV VILLAS	Colombia	CP	5.93%	-	-	-	-	-	-	-	-	-	11,145,579		11,145,579	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Citibank Colombia	Colombia	CP	6.01%	-	-	-	-	-	-	-	-	-	5,233,163		5,233,163	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	BBVA Colombia	Colombia	CP	8.61%	-	-	-	-	-	-	-	-	-	438,046	28,712,649	29,150,695	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Bogota	Colombia	CP	6.66%	-	-	-	-	-	-	-	-	-	13,683,505	-	13,683,505	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Crédito del Peru	Colombia	Soles	5.70%	-	-	-	-	-	-	-	-	-	295,055	20,873,617	21,168,672	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Crédito del Peru	Colombia	Soles	5.76%	-	-	-	-	-	-	-	-	-	198,385	13,892,621	14,091,006	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco de Crédito del Peru	Colombia	Soles	5.50%	-	-	-	-	-	-	-	-	-	149,881	10,882,356	11,032,237	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	The Bank Of Tokyo	Colombia	CP	6.90%	506,725	29,479,685	29,986,410	-	-	-	-	-	-	532,271	1,596,812	2,129,083	30,361,038	-	-	-	-	30,361,038
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco Davivienda	Colombia	CP	6.15%	-	-	-	-	-	-	-	-	-	2,959,952		2,959,952	-	-	-	-	-	-
Foreign	Enel Argentina S.A. (formerly named Endesa Argentina S.A.)	Argentina	Foreign	Citibank	Argentina	Ar$	34.00%	-	-	-	-	-	-	-	-	-	29,771	445,358	475,129	-	-	-	-	-	-
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Banco Galicia	Argentina	Ar$	32.00%	115,223	105,975	221,198	-	-	-	-	-	-	214,270	583,114	797,384	276,664	-	-	-	-	276,664
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Banco Itaú Argentina	Argentina	Ar$	34.00%	48,996	55,045	104,041	-	-	-	-	-	-	80,256	225,731	305,987	128,627	-	-	-	-	128,627
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Banco Santander Río	Argentina	Ar$	30.00%	29,706	33,630	63,336	-	-	-	-	-	-	50,253	140,581	190,834	79,542	-	-	-	-	79,542
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Banco Supervielle	Argentina	Ar$	38.00%	47,140	52,943	100,083	-	-	-	-	-	-	81,254	224,941	306,195	125,511	-	-	-	-	125,511
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Citibank	Argentina	Ar$	30.00%	153,048	173,400	326,448	-	-	-	-	-	-	263,796	734,081	997,877	412,453	-	-	-	-	412,453
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Credit Suisse International	Argentina	US$	13.92%	-	-	-	-	-	-	-	-	-	1,214,284		1,214,284	-	-	-	-	-	-
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	ICBC Argentina	Argentina	Ar$	31.00%	52,386	59,071	111,457	-	-	-	-	-	-	89,832	249,669	339,501	140,047	-	-	-	-	140,047
94.271.000-3	Enel Américas S.A.	Chile	97.004.000-5	Banco Santander Chile	Chile	Ch$	6.00%	-	-	-	-	-	-	-	-	-	64		64	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Deutsche Bank	Argentina	US$	12.86%	-	-	-	-	-	-	-	-	-	1,339,210		1,339,210	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Standard Bank	Argentina	US$	12.86%	-	-	-	-	-	-	-	-	-	673,817		673,817	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Itau	Argentina	US$	12.86%	-	-	-	-	-	-	-	-	-	673,905		673,905	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Macro	Argentina	Ar$	38.45%	-	-	-	-	-	-	-	-	-	75,083	1,113,612	1,188,695	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Santander - Sindicado IV	Argentina	Ar$	30.81%	-	-	-	-	-	-	-	-	-	266,203	516,165	782,368	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Itau- Sindicado IV	Argentina	Ar$	30.81%	-	-	-	-	-	-	-	-	-	241,619	464,727	706,346	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Galicia - Sindicado IV	Argentina	Ar$	30.81%	-	-	-	-	-	-	-	-	-	228,411	442,424	670,835	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Hipotecario - Sindicado IV	Argentina	Ar$	30.81%	-	-	-	-	-	-	-	-	-	73,221	144,361	217,582	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Banco Ciudad -Sindicado IV	Argentina	Ar$	30.81%	-	-	-	-	-	-	-	-	-	30,708	59,481	90,189	-	-	-	-	-	-
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	ICBC - Sindicado IV	Argentina	Ar$	30.81%	-	-	-	-	-	-	-	-	-	296,189	573,160	869,349	-	-	-	-	-	-
								43,849,204	156,615,509	200,464,713	205,025,856	217,078,904	72,451,117	38,161,731	30,242,611	562,960,219	94,438,177	119,047,141	213,485,318	94,680,542	93,341,883	46,131,557	11,556,930	30,842,974	276,553,886

The accompanying notes are an integral part of these consolidated financial statements.

F-177

b) Secured and unsecured liabilities

a. Summary of secured and unsecured liabilities by currency and maturity

Country	Currency	Nominal Interest Rate	Current			Non-Current						Current			Non-Current
			Maturity		Total Current 12/31/2016	Maturity					Total Non-Current 12/31/2016			Total Current 12/31/2015	Maturity					Total Non-Current 12/31/2015
			One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years		One to three months	Three to twelve months		One to two years	Two to three years	Three to four years	Four to five years	More than five years
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	5.30%	4,247,885	12,743,655	16,991,540	16,991,541	16,991,541	16,991,541	16,991,541	483,965,282	551,931,446	3,015,734	186,297,709	189,313,443	39,170	39,170	39,170	39,170	843,993	1,000,673
Chile	U.F.	5.75%	515,146	5,106,513	5,621,659	5,497,308	5,365,808	5,226,746	5,079,688	2,482,053	23,651,603	654,291	5,230,040	5,884,331	5,728,780	5,564,286	5,390,333	5,206,378	7,441,327	29,331,104
Peru	US$	6.59%	419,300	1,257,900	1,677,200	7,966,208	6,311,873	7,405,625	426,478	9,282,058	31,392,242	624,775	15,786,095	16,410,870	1,659,369	8,362,538	6,637,571	7,807,914	10,086,341	34,553,733
Peru	Soles	6.27%	11,558,684	31,356,758	42,915,442	14,975,604	56,448,262	37,824,664	29,621,798	195,062,525	333,932,853	13,029,793	18,645,206	31,674,999	33,667,892	12,316,415	55,639,169	36,169,256	166,145,520	303,938,252
Colombia	CP	10.16%	156,226,892	82,632,602	238,859,494	214,085,529	220,071,655	151,457,297	282,023,953	613,860,381	1,481,498,815	55,700,572	67,624,004	123,324,576	206,126,573	182,198,785	143,062,230	109,340,794	709,356,051	1,350,084,433
Brazil	Real	13.50%	7,677,778	123,674,551	131,352,329	108,692,675	51,868,233	-	-	-	160,560,908	10,784,409	97,033,475	107,817,884	116,967,735	94,643,824	44,934,561	-	-	256,546,120
Total			180,645,685	256,771,979	437,417,664	368,208,865	357,057,372	218,905,873	334,143,458	1,304,652,299	2,582,967,867	83,809,574	390,616,529	474,426,103	364,189,519	303,125,018	255,703,034	158,563,512	893,873,232	1,975,454,315

b. Secured and unsecured liabilities by company

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Nominal Interest Rate	December 31, 2016									December 31, 2015
								Current			Non-Current						Current			Non-Current
								Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
								ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 1ª Serie 16	Brazil	Real	14.84%	-	-	-	-	-	-	-	-	-	369,157	11,002,428	11,371,585	-	-	-	-	-	-
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 1ª Serie 17	Brazil	Real	14.57%	373,705	10,633,669	11,007,374	-	-	-	-	-	-	635,501	10,359,267	10,994,768	9,723,766	-	-	-	-	9,723,766
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 1ª Serie 18	Brazil	Real	15.04%	1,157,230	13,088,749	14,245,979	12,703,006	11,160,032	-	-	-	23,863,038	1,011,209	3,033,627	4,044,836	12,571,319	11,223,040	9,874,762	-	-	33,669,121
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 2ª Serie 26	Brazil	Real	11.69%	1,053,376	20,129,548	21,182,924	19,076,172	-	-	-	-	19,076,172	1,632,773	18,770,248	20,403,021	18,225,996	16,048,964	-	-	-	34,274,960
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 2ª Serie 27	Brazil	Real	10.00%	2,109,824	33,064,531	35,174,355	32,361,268	29,548,169	-	-	-	61,909,437	2,737,659	8,212,977	10,950,636	32,485,454	28,835,249	25,185,037	-	-	86,505,740
Foreign	Ampla Energía S.A.	Brazil	Foreign	Bonos 2ª Serie 28	Brazil	Real	15.04%	1,157,230	13,088,749	14,245,979	12,703,006	11,160,032	-	-	-	23,863,038	1,011,209	3,033,627	4,044,836	12,571,319	11,223,040	9,874,762	-	-	33,669,121
Foreign	Codensa	Colombia	Foreign	B102	Colombia	CP	11.10%	89,999,852	-	89,999,852	-	-	-	-	-	-	2,285,586	6,856,759	9,142,345	90,513,112	-	-	-	-	90,513,112
Foreign	Codensa	Colombia	Foreign	B103	Colombia	CP	11.35%	567,977	1,703,931	2,271,908	20,101,422	-	-	-	-	20,101,422	475,081	1,425,243	1,900,324	1,900,324	19,928,937	-	-	-	21,829,261
Foreign	Codensa	Colombia	Foreign	B604	Colombia	CP	10.17%	-	-	-	-	-	-	-	-	-	33,159,237		33,159,237	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Bonos B12-13	Colombia	CP	10.62%	1,314,976	3,944,928	5,259,904	5,259,903	5,259,903	5,259,903	5,259,903	63,690,765	84,730,377	1,060,598	3,181,795	4,242,393	4,242,394	4,242,394	4,242,394	4,242,394	64,429,087	81,398,663
Foreign	Codensa	Colombia	Foreign	Bonos B5-13	Colombia	CP	9.75%	1,147,852	3,443,557	4,591,409	44,695,160	-	-	-	-	44,695,160	907,996	2,723,989	3,631,985	3,631,986	44,267,794	-	-	-	47,899,780
Foreign	Codensa	Colombia	Foreign	Bonos B7-14	Colombia	CP	9.36%	1,110,481	3,331,442	4,441,923	4,441,923	4,441,923	4,441,923	44,562,193	-	57,887,962	881,572	2,644,715	3,526,287	3,526,287	3,526,287	3,526,287	3,526,287	44,335,883	58,441,031
Foreign	Codensa	Colombia	Foreign	Bonos E4-16	Colombia	CP	7.49%	375,682	1,127,047	1,502,729	1,502,730	1,502,730	21,185,250	-	-	24,190,710	-	-	-	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Itaú 1	Brazil	Real	14.74%	-	-	-	-	-	-	-	-	-	325,485	10,211,261	10,536,746	-	-	-	-	-	-
Foreign	Coelce S.A.	Brazil	Foreign	Itaú 2	Brazil	Real	14.68%	1,826,413	33,669,305	35,495,718	31,849,223	-	-	-	-	31,849,223	3,061,416	32,410,040	35,471,456	31,389,881	27,313,531	-	-	-	58,703,412
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.31%	78,312	234,936	313,248	313,247	313,247	313,247	313,247	5,132,554	6,385,542	82,046	246,137	328,183	328,182	328,182	328,182	328,182	5,691,198	7,003,926
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.28%	77,275	231,824	309,099	309,099	5,156,238	-	-	-	5,465,337	82,320	246,959	329,279	329,279	329,279	5,391,004	-	-	6,049,562
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	US$	6.34%	106,619	319,858	426,477	426,478	426,478	426,478	426,478	9,282,058	10,987,970	105,486	316,458	421,944	421,944	421,944	421,944	421,944	10,086,341	11,774,117
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Continental	Peru	US$	7.78%	106,795	320,384	427,179	427,178	5,496,733	-	-	-	5,923,911	105,659	316,978	422,637	422,637	422,637	5,831,097	-	-	6,676,371
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	6.63%	-	-	-	-	-	-	-	-	-	110,163	7,244,456	7,354,619	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	6.00%	-	-	-	-	-	-	-	-	-	99,770	7,297,112	7,396,882	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	5.78%	97,166	291,497	388,663	388,662	388,662	6,979,147	-	-	7,756,471	96,133	288,398	384,531	384,530	384,530	384,530	7,385,970	-	8,539,560
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	6.47%	108,720	326,161	434,881	6,723,890	-	-	-	-	6,723,890	107,564	322,693	430,257	430,258	7,133,427	-	-	-	7,563,685
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	AFP Horizonte	Peru	Soles	7.09%	-	-	-	-	-	-	-	-	-	56,529	3,213,571	3,270,100	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	AFP Integra	Peru	Soles	8.00%	-	-	-	-	-	-	-	-	-	3,768,393	-	3,768,393	-	-	-	-	-	-

The accompanying notes are an integral part of these consolidated financial statements.

F-178

b. Secured and unsecured liabilities by company (continued)

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Nominal Interest Rate	December 31, 2016									December 31, 2015
								Current			Non-Current						Current			Non-Current
								Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
								ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	AFP Integra	Peru	Soles	7.85%	-	-	-	-	-	-	-	-	-	5,732,006	-	5,732,006	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	AFP Prima	Peru	Soles	7.00%	-	-	-	-	-	-	-	-	-	92,940	5,291,865	5,384,805	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	AFP Prima	Peru	Soles	7.30%	110,964	332,892	443,856	443,856	443,856	6,267,020	-	-	7,154,732	116,196	348,588	464,784	464,783	464,783	464,783	6,548,565		7,942,914
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	FCR - Macrofondo	Peru	Soles	5.49%	138,635	415,906	554,541	554,541	554,541	554,541	554,541	10,321,554	12,539,718	145,245	435,735	580,980	580,980	580,980	580,980	580,980	11,366,149	13,690,069
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	FCR - Macrofondo	Peru	Soles	6.91%	70,025	210,074	280,099	280,099	4,004,086	-	-	-	4,284,185	73,305	219,914	293,219	293,219	293,219	4,183,575	-	-	4,770,013
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Interseguro Cia de Seguros	Peru	Soles	6.19%	125,175	375,525	500,700	500,700	500,700	500,700	500,700	8,128,388	10,131,188	131,143	393,429	524,572	524,572	524,572	524,572	524,572	9,017,708	11,115,996
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.97%	151,041	453,123	604,164	604,164	604,164	604,164	604,164	16,245,238	18,661,894	158,242	474,727	632,969	632,969	632,969	632,969	632,969	17,624,247	20,156,123
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.40%	127,780	383,340	511,120	511,120	511,120	511,120	511,120	15,616,779	17,661,259	133,872	401,617	535,489	535,489	535,489	535,489	535,489	16,868,345	19,010,301
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.94%	99,743	299,229	398,972	398,972	398,972	398,972	398,972	9,524,127	11,120,015	104,498	313,495	417,993	417,994	417,994	417,994	417,994	10,373,415	12,045,391
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	4.94%	105,381	6,006,243	6,111,624	-	-	-	-	-	-	110,347	331,041	441,388	6,385,839	-	-	-	-	6,385,839
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.06%	64,752	4,131,833	4,196,585	-	-	-	-	-	-	67,781	203,343	271,124	4,407,670	-	-	-	-	4,407,670
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.64%	167,538	502,615	670,153	670,153	670,153	10,398,629	-	-	11,738,935	175,558	526,675	702,233	702,233	702,233	702,233	10,866,005	-	12,972,704
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	7.15%	128,328	384,984	513,312	513,313	513,313	513,313	513,313	13,867,212	15,920,464	134,479	403,436	537,915	537,915	537,915	537,915	537,915	14,287,204	16,438,864
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.40%	161,335	484,006	645,341	645,342	645,342	10,543,423	-	-	11,834,107	169,060	507,179	676,239	676,238	676,238	676,238	11,017,735	-	13,046,449
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	7.24%	219,643	658,929	878,572	878,571	878,571	878,571	878,571	23,583,303	27,097,587	230,147	690,441	920,588	920,588	920,588	920,588	920,588	24,598,494	28,280,846
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.67%	336,568	1,009,704	1,346,272	1,346,271	1,346,271	1,346,271	20,352,477	-	24,391,290	352,647	1,057,940	1,410,587	1,410,587	1,410,587	1,410,587	1,410,587	21,265,895	26,908,243
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.25%	188,938	566,815	755,753	755,754	755,754	755,754	755,754	13,075,863	16,098,879	197,979	593,936	791,915	791,915	791,915	791,915	791,915	14,457,206	17,624,866
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.76%	290,046	870,138	1,160,184	1,160,184	20,483,812	-	-	-	21,643,996	303,907	911,720	1,215,627	1,215,627	1,215,627	21,403,513	-	-	23,834,767
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.25%	251,898	755,694	1,007,592	1,007,592	1,007,592	1,007,592	1,007,592	18,693,855	22,724,223	263,940	791,820	1,055,760	1,055,760	1,055,760	1,055,760	1,055,760	20,595,659	24,818,699
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	4.76%	117,078	9,986,978	10,104,056	-	-	-	-	-	-	122,692	368,075	490,767	10,557,968	-	-	-	-	10,557,968
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.03%	212,820	638,459	851,279	851,279	14,429,183	-	-	-	15,280,462	224,521	673,563	898,084	898,085	898,085	15,080,872	-	-	16,877,042
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.87%	7,527,572	-	7,527,572	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	7.97%	282,454	847,363	1,129,817	1,129,817	1,129,817	1,129,817	1,129,817	22,123,781	26,643,049	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	6.00%	303,895	911,684	1,215,579	1,215,579	1,215,579	1,215,579	1,215,579	21,828,387	26,690,703	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Rimac Internacional	Peru	Soles	5.91%	221,488	664,464	885,952	885,951	885,951	885,951	885,951	16,921,484	20,465,288	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B09-09	Colombia	CP	11.69%	1,592,724	4,778,171	6,370,895	52,346,354	-	-	-	-	52,346,354	1,318,361	3,955,083	5,273,444	5,273,444	52,249,218	-	-	-	57,522,662
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B10	Colombia	CP	11.57%	1,173,647	3,520,941	4,694,588	4,694,589	36,454,831	-	-	-	41,149,420	966,592	2,899,777	3,866,369	3,866,370	3,866,370	36,715,143	-	-	44,447,883
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B-103	Colombia	CP	10.86%	38,682,841	-	38,682,841	-	-	-	-	-	-	1,116,102	3,348,305	4,464,407	39,054,871	-	-	-	-	39,054,871
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B12	Colombia	CP	11.88%	663,574	1,990,723	2,654,297	2,654,297	2,654,297	2,654,297	21,512,938	-	29,475,829	551,017	1,653,050	2,204,067	2,204,066	2,204,066	2,204,066	2,204,066	21,473,245	30,289,509
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B15	Colombia	CP	11.88%	416,280	1,248,840	1,665,120	1,665,120	1,665,120	1,665,120	1,665,120	15,976,986	22,637,466	344,557	1,033,670	1,378,227	1,378,226	1,378,226	1,378,226	1,378,226	16,871,733	22,384,637
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B6-13	Colombia	CP	10.07%	974,563	2,923,689	3,898,252	3,898,252	36,917,886	-	-	-	40,816,138	258,219	774,658	1,032,877	1,032,878	1,032,878	11,916,341	-	-	13,982,097
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B6-14	Colombia	CP	9.26%	792,223	2,376,670	3,168,893	3,168,894	3,168,894	30,531,802	-	-	36,869,590	518,847	1,556,541	2,075,388	2,075,389	2,075,389	2,075,389	25,654,089	-	31,880,256
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos exterior	Colombia	CP	10.17%	508,806	1,526,419	2,035,225	2,035,226	2,035,226	2,035,226	20,227,805	-	26,333,483	515,898	1,547,693	2,063,591	2,063,591	2,063,591	2,063,591	2,063,591	20,454,156	28,708,520
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos quimbo	Colombia	CP	10.17%	3,656,396	10,969,189	14,625,585	14,625,585	14,625,585	14,625,585	145,361,502	-	189,238,257	3,707,356	11,122,068	14,829,424	14,829,424	14,829,424	14,829,424	14,829,424	146,988,109	206,305,805
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B10	Colombia	CP	9.35%	1,796,781	5,390,343	7,187,124	7,187,124	7,187,124	7,187,124	7,187,124	74,047,801	102,796,297	1,443,011	4,329,034	5,772,045	5,772,045	5,772,045	5,772,045	5,772,045	79,151,390	102,239,570
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B10-14	Colombia	CP	9.66%	1,168,959	3,506,878	4,675,837	4,675,838	4,675,838	4,675,838	4,675,838	52,849,394	71,552,746	921,801	2,765,403	3,687,204	3,687,204	3,687,204	3,687,204	3,687,204	54,611,375	69,360,191
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B12-13	Colombia	CP	10.81%	2,468,410	7,405,229	9,873,639	9,873,639	9,873,639	9,873,639	9,873,639	117,934,252	157,428,808	2,046,250	6,138,749	8,184,999	8,184,998	8,184,998	8,184,998	8,184,998	120,690,336	153,430,328
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B15	Colombia	CP	9.47%	1,211,077	3,633,230	4,844,307	4,844,307	4,844,307	4,844,307	4,844,307	73,639,627	93,016,855	975,333	2,925,998	3,901,331	3,901,331	3,901,331	3,901,331	3,901,331	72,380,849	87,986,173
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B16-14	Colombia	CP	9.98%	1,047,495	3,142,485	4,189,980	4,189,980	4,189,980	4,189,980	4,189,980	71,481,865	88,241,785	832,281	2,496,844	3,329,125	3,329,126	3,329,126	3,329,126	3,329,126	67,969,888	81,286,392
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B6-13	Colombia	CP	10.07%	315,888	947,664	1,263,552	1,263,552	11,966,304	-	-	-	13,229,856	796,647	2,389,940	3,186,587	3,186,587	3,186,587	36,763,745	-	-	43,136,919
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos Quimbo B6-14	Colombia	CP	9.26%	664,870	1,994,611	2,659,481	2,659,482	2,659,482	25,623,699	-	-	30,942,663	618,230	1,854,690	2,472,920	2,472,920	2,472,920	2,472,920	30,568,013	-	37,986,773
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B3-16	Colombia	CP	9.33%	1,409,637	4,228,911	5,638,548	5,638,548	53,284,982	-	-	-	58,923,530	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos B7-16	Colombia	CP	10.51%	1,932,211	5,796,633	7,728,844	7,728,843	7,728,843	7,728,843	7,728,843	73,677,944	104,593,316	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Bonos E7-16	Colombia	CP	7.38%	1,233,690	3,701,071	4,934,761	4,934,761	4,934,761	4,934,761	4,934,761	70,561,747	90,300,791	-	-	-	-	-	-	-	-	-
94.271.000-3	Enel Américas S.A.	Chile	97.004.000-5	Bonos UF 269	Chile	U.F.	5.75%	515,146	5,106,513	5,621,659	5,497,308	5,365,808	5,226,746	5,079,688	2,482,053	23,651,603	654,291	5,230,040	5,884,331	5,728,780	5,564,286	5,390,333	5,206,378	7,441,327	29,331,104
94.271.000-3	Enel Américas S.A.	Chile	97.036.000-K	Yankee bonos Serie Única	E.E.U.U.	US$	4.00%	4,237,834	12,713,501	16,951,335	16,951,335	16,951,335	16,951,335	16,951,335	483,190,453	550,995,793	3,005,941	186,268,331	189,274,272	-	-	-	-	-	-
94.271.000-3	Enel Américas S.A.	Chile	97.036.000-K	Yankee bonos 2026	E.E.U.U.	US$	6.60%	10,051	30,154	40,205	40,206	40,206	40,206	40,206	774,829	935,653	9,793	29,378	39,171	39,170	39,170	39,170	39,170	843,993	1,000,673
				Total				180,645,685	256,771,979	437,417,664	368,208,865	357,057,372	218,905,873	334,143,458	1,304,652,299	2,582,967,867	83,809,574	390,616,529	474,426,103	364,189,519	303,125,018	255,703,034	158,563,512	893,873,232	1,975,454,315

The accompanying notes are an integral part of these consolidated financial statements.

F-179

c) Financial lease obligations

Financial lease obligations by company

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Nominal Interest Rate	December 31, 2016									December 31, 2015
								Current			Non-Current						Current			Non-Current
								Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
								ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Codensa	Colombia	Foreign	Union Temporal Rentacol	Colombia	CP	10.80%	121,091	293,591	414,682	-	-	-	-	-	-	104,950	284,704	389,654	309,519	-	-	-	-	309,519
Foreign	Codensa	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP	10.98%	17,091	49,160	66,251	64,576	52,699	28,380	-	-	145,655	3,894	11,011	14,905	14,462	6,468	-	-	-	20,930
Foreign	Codensa	Colombia	Foreign	Banco Corpbanca	Colombia	CP	7.36%	12,635	24,842	37,477	14,041	-	-	-	-	14,041	24,433	35,543	59,976	25,939	13,636	-	-	-	39,575
Foreign	Codensa	Colombia	Foreign	Transportes Especializados JR	Colombia	CP	9.48%	3,305	9,611	12,916	13,768	9,712	-	-	-	23,480	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Consorcio Empresarial	Colombia	CP	7.08%	72,980	209,948	282,928	207,290	-	-	-	-	207,290	-	-	-	-	-	-	-	-	-
Foreign	Codensa	Colombia	Foreign	Equirent S.A.	Colombia	CP	9.54%	8,223	23,938	32,161	35,284	32,917	20,630	-	-	88,831	-	-	-	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco de Interbank	Peru	Soles	5.29%	-	-	-	-	-	-	-	-	-	111,240	-	111,240	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.98%	-	-	-	-	-	-	-	-	-	88,396	181,920	270,316	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.00%	-	-	-	-	-	-	-	-	-	81,772	245,252	327,024	-	-	-	-	-	-
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	6.00%	-	-	-	-	-	-	-	-	-	77,478	232,058	309,536	12,127	-	-	-	-	12,127
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.98%	33,408	-	33,408	-	-	-	-	-	-	68,777	205,694	274,471	22,795	-	-	-	-	22,795
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Continental	Peru	Soles	5.60%	285,899	854,297	1,140,196	567,670	-	-	-	-	567,670	948	2,845	3,793	70,687	-	-	-	-	70,687
Foreign	Enel Distribución Peru S.A. (formerly named Edelnor S.A.A.)	Peru	Foreign	Banco Santander Peru	Peru	Soles	5.13%	163,428	488,999	652,427	162,562	-	-	-	-	162,562	174,389	519,118	693,507	682,380	-	-	-	-	682,380
Foreign	Enel Generación Piura S.A. (formerly named Empresa Eléctrica Piura)	Peru	Foreign	Banco de Crédito	Peru	US$	5.80%	1,736,535	5,098,471	6,835,006	6,538,651	6,242,297	13,932,443	-	-	26,713,391	1,905,026	5,600,924	7,505,950	7,201,538	6,897,126	6,592,714	14,774,124	-	35,465,502
Foreign	Enel Generación Piura S.A. (formerly named Empresa Eléctrica Piura)	Peru	Foreign	Banco Scotiabank	Peru	US$	3.75%	261,887	4,229,971	4,491,858	5,456,640	5,247,130	5,037,621	4,828,111	1,174,292	21,743,794	-	-	-	-	-	-	-	-	-
Foreign	Enel Generación Piura S.A. (formerly named Empresa Eléctrica Piura)	Peru	Foreign	Banco de Crédito	Peru	Soles	5.70%	595,129	1,747,214	2,342,343	2,240,547	2,138,751	4,771,771	-	-	9,151,069	649,814	1,909,231	2,559,045	2,451,818	2,344,592	2,237,365	4,986,674	-	12,020,449
Foreign	Enel Generación Piura S.A. (formerly named Empresa Eléctrica Piura)	Peru	Foreign	Banco de Crédito	Peru	US$	3.63%	15,670	135,913	151,583	509,675	411,020	202,373	-	-	1,123,068	-	-	-	-	-	-	-	-	-
Foreign	Enel Generación Peru S.A. (formerly named Edegel S.A.A.)	Peru	Foreign	Banco Scotiabank	Peru	US$	2.75%	14,760,419	-	14,760,419	-	-	-	-	-	-	2,584,782	7,682,823	10,267,605	15,644,049	-	-	-	-	15,644,049
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Transportes Especializados JR	Colombia	CP	11.69%	99,842	280,862	380,704	376,687	243,246	-	-	-	619,933	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Consorcio Empresarial	Colombia	CP	7.08%	2,803	7,913	10,716	7,305	-	-	-	-	7,305	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Mareauto Colombia SAS	Colombia	CP	10.98%	7,844	22,335	30,179	30,263	26,457	13,676	-	-	70,396	-	-	-	-	-	-	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Banco Corpbanca	Colombia	CP	8.40%	6,459	17,970	24,429	19,242	-	-	-	-	19,242	7,331	21,099	28,430	27,912	23,306	-	-	-	51,218
Foreign	Emgesa S.A. E.S.P.	Colombia	Foreign	Equirent S.A.	Colombia	CP	7.70%	59,170	167,939	227,109	207,919	166,829	9,671	-	-	384,419	6,977	20,183	27,160	27,731	20,095	-	-	-	47,826
			Total					18,263,818	13,662,974	31,926,792	16,452,120	14,571,058	24,016,565	4,828,111	1,174,292	61,042,146	5,890,207	16,952,405	22,842,612	26,490,957	9,305,223	8,830,079	19,760,798	-	64,387,057

d) Other liabilities

Other liabilities by company

Taxpayer ID No. (RUT)	Company	Country	Taxpayer ID No. (RUT)	Financial Institution	Country	Currency	Nominal Interest Rate	December 31, 2016									December 31, 2015
								Current			Non-Current						Current			Non-Current
								Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current	Less than 90 days	More than 90 days	Total Current	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non-Current
								ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Ampla Energía  S.A.	Brazil	Foreign	BNDES	Brazil	Real	9.17%	-	-	-	-	-	-	-	-	-	7,170,765	22,702,647	29,873,412	29,555,949	23,816,520	18,573,479	12,754,861	8,800,388	93,501,197
Foreign	Enel Cien S.A. (formerly named Cien S.A.)	Brazil	Foreign	Bndes	Brazil	Real	8.33%	-	-	-	-	-	-	-	-	-	298,586	868,484	1,167,070	1,094,340	1,021,609	948,878	447,165	-	3,511,992
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Nordeste	Brazil	Real	7.85%	-	-	-	-	-	-	-	-	-	1,200,204	3,489,229	4,689,433	4,392,407	4,095,381	977,435	-	-	9,465,223
Foreign	Coelce S.A.	Brazil	Foreign	Eletrobras	Brazil	Real	6.08%	540,385	1,580,668	2,121,053	1,900,904	1,679,735	1,383,840	981,885	813,159	6,759,523	693,523	1,569,329	2,262,852	1,878,520	1,681,608	1,485,719	1,223,656	1,609,492	7,878,995
Foreign	Coelce S.A.	Brazil	Foreign	BNDES	Brazil	Real	10.43%	-	-	-	-	-	-	-	-	-	2,314,061	7,646,652	9,960,713	10,148,604	9,382,994	8,617,385	5,533,315	3,928,496	37,610,794
Foreign	Coelce S.A.	Brazil	Foreign	Banco do Brasil	Brazil	US$	52.56%	-	-	-	-	-	-	-	-	-	20,770	62,310	83,080	83,080	83,079	83,080	83,080	2,247,602	2,579,921
Foreign	Enel Generación Costanera S.A. (formerly named Central Costanera S.A.)	Argentina	Foreign	Mitsubishi (secured debt)	Argentina	US$	0.25%	-	2,128,962	2,128,962	2,119,963	2,119,963	2,119,963	2,119,963	25,434,497	33,914,349	590,129	1,768,176	2,358,305	5,810,613	1,792,235	1,883,493	1,937,302	23,273,695	34,697,338
Foreign	Enel Generación El Chocón S.A. (formerly named H. El Chocón S.A.)	Argentina	Foreign	Other	Argentina	Ar$	28.78%	-	-	-	-	-	-	-	-	-	2,347,678	14,015,924	16,363,602	4,358,417	681,224	-	-	-	5,039,641
Foreign	Hidroinvest S.A.	Argentina	Foreign	Other	Argentina	US$	2.53%	184,690	-	184,690	-	-	-	-	-	-	898	196,109	197,007	-	-	-	-	-	-
			Totales					725,075	3,709,630	4,434,705	4,020,867	3,799,698	3,503,803	3,101,848	26,247,656	40,673,872	14,636,614	52,318,860	66,955,474	57,321,930	42,554,650	32,569,469	21,979,379	39,859,673	194,285,101

The accompanying notes are an integral part of these consolidated financial statements.

F-180

APPENDIX 5 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY:

This appendix forms an integral part of these consolidated financial statatemens.

The detail of assets and liabilities denominated in foreign currencies is the following:

ASSETS		Foreign Currency	Functional Currency	12-31-2016	12-31-2015
				ThCh$	ThCh$
	Cash and cash equivalents	U.S. dollar	Chilean peso	342,409,661	6,606,837
		U.S. dollar	Colombian peso	878,967	195,597
		U.S. dollar	Peruvian soles	101,615,471	14,024,599
		U.S. dollar	Argentine peso	2,258,856	1,297,448
TOTAL CURRENT ASSETS				447,162,955	22,124,481

			12-31-2016									12-31-2015
			Current Liabilities			Non-Current Liabilities						Current Liabilities			Non-Current Liabilities
LIABILITIES	Foreign Currency	Functional Currency	Less than 90 days	91 days to 1 year	Total	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total	Less than 90 days	91 days to 1 year	Total	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total
			ThCh$	ThCh$	Current	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	Non-Current	ThCh$	ThCh$	Current						Non-Current
															ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Other current financial liabilities	U.S. dollar	Chilean peso	4,247,885	12,743,655	16,991,540	16,991,541	16,991,541	16,991,541	16,991,541	483,965,282	551,931,446	3,015,734	186,297,709	189,313,443	39,170	39,170	39,170	39,170	843,993	1,000,673
	U.S. dollar	Brazilian Real	608,685	1,826,054	2,434,739	28,104,548	51,313,622	82,652	82,652	2,049,705	81,633,179	20,770	62,310	83,080	83,080	83,079	83,080	83,080	2,247,602	2,579,921
	U.S. dollar	Peruvian Soles	18,278,780	28,501,008	46,779,788	38,668,018	18,494,721	26,578,062	5,254,589	10,456,350	99,451,740	31,821,714	32,310,979	64,132,693	28,734,262	34,555,459	13,529,933	22,582,038	10,086,341	109,488,033
	U.S. dollar	Argentine peso	184,690	2,128,962	2,313,652	2,119,963	2,119,963	2,119,963	2,119,963	25,434,497	33,914,349	4,492,243	1,964,285	6,456,528	5,810,613	1,792,235	1,883,493	1,937,302	23,273,695	34,697,338
TOTAL LIABILITIES			23,320,040	45,199,679	68,519,719	85,884,070	88,919,847	45,772,218	24,448,745	521,905,834	766,930,714	39,350,461	220,635,283	259,985,744	34,667,125	36,469,943	15,535,676	24,641,590	36,451,631	147,765,965

The accompanying notes are an integral part of these consolidated financial statements.

F-181

APPENDIX 6 ADDITIONAL INFORMATION OFFICIAL BULLETIN No. 715 OF FEBRUARY 3, 2012:

This appendix forms an integral part of the Group’s financial statements.

a) Portfolio stratification

- Trade and other receivables by time in arrears:

Trade and other current receivables	12-31-2016
	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 -180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	Total Current	Total Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, gross	612,692,552	114,409,279	41,374,075	17,311,962	16,413,107	14,084,028	13,110,063	6,415,162	5,684,730	157,931,484	999,426,442	77,366,903
Impairment provision	(2,428,585)	(10,092,511)	(1,480,139)	(1,157,646)	(7,559,830)	(8,685,245)	(8,275,017)	(4,156,072)	(3,212,876)	(129,301,956)	(176,349,877)	(13,848,917)
Other receivables, gross	210,005,702	-	-	-	-	-	-	-	-	-	210,005,702	296,129,610
Impairment provision	(2,863,040)	-	-	-	-	-	-	-	-	-	(2,863,040)	-
Total	817,406,629	104,316,768	39,893,936	16,154,316	8,853,277	5,398,783	4,835,046	2,259,090	2,471,854	28,629,528	1,030,219,227	359,647,596
Trade and other current receivables	12-31-2015
	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 -180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	Total Current	Total Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, gross	577,040,344	69,749,887	36,722,157	15,687,116	20,749,032	12,624,597	25,381,047	10,410,324	9,076,689	82,254,409	859,695,602	82,274,666
Impairment provision	(1,402,962)	(682,398)	(1,571,631)	(2,009,596)	(5,939,987)	(7,094,068)	(19,937,434)	(6,841,473)	(7,231,279)	(52,413,506)	(105,124,334)	-
Other receivables, gross	334,685,900	-	-	-	-	-	-	-	-	-	334,685,900	316,421,198
Impairment provision	(1,125,601)	-	-	-	-	-	-	-	-	-	(1,125,601)	-
Total	909,197,681	69,067,489	35,150,526	13,677,520	14,809,045	5,530,529	5,443,613	3,568,851	1,845,410	29,840,903	1,088,131,567	398,695,864

- By type of portfolio:

Time in Arrears	12-31-2016						12-31-2015
	Non-renegotiated portfolio		Renegotiated portfolio		Total Gross Portfolio		Non-renegotiated portfolio		Renegotiated portfolio		Total Gross Portfolio
	Number of customers	Gross amount	Number of customers	Gross amount	Number of customers	Gross Amount	Number of customers	Gross amount	Number of customers	Gross amount	Number of customers	Gross Amount
		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$
Up-to-date	10,715,965	647,724,479	166,329	42,334,976	10,882,294	690,059,455	9,496,241	629,928,769	195,019	29,386,241	9,691,260	659,315,010
1 to 30 days	2,751,759	108,850,914	88,131	5,558,365	2,839,890	114,409,279	2,104,270	65,980,622	80,275	3,769,265	2,184,545	69,749,887
31 to 60 days	469,136	37,165,591	14,112	4,208,484	483,248	41,374,075	285,256	34,798,871	6,727	1,923,286	291,983	36,722,157
61 to 90 days	220,322	13,885,175	9,659	3,426,787	229,981	17,311,962	77,855	14,036,045	7,552	1,651,071	85,407	15,687,116
91 to 120 days	148,926	13,453,789	7,085	2,959,318	156,011	16,413,107	177,160	19,282,854	5,840	1,466,178	183,000	20,749,032
121 to 150 days	120,143	11,724,815	6,750	2,359,213	126,893	14,084,028	172,778	11,272,010	6,289	1,352,587	179,067	12,624,597
151 to 180 days	112,314	11,066,895	6,248	2,043,168	118,562	13,110,063	111,678	24,222,662	6,415	1,158,385	118,093	25,381,047
181 to 210 days	75,001	4,562,525	5,098	1,852,637	80,099	6,415,162	94,221	9,312,808	4,390	1,097,516	98,611	10,410,324
211 to 250 days	64,955	3,940,491	3,840	1,744,239	68,795	5,684,730	55,382	8,049,056	4,688	1,027,633	60,070	9,076,689
More than 251 days	185,801	149,080,281	41,014	8,851,203	226,815	157,931,484	618,700	78,781,681	8,092	3,472,728	626,792	82,254,409
Total	14,864,322	1,001,454,955	348,266	75,338,390	15,212,588	1,076,793,345	13,193,541	895,665,378	325,287	46,304,890	13,518,828	941,970,268

The accompanying notes are an integral part of these consolidated financial statements.

F-182

b) Portfolio in default and in legal collection process

Portfolio in Default and in Legal Collection Process	Balance as of		Balance as of
	12-31-2016		12-31-2015
	Number of customers	Amount	Number of customers	Amount
		ThCh$		ThCh$
Notes receivable in default	1,876,256	26,348,864	1,872,073	23,354,556
Notes receivable in legal collection process  (*)	5,309	17,230,672	4,219	16,044,580
Total	1,881,565	43,579,536	1,876,292	39,399,136

(*) Legal collections are included in the portfolio in arrears.

c) Provisions and write-offs

Provisions and write-offs	Balance as of
	12-31-2016	12-31-2015
	ThCh$	ThCh$
Provision for non-renegotiated portfolio	67,307,619	25,846,624
Provision for renegotiated portfolio	11,027,648	6,081,295
Write-offs	-	(23,480,578)
Recoveries	10,416,267	14,962,098
Total	88,751,534	23,409,439

d) Number and amount of operations

Number and Amount of Transactions	Balance as of
	12-31-2016		12-31-2015
	Total detail by type of transaction Last Quarter	Total detail by type of operation Year-to-date	Total detail by type of operation Last Quarter	Total detail by type of operation Year-to-date
	ThCh$	ThCh$	ThCh$	ThCh$
Impairment provision and recoveries:
Number of transactions	4,060,885	10,198,839	199,988	557,364
Amount of the transactions	45,257,339	88,751,534	11,043,157	46,890,017

The accompanying notes are an integral part of these consolidated financial statements.

F-183

APPENDIX 6.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:

This appendix forms an integral part of the Group’s financial statements.

a) Portfolio stratification

- Trade receivables by time in arrears:

Trade receivables	12-31-2016
	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, Generation and Transmission	163,423,071	12,052,236	3,184,081	1,670,503	2,647,827	1,852,752	1,455,697	669,108	226,801	9,947,084	57,294,597	254,423,757	34,797,069
- Large Clients	61,981,503	11,672,600	2,348,156	191,723	88,862	86,765	195,575	1,653	167,593	9,491,121	564,890	86,790,441	-
- Institutional Clients	67,089,184	-	-	-	-	-	-	-	-	-	-	67,089,184	34,786,871
- Other	34,352,384	379,636	835,925	1,478,780	2,558,965	1,765,987	1,260,122	667,455	59,208	455,963	56,729,707	100,544,132	10,198
Impairment provision	(1,979,501)	(7,697,800)	(1,577)	(13,052)	-	(131,117)	-	(1,653)	-	(4,524,213)	(50,083,809)	(64,432,722)	-
Unbilled services	65,179,838	-	-	-	-	-	-	-	-	-	-	65,179,838	-
Billed services	98,243,233	12,052,236	3,184,081	1,670,503	2,647,827	1,852,752	1,455,697	669,108	226,801	9,947,084	57,294,597	189,243,919	34,797,069
Trade receivables, Distribution	449,269,481	102,357,043	38,189,994	15,641,459	13,765,280	12,231,276	11,654,366	5,746,054	5,457,929	23,645,724	67,044,079	745,002,685	42,569,834
- Mass-market Clients	295,417,471	74,555,391	25,096,876	9,368,311	9,116,335	7,714,907	7,389,601	3,026,774	2,155,251	18,930,141	24,078,813	476,849,871	17,927,760
- Large Clients	103,254,528	11,481,488	5,582,550	2,017,138	1,778,433	1,317,309	1,528,575	1,089,278	1,438,281	3,073,285	26,004,387	158,565,252	6,571,345
- Institutional Clients	50,597,482	16,320,164	7,510,568	4,256,010	2,870,512	3,199,060	2,736,190	1,630,002	1,864,397	1,642,298	16,960,879	109,587,562	18,070,729
Impairment provision	(449,084)	(2,394,711)	(1,478,562)	(1,144,594)	(7,559,830)	(8,554,128)	(8,275,017)	(4,154,419)	(3,212,876)	(16,432,907)	(58,261,027)	(111,917,155)	(13,848,917)
Unbilled services	218,481,746	-	-	-	-	-	-	-	-	-	-	218,481,746	-
Billed services	230,787,735	102,357,043	38,189,994	15,641,459	13,765,280	12,231,276	11,654,366	5,746,054	5,457,929	23,645,724	67,044,079	526,520,939	42,569,834
Total trade receivables, gross	612,692,552	114,409,279	41,374,075	17,311,962	16,413,107	14,084,028	13,110,063	6,415,162	5,684,730	33,592,808	124,338,676	999,426,442	77,366,903
Total impaiment provision	(2,428,585)	(10,092,511)	(1,480,139)	(1,157,646)	(7,559,830)	(8,685,245)	(8,275,017)	(4,156,072)	(3,212,876)	(20,957,120)	(108,344,836)	(176,349,877)	(13,848,917)
Total trade receivables, net	610,263,967	104,316,768	39,893,936	16,154,316	8,853,277	5,398,783	4,835,046	2,259,090	2,471,854	12,635,688	15,993,840	823,076,565	63,517,986

Since not all of our commercial databases in our Group’s different subsidiaries distinguish whether the final electricity service consumer is a natural or legal person, the main management segmentation used by all the subsidiaries to monitor and follow up on trade receivables is the following:

  - Mass-market clients

  - Large clients

  - Institutional clients

The accompanying notes are an integral part of these consolidated financial statements.

F-184

Trade receivables	12-31-2015
	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, Generation and Transmission	214,520,868	10,315,795	3,889,661	3,959,399	3,758,589	3,671,364	3,869,173	5,219,854	118,598	47,438,345	-	296,761,646	55,582,276
- Large Clients	105,350,555	9,422,903	3,835,624	3,804,996	3,734,126	3,641,098	3,550,857	5,192,924	75,322	4,367,646	-	142,976,051	-
- Institutional Clients	76,797,290	-	-	-	-	-	-	-	-	-	-	76,797,290	52,371,150
- Other	32,373,023	892,892	54,037	154,403	24,463	30,266	318,316	26,930	43,276	43,070,699	-	76,988,305	3,211,126
Impairment provision	(212,623)	-	-	(363,070)	-	-	(415,609)	(2,735,412)	-	(45,093,112)	-	(48,819,826)	-
Unbilled services	89,723,981	-	-	-	-	-	-	-	-	-	-	89,723,981	32,993,708
Billed services	124,796,887	10,315,795	3,889,661	3,959,399	3,758,589	3,671,364	3,869,173	5,219,854	118,598	47,438,345	-	207,037,665	22,588,568
Trade receivables, Distribution	362,519,476	59,434,092	32,832,496	11,727,717	16,990,443	8,953,233	21,511,874	5,190,470	8,958,091	34,816,064	-	562,933,956	26,692,390
- Mass-market Clients	217,119,041	36,222,800	21,046,214	7,845,767	5,350,487	5,742,028	18,419,905	2,598,396	6,157,123	10,208,043	-	330,709,804	13,043,874
- Large Clients	99,833,365	12,867,396	6,598,117	1,338,886	1,095,541	996,107	1,253,697	767,947	850,748	21,559,120	-	147,160,924	3,424,933
- Institutional Clients	45,567,070	10,343,896	5,188,165	2,543,064	10,544,415	2,215,098	1,838,272	1,824,127	1,950,220	3,048,901	-	85,063,228	10,223,583
Impairment provision	(1,190,339)	(682,398)	(1,571,631)	(1,646,526)	(5,939,987)	(7,094,068)	(19,521,825)	(4,106,061)	(7,231,279)	(7,320,394)	-	(56,304,508)	-
Unbilled services	173,794,483	-	-	-	-	-	-	-	-	-	-	173,794,483	-
Billed services	188,724,993	59,434,092	32,832,496	11,727,717	16,990,443	8,953,233	21,511,874	5,190,470	8,958,091	34,816,064	-	389,139,473	26,692,390
Total trade receivables, gross	577,040,344	69,749,887	36,722,157	15,687,116	20,749,032	12,624,597	25,381,047	10,410,324	9,076,689	82,254,409	-	859,695,602	82,274,666
Total impaiment provision	(1,402,962)	(682,398)	(1,571,631)	(2,009,596)	(5,939,987)	(7,094,068)	(19,937,434)	(6,841,473)	(7,231,279)	(52,413,506)	-	(105,124,334)	-
Total trade receivables, net	575,637,382	69,067,489	35,150,526	13,677,520	14,809,045	5,530,529	5,443,613	3,568,851	1,845,410	29,840,903	-	754,571,268	82,274,666

The accompanying notes are an integral part of these consolidated financial statements.

F-185

- By type of portfolio:

Type of Portfolio	12-31-2016
	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	157,599,788	12,020,281	3,160,059	1,659,900	2,624,191	1,812,247	1,414,288	653,432	209,251	66,351,275	-	247,504,712	34,797,069
- Large Clients	61,981,503	11,672,600	2,348,156	191,724	88,863	86,766	195,575	1,654	167,593	10,056,012	-	86,790,446	-
- Institutional Clients	67,089,184	-	-	-	-	-	-	-	-	-	-	67,089,184	34,786,871
- Other	28,529,101	347,681	811,903	1,468,176	2,535,328	1,725,481	1,218,713	651,778	41,658	56,295,263	-	93,625,082	10,198
Renegotiated portfolio	5,823,283	31,955	24,022	10,603	23,636	40,505	41,409	15,676	17,550	890,406	-	6,919,045	-
- Large Clients	-	-	-	-	-	-	-	-	-	-	-	-	-
- Institutional Clients	-	-	-	-	-	-	-	-	-	-	-	-	-
- Other	5,823,283	31,955	24,022	10,603	23,636	40,505	41,409	15,676	17,550	890,406	-	6,919,045	-
DISTRIBUTION
Non-renegotiated portfolio	444,417,873	96,830,633	34,005,532	12,225,275	10,829,598	9,912,568	9,652,607	3,909,093	3,731,240	82,729,006	-	708,243,425	10,909,749
- Mass-market Clients	291,576,675	71,602,635	22,727,593	7,712,664	7,846,740	6,705,936	6,537,114	2,339,771	1,556,748	39,930,189	-	458,536,065	2,176,467
- Large Clients	102,779,132	10,541,859	5,002,012	1,441,639	1,268,806	1,161,497	1,421,501	980,632	1,336,218	28,510,457	-	154,443,753	1,393,034
- Institutional Clients	50,062,066	14,686,139	6,275,927	3,070,972	1,714,052	2,045,135	1,693,992	588,690	838,274	14,288,360	-	95,263,607	7,340,248
Renegotiated portfolio	4,851,608	5,526,410	4,184,462	3,416,184	2,935,682	2,318,708	2,001,759	1,836,961	1,726,689	7,960,797	-	36,759,260	31,660,085
- Mass-market Clients	3,840,796	2,952,755	2,369,283	1,655,648	1,269,595	1,008,970	852,487	687,004	598,503	3,078,765	-	18,313,806	15,751,292
- Large Clients	475,396	939,630	580,538	575,498	509,627	155,813	107,074	108,645	102,063	567,215	-	4,121,499	5,178,312
- Institutional Clients	535,416	1,634,025	1,234,641	1,185,038	1,156,460	1,153,925	1,042,198	1,041,312	1,026,123	4,314,817	-	14,323,955	10,730,481
Total gross portfolio	612,692,552	114,409,279	41,374,075	17,311,962	16,413,107	14,084,028	13,110,063	6,415,162	5,684,730	157,931,484	-	999,426,442	77,366,903
Type of Portfolio	12-31-2015
	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non-Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	209,710,717	10,292,925	3,835,624	3,934,142	3,734,126	3,641,098	3,839,625	5,192,924	75,322	47,048,299	-	291,304,802	-
- Large Clients	105,350,555	9,422,903	3,835,624	3,804,997	3,734,126	3,641,098	3,550,857	5,192,924	75,322	4,367,645	-	142,976,051	-
- Institutional Clients	76,797,290	-	-	-	-	-	-	-	-	-	-	76,797,290	-
- Other	27,562,872	870,022	-	129,145	-	-	288,768	-	-	42,680,654	-	71,531,461	-
Renegotiated portfolio	4,810,151	22,870	54,037	25,257	24,463	30,266	29,548	26,930	43,276	390,045	-	5,456,843	-
- Large Clients	-	-	-	-	-	-	-	-	-	-	-	-	-
- Institutional Clients	-	-	-	-	-	-	-	-	-	-	-	-	-
- Other	4,810,151	22,870	54,037	25,257	24,463	30,266	29,548	26,930	43,276	390,045	-	5,456,843	-
DISTRIBUTION
Non-renegotiated portfolio	360,318,915	55,687,697	30,963,247	10,101,903	15,548,728	7,630,912	20,383,037	4,119,884	7,973,734	31,733,382	-	544,461,439	-
- Mass-market Clients	215,638,939	34,316,549	19,859,514	6,818,125	4,452,336	4,953,953	17,774,987	2,008,723	5,629,594	8,660,803	-	320,113,523	-
- Large Clients	99,340,127	11,546,722	6,337,137	1,122,596	936,511	831,176	1,130,633	643,942	736,404	4,107,633	-	126,732,881	-
- Institutional Clients	45,339,849	9,824,426	4,766,596	2,161,182	10,159,881	1,845,783	1,477,417	1,467,219	1,607,736	18,964,946	-	97,615,035	-
Renegotiated portfolio	2,200,561	3,746,395	1,869,249	1,625,814	1,441,715	1,322,321	1,128,837	1,070,586	984,357	3,082,683	-	18,472,518	-
- Mass-market Clients	1,480,102	1,906,252	1,186,699	1,027,641	898,152	788,075	644,917	589,672	527,529	1,547,241	-	10,596,280	-
- Large Clients	493,237	1,320,673	260,980	216,290	159,030	164,931	123,064	124,005	114,344	428,743	-	3,405,297	-
- Institutional Clients	227,222	519,470	421,570	381,883	384,533	369,315	360,856	356,909	342,484	1,106,699	-	4,470,941	-
Total gross porftolio	577,040,344	69,749,887	36,722,157	15,687,116	20,749,032	12,624,597	25,381,047	10,410,324	9,076,689	82,254,409	-	859,695,602	-

The accompanying notes are an integral part of these consolidated financial statements.

F-186

APPENDIX 6.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY:

This appendix forms an integral part of the Group’s financial statements.

	COLOMBIA				PERU				ARGENTINA				BRAZIL				TOTAL
	12-31-2016		12-31-2015		12-31-2016		12-31-2015		12-31-2016		12-31-2015		12-31-2016		12-31-2015		12-31-2016		12-31-2015
BALANCE	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls
Current accounts receivable from related parties	-	-	312,398	231,744	-	-	-	-	-	-	-	-	269,050	6,872	-	5,967	269,050	6,872	312,398	237,711
Trade and other current receivables	75,674,474	6,265,931	91,292,198	3,767,410	21,077,200	5,157,324	39,545,565	5,091,255	59,962,061	44,671	26,291,133	114,662	115,033,802	6,218,708	95,783,612	4,867,959	271,747,537	17,686,634	252,912,508	13,841,286
Total Asset Estimate	75,674,474	6,265,931	91,604,596	3,999,154	21,077,200	5,157,324	39,545,565	5,091,255	59,962,061	44,671	26,291,133	114,662	115,302,852	6,225,580	95,783,612	4,873,926	272,016,587	17,693,506	253,224,906	14,078,997
Current accounts payable to related parties	-	-	43,386	85,780	-	-	-	-	-	-	-	-	-	-	1,107,814	1,107,814	-	-	1,151,200	1,193,594
Trade and other current payables	27,714,500	5,362,685	21,741,708	5,032,612	4,661,902	4,485,624	25,029,210	4,373,789	22,840,714	-	8,559,240	-	119,226,938	5,057,207	167,569,844	3,833,787	174,444,054	14,905,516	222,900,002	13,240,188
Total Liability Estimate	27,714,500	5,362,685	21,785,094	5,118,392	4,661,902	4,485,624	25,029,210	4,373,789	22,840,714	-	8,559,240	-	119,226,938	5,057,207	168,677,658	4,941,601	174,444,054	14,905,516	224,051,202	14,433,782

	COLOMBIA						PERU						ARGENTINA						BRAZIL						TOTAL
INCOME STATEMENT	12-31-2016		12-31-2015		12-31-2014		12-31-2016		12-31-2015		12-31-2014		12-31-2016		12-31-2015		12-31-2014		12-31-2016		12-31-2015		12-31-2014		12-31-2016		12-31-2015		12-31-2014
	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls	Energy and capacity	Tolls
Energy sales	75,411,842	6,244,185	91,614,430	3,782,034	94,439,616	4,137,051	21,207,991	5,189,327	39,027,533	5,024,561	34,481,991	3,341,292	65,936,012	48,610	24,469,681	148,113	37,120,676	310,919	108,909,847	5,947,512	104,917,610	5,394,125	89,394,426	6,268,177	271,465,692	17,429,634	260,029,254	14,348,833	255,436,709	14,057,439
Energy purchases	27,618,316	5,344,074	20,447,041	5,223,843	25,631,699	9,889,413	4,687,775	4,505,343	24,701,337	4,316,494	19,958,532	3,478,388	24,854,838	-	10,541,703	-	13,839,215	441,931	115,091,736	4,776,808	184,762,886	4,199,379	179,556,986	6,463,979	172,252,665	14,626,225	240,452,967	13,739,716	238,986,432	20,273,711

The accompanying notes are an integral part of these consolidated financial statements.

F-187

APPENDIX 7 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS:

This appendix forms an integral part of the Group’s financial statements.

Suppliers with Payments Up-to-Date	Balance as of				Balance as of
	12-31-2016				12-31-2015
	Goods	Services	Other	Total	Goods	Services	Other	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Up to 30 days	-	107,497,513	154,965,138	262,462,651	-	107,441,015	179,688,300	287,129,315
From 31 to 60 days	-	12,930,444	23,010,172	35,940,616	-	13,041,611	16,446,525	29,488,136
From 61 to 90 days	-	-	1,215,148	1,215,148	-	-	-	-
From 91 to 120 days	-	-	341,995	341,995	-	-	-	-
From 121 to 365 days	-	-	6,051,633	6,051,633	-	-	-	-
More than 365 days	-	-	1,700,008	1,700,008	-	-	2,278,233	2,278,233
Total	-	120,427,957	187,284,094	307,712,051	-	120,482,626	198,413,058	318,895,684
Suppliers with Payments Overdue	Balance as of				Balance as of
	12-31-2016				12-31-2015
	Goods	Services	Other	Total	Goods	Services	Other	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Up to 30 days	-	-	6,598,959	6,598,959	-	-	10,249,865	10,249,865
From 31 to 60 days	-	-	-	-	-	-	-	-
From 61 to 90 days	-	-	-	-	-	-	-	-
From 91 to 120 days	-	-	6,472,974	6,472,974	-	-	-	-
From 121 to 365 days	-	-	9,695,136	9,695,136	-	-	-	-
More than 365 days	-	-	66,801,033	66,801,033	-	-	87,506,351	87,506,351
Total	-	-	89,568,102	89,568,102	-	-	97,756,216	97,756,216

The accompanying notes are an integral part of these consolidated financial statements.

F-188

EX-1.1

Exhibit 1.1

Bylaws (Estatutos) of ENEL AMÉRICAS S. A.

(Approved by shareholders on April 27, 2017)

CHAPTER ONE

Name, Domicile, Duration and Objects

Article 1: An open, joint-stock company which is to be called "Enel Américas S.A." (the "Company"), is organized and shall be governed by these bylaws and, on those matters omitted|, by the legislation and regulation applicable to this type of corporation.

Article 1 bis: Notwithstanding the preceding Article, the Company is subject to the provisions of Decree Law No. 3,500 and its amendments.

Article 2: The Company's address shall be in the city of Santiago and agencies or branches may be opened in other parts of the country or abroad.

Article 3: The life of the Company is indefinite.

Article 4: The purpose of the company, in Chile or abroad, shall be the exploration, development, operation, generation, distribution, transmission, transformation, and/or energy sale in any of its forms or nature, directly or through other companies, as well as telecommunication activities and the provision of engineering consultancy services in the country and abroad. It shall also be its object to invest and manage its investments in its subsidiary and affiliate generation, transmission, distribution or electricity trading companies, or any other subsidiary and affiliate companies whose business is  related to any of the following: (i) energy in any of its forms or nature; (ii) supply of public utilities or which have electric energy as their main component; (iii) telecommunications and computer science, and (iv) intermediation business through the Internet. In meeting its main objects, the Company shall carry out the following functions:

(a) Promote, organize, constitute, modify, dissolve or liquidate companies of any kind whose objects are allied or related to those of the Company.

(b) Propose the investment, financing and trading policies to its subsidiary companies, as well as the accounting systems and criteria to be followed.

(c) Supervise the management of its subsidiary companies.

(d) Provide its related companies, subsidiary and affiliate companies with financial resources necessary for their businesses and provide management services for its related parties, subsidiaries and affiliate companies; financial, commercial, technical and legal advice; auditing services and generally any kinds of service seeming necessary for their best performance.

Apart from its main objects and acting always within the limits set out in the Investment and Financing Policy approved by a Shareholders' Meeting, the Company may invest in:

(1) The acquisition, exploitation, construction, rental, management, commercialization and disposal of all kinds of real estate directly or through subsidiary or affiliate companies.

(2) All kinds of financial assets including shares, bonds and debentures, commercial papers and in general all kinds of securities and holdings in companies, directly or through subsidiary or affiliate companies.

CHAPTER TWO

Capital and Shares

Article 5: The capital of the Company is 6,763,204,424 (six billion seven hundred and sixty three million two hundred and four thousand four hundred and twenty four) United States dollars divided into 57,452,641,516 (fifty seven billion four hundred and fifty two million six hundred and forty one thousand five hundred and sixteen)

i

registered ordinary shares, all of the same series and with no par value, which are subscribed and paid for in the manner described in the First Transitory Article of these bylaws.

Article 5 bis: No person shall directly or through other related persons hold more than 65% of the capital with voting rights of the Company or a higher percentage which the law may allow for holding a concentration factor of 0.6. The minority shareholders should hold at least 10% of the capital with voting rights and at least 15% of the capital with voting rights should be held by over one hundred unrelated shareholders each of whom shall hold a minimum equivalent to one hundred Unidades de Fomento in shares, according to the value at which they appear in the latest balance sheet. Minority shareholders and related persons shall be understood as defined in current legislation.

Article 6: Shares shall be registered and their subscription shall be recorded in writing in the manner determined under current legislation and regulations. Their transfers and transmission shall be in accordance with those regulations. Payment for subscribed shares may be in cash or other tangible or intangible assets.

Article 7: The Company shall not recognize fractions of shares. Should one or more shares belong jointly to various parties, the co-owners shall all be obliged to provide a power of attorney to act before the Company.

Article 8: Unpaid balances of subscribed shares shall be adjusted in the same proportion as changes in the value of the Unidad de Fomento.

Article 9: Shareholders are only responsible for the payment of their shares and are not obliged to return to the Company the amounts of any benefits they might have received as a benefit. In the case of the transfer of subscribed and unpaid shares, the transferor shall be liable severally with the transferee for its payment, and notice must be recorded on the certificate of the share payment conditions.

Article 9 bis: The withdrawal rights that a Pension Fund Manager may exercise in the cases foreseen in Article 107 of Decree Law No. 3,500 of 1980 shall be subject to the following special conditions: a) the withdrawal right may be exercised from the date of publication of the decision of the Risk Classification Committee which withdraws its approval of the shares of the Company, and the term for exercising such right and for payment of the share price in accordance with paragraph 2 of Article 71 of Law No.18,046 shall run from that date, and b) the value of the share which the Company shall pay to the Pension Fund Manager exercising its withdrawal rights, shall be calculated in accordance with the relevant Articles of Supreme Decree No.587 dated August 4, 1982 of the Ministry of Finance, known as Corporation Regulations. However, should the shares have a market quotation, the value per share shall be the greater of the average weighted price in its market trading during the six months prior to the date of the withdrawal of approval decision of the Risk Classification Committee causing the withdrawal, duly adjusted for inflation in line with changes in the Consumer Price Index between the day of each transaction and the date of that decision, and the market value on that day defined as the average price of transactions on the stock market. The higher value so calculated shall be applicable only if it be greater than that determined in accordance with the provisions of the said Corporations Regulations and, in the case of shares having no market quotation, the date of the withdrawal of approval decision of the Risk Classification Committee shall be considered as the date for calculating the book value.  

Article 10: Private agreements between shareholders relating to shares disposal, shall be registered with the Company and made available to other shareholders and interested third parties and reference shall be made to them in the Shareholders Register. If this procedure is not followed, such agreements shall be not opposable to third parties. Such agreements shall not affect the obligation of the Company to register without further formality the transfers that are presented, in accordance with the law.

Article 11: The Shareholders Register, the details to be stated on share certificates and the procedure in the case of lost or mislaid certificates, shall comply with the pertinent legal rules and regulations.

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CHAPTER THREE

Administration

Article 12: The Company shall be administered by a Board of Directors composed by seven re-eligible members who may or may not be shareholders of the Company.

Article 13: Members of the Board of Directors shall be elected by the Ordinary Shareholders' Meeting. The Board of Directors shall remain for a period of three years at the end of which it shall be completely renewed or re-elected.

Article 14: Board of Directors' meetings shall be constituted with the absolute majority of the Directors and decisions shall be taken by the absolute majority of the Directors present with voting rights. In the case of a tied vote, the person presiding the meeting shall decide.

Article 14 bis: All acts or contracts entered into by the Company with its majority shareholders, its Directors or Executives or with parties related to these, shall be previously approved by two-thirds of the Board of Directors and appear in the corresponding minutes, subject to the provisions of Chapter XVI of Law No. 18,046.

Article 15: The Board of Directors shall meet at least once every month and whenever the Company's business so requires. There shall be ordinary and extraordinary Meetings. The former shall be held on dates and times pre-established by the Board of Directors itself; the latter when especially convened by the Chairman himself or at the request of one or more Directors, in which case prior qualification by the President with respect to the need to hold such Meeting is required, except where the Meeting is requested by the absolute majority of all Board Members, in which case such Meeting may be held without any prior qualification. Extraordinary Meetings may only deal with those matters specifically included in the meeting notification. In the first session following the appointment of the Directors at an Ordinary Shareholders' Meeting, the Board of Directors shall elect a Chairman from amongst its members.

Article 16: The Directors shall be remunerated. The Ordinary Shareholders' Meeting will set the amount of remuneration annually. The Chairman shall be entitled to receive twice the amount paid to each Director.  

Article 17: The Board of Directors of the Company represents it judicially and extra-judicially and to comply with its objects which it shall not be necessary to demonstrate to third parties, has all the powers of administration and disposal which the Law or the bylaws do not reserve for the Shareholders' Meeting, without the necessity to give it any special powers, even for those acts or contracts for which the law demands such. This does not impede actions appropriate to the Chief Executive Officer. The Board of Directors may delegate part of its powers to the Chief Executive Officer, Managers, Assistant Managers, Lawyers and senior executives of the Company, to one Director or to a Committee of Directors and to other persons for especially defined objectives.

Article 17 bis: In carrying out the powers set out in the preceding Article, the Board of Directors shall act always within the limitations set by the investment and financing policy approved at the Ordinary Shareholders' Meeting in accordance with the terms of Article 119 of Decree Law No. 3,500 of 1980, and its amendments.

Article 18: The Company shall have a Chief Executive Officer who shall be appointed by the Board of Directors and shall be granted all the powers of a commercial agent and those expressly agreed by the Board of Directors. The position of Chief Executive Officer is incompatible with that of Chairman, Director, Auditor or Accountant of the Company.

CHAPTER FOUR

Shareholders' Meetings

Article 19: Shareholders shall meet in Ordinary and Extraordinary Meetings. The former shall be held once each year within four months following the balance sheet date to decide on matters of mutual interest without necessarily being mentioned in the respective meeting notification. The latter may be held at any time as required by the business to decide on any matter which the Law or these bylaws reserves for consideration by a shareholders meeting and provided these matters are stated in the respective meeting notification. Notifications of Ordinary and

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Extraordinary Meetings shall not be necessary when the whole number of validly issued shares is represented at the respective meeting. When an Extraordinary Meeting has to resolve on matters appropriate to an Ordinary Shareholders' Meeting, its procedures and resolutions shall be subject, where appropriate, to the quorums applicable to the latter class of meetings.

Article 20: The following are matters for an Ordinary Meeting: 1) Examination of the situation of the Company and of the reports of accounting inspectors and external auditors and the approval or rejection of the annual report, balance sheet, financial statements and presentations prepared by the managers or liquidators of the Company; 2) The distribution of profits for each year and, especially, the dividend distribution; 3) The election or renewal of the members of the Board of Directors, of liquidators and of management inspectors; and 4) Generally, any matter of general interest which is not reserved for an Extraordinary Meeting. Ordinary Meetings shall appoint independent external auditors annually to examine the accounts, inventories, balance sheet and other financial statements, and to inform the following Ordinary Meeting in writing of its findings.

Article 20 bis: In addition to the terms of the preceding Article, the Ordinary Meeting shall be responsible for approving the investment and financing policy proposed by the management in the terms contemplated in Article 119 of Decree Law No. 3,500 of 1980 and its amendments. It shall also be the responsibility of the Ordinary Meeting to appoint annually the inspectors of accounts and their respective alternates, with the powers established in Article 51 of Law No.18,046.

Article 21:  The following are matters for an Extraordinary Meeting: 1) The dissolution of the Company; 2) Transformation, merger, or division of the Company and amendments to its bylaws; 3) Bond and convertible debenture issuances; 4) The disposal of 50% or more of assets, with or without its liabilities, to be determined on the basis of the balance sheet for the previous financial year; and likewise, any business plan definition or amendment that involves the sale of assets above the aforementioned percentage. Likewise the sale or transfer of ownership of 50% or more of the assets of a subsidiary, provided that this represents at least 20% of the assets of the Company, and any disposal of its shares that implies that the parent company ceases to be its controller; 5) The granting of real or personal guarantees to secure third party obligations, unless granted to subsidiaries, in which case, the approval of the Board of Directors will be sufficient and; 6) Other matters which, by law, or by these bylaws, should be known by, and subject to the Shareholders' Meetings. The matter referred to in items one, two, three and four may only be agreed upon in Meetings held before a Notary, who must certify that the Minutes of the Meeting is the true expression of what occurred and was agreed upon in the meeting

Article 21 bis:  Notwithstanding the terms of the preceding Article, the following shall also be matters of an Extraordinary Meeting: a) The disposal of assets or rights of the Company which are declared essential for its business in the investment and financing policy, as well as the granting of guarantees over them; and b) The modification in advance of the investment and financing policy approved by the Ordinary Meeting.

Article 22: Meetings shall be convened by the Board of Directors of the Company and notifications shall be effected by means of a conspicuous advice which shall be published at least three times on different days in the newspaper within the Company's legal area of residence, which the Meeting shall nominate. It shall also send a notification by mail to every shareholder at least 15 days prior to the date of the meeting, which should mention the matters for consideration at the meeting, as well as an explanation of the way full copies of the documents justifying the various options submitted to a vote can be obtained, if any, which should be made available to shareholders on the web site of the Company. The omission of this obligation shall not affect the validity of the notification, but the Directors, Liquidators and Managers of the Company at fault shall be responsible for any damage suffered by shareholders, irrespective of the administrative sanctions which the Superintendence of Securities and Insurance may apply. However, those meetings attended by the whole of the issued shares with voting rights may be self-convened and held validly even when the required formalities for notifications have not been complied with. All shareholder meetings must be informed to the Superintendence of Securities and Insurance at least 15 days in advance.

Article 23: Meetings are constituted with an absolute majority of shares with voting rights on the first notification, and with those present or represented, whatever their number, on the second notification, and resolutions shall be adopted by the absolute majority of the shares present or represented with voting rights. Notices of the second notification may only be published once the meeting subject to the first notification fails to convene, and in any case the new meeting should be convened within 45 days following the date fixed for the meeting not held. Meetings

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shall be presided by the Chairman of the Board of Directors or the person taking his place, and the Secretary of the Board of Directors of the Company, or the Chief Executive Officer in his absence, shall act as Secretary of the meeting.

Article 24: Resolutions of Extraordinary Shareholders' Meetings which relate to modifications of the bylaws shall require the vote of two-thirds of the shares with voting rights.

Article 24 bis: As long as the Company remains subject to the terms contained in Chapter Twelve and other relevant parts of Decree Law No. 3,500, of 1980, as amended, any modification to the regulations set out in the First, Fifth, Ninth, Fourteenth, Seventeenth, Twentieth, Twenty-First, Twenty-Seventh and Thirty Seven Supplementary Articles and this Article, shall require the consenting vote of 75% of the issued shares with voting rights, in accordance with Article 121 of the said Decree Law No. 3,500.

Article 25: Only those shareholders registered in the Shareholders Register five days before the date for which the respective Meeting is convened, may participate in meetings and exercise their rights to speak and vote. Shareholders without voting rights, as well as the Directors and Managers who are not shareholders, may participate in General Meetings with a right to speak.

Article 26: Shareholders may be represented at meetings by another person even if such person is not a shareholder, notwithstanding that established in Article 45 bis of Decree Law No. 3,500. Proxies for such representations shall be given in writing for all the shares held by the owner on the date stated in the preceding Article.

Article 27: Shareholders shall have a right to one vote for each share they own or represent, and may accumulate or distribute them as they wish in any election.

Article 27 bis: Notwithstanding the contents of the preceding Article, no shareholder may exercise for his own account or on behalf of other shareholders, the right to vote for a percentage of subscribed shares with voting rights of the Company in excess of the maximum concentration permitted in the bylaws and must deduct any excess over this limit for this purpose. For calculating this percentage, the shares held by the shareholder shall be added to those of parties related to the former. Neither may any person represent shareholders who in aggregate hold more than the maximum concentration level permitted in the bylaws.

CHAPTER FIVE

The Directors' Committee and Audit Committee

Article 28: While the Company meets the equity and concentration requirements established in Article 50 bis, or that succeeding or replacing it, of Law No. 18,046, it shall be obliged to appoint an independent director and a Directors' Committee. This Committee shall be governed in its formation, membership, functioning and powers by the provisions of the Chilean Companies Act and instructions on this subject issued by the Superintendence of Securities and Insurance.

Article 29: Notwithstanding the provisions of the preceding Article and while the Company is an issuer of securities duly registered with the New York Stock Exchange (NYSE) or any other American national stock exchange, the formation, membership, functioning and powers of the Directors' Committee shall also be governed, where not to be contrary to Chilean law, by the obligatory provision for the so-called "Audit Committee" in the Sarbanes Oxley Act (SOX) of the United States of America and the instructions issued by the Securities and Exchange Commission (SEC) and the New York Stock Exchange (NYSE), or the organism or entity that definitively corresponds in accordance with the legislation of the United States of America. In case of a irreconcilable or irremediable conflict, disagreement or incompatibility between the provisions of Chilean and American legislation for the Directors' Committee and the Audit Committee respectively, Chilean law shall prevail over foreign law, although the Board of Directors may call an Extraordinary Shareholders' Meeting to amend the bylaws should this be necessary, and shall have the widest powers, acting within its powers, to solve such conflict, disagreement or incompatibility should this be possible, by the creation of new committees and/or sub-committees, as also the delegation of part of its powers in accordance with Article 40 of the Chilean Companies Act. The shareholders, directors and Board of Directors of the

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Company should ensure at all times that the agreements and policies adopted by it are compatible and harmonious with the provisions of both legislations.

Article 30: The Directors' Committee shall be composed of three members, the majority of whom shall be independent according to the criteria and requirements established for this purpose in Article 50 bis of Law No. 18,046, both at the time of their appointment and during the whole period in which they perform as members of the Committee. Notwithstanding the above and complementing the provisions of Article 29 above, while the corporation is an issuer of securities duly registered on the NYSE or any other American national stock exchange, and in order to give strict compliance with the legal and regulatory requirements that the registration involves, all the members of the Directors' Committee should also meet the criteria and requirements of independence prescribed for this purpose by the SOX, SEC and NYSE. Thus, no director who has been elected or appointed as a member of the Directors' Committee may therefore have any link, interest or dependence with the corporation, whether economic, professional, credit or commercial, whatever the amount or nature, nor receive, directly or indirectly, any income, remuneration or compensation from the corporation or any of its subsidiaries which is not by concept nor has as the sole and exclusive source the duties performed as a member of the Board of Directors, as a member of the Directors' Committee or as a member of any other committee or sub-committee of directors of the Company.

Article 31: The loss of independence which, according to the laws governing the Company and these bylaws, affects a member of the Committee, shall generate the following incapacity of the respective director to perform their duties as a director or member of the Directors' Committee and therefore they should cease automatically in that position, notwithstanding their responsibility to the shareholders.

Article 32: The directors appointed as members of the Directors' Committee shall remain as such for the period they were appointed as director and may only resign from this position when they resign as director or having acquired a following incapacity to perform the duties, in which case the provisions of the preceding Article shall apply. No director elected or appointed as a member of the Directors' Committee may be excused from this election or appointment.

Article 33: The meetings of the Directors' Committee shall be validly constituted with the absolute majority of its members and its resolutions shall be adopted by the absolute majority of the members present. The Directors' Committee should elect a Chairman from among its members, who shall have the casting vote in the event of a tied vote.

Article 34: The Committee shall have the powers and duties that have been expressly contemplated both in the laws and their regulations, as well as the rules issued for the purpose by the competent administrative authority, especially those stated in Article 50 bis of Law No. 18,046, and any other matter, mandate, power or duty commended to it by a shareholders or Board meeting.

Article 35: The deliberations, agreements and organization of the Directors' Committee shall be governed, in everything applicable, by the regulations relating to the Board meetings of the Company.

CHAPTER SIX

Balance Sheet, Funds and Earnings

Article 36: As of December 31 of each year, a financial statement with the operations of the Company shall be prepared, and the Board of Directors shall present this to the Ordinary Shareholders' Meeting together with a report analyzing the situation of the Company and the statement of income and the related report provided by the inspectors of accounts and external auditors. All these documents must reflect clearly the equity position of the Company at the close of the respective year and the profits obtained or losses suffered during the year.

Article 37: On a date no later than the first notification convening the Ordinary Shareholders' Meeting, the Board of Directors should make available to each shareholder registered in the respective register a copy of the duly audited Financial Statements and Annual Report of the Company, including the reports of the external auditors and inspectors of accounts, and their respective notes. The duly audited balance sheet and statement of income and other information which the law or the Superintendence of Securities and Insurance requires, shall be published on the

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web site of the Company no less than ten days before the date on which the meeting to approve them is to be held. The annual report, balance sheet, inventories, minutes of Board and Shareholders' Meetings, books and reports of inspectors, must be available to shareholders in the offices of the Company for 15 days prior to the date informed for the meeting. Should the balance sheet and statement of income be altered by the Meeting, the amendments, where corresponding, shall be made available to shareholders within 15 days following the date of the Meeting.

Article 38: Unless otherwise approved at the respective Meeting with the unanimous vote of the shares issued, a cash dividend shall be distributed annually to shareholders, pro rata to their shares, for at least 30% of the net income for each year. In any event, the Board of Directors may, under the personal responsibility of the Directors present at the respective approval, distribute interim dividends during the year as a charge against the profits of that year, provided that there are no accumulated losses. That portion of profits earnings not appropriated by the Meeting to dividends, may be capitalized at any time, subject to amending the bylaws through the issue of free shares or by increasing the nominal value of the shares, or be retained to meet possible dividend payments in following years.

CHAPTER SEVEN

Dissolution and Liquidation

Article 39: The dissolution of the Company shall occur in the cases foreseen in the Law. Dissolution in advance shall only be agreed at an Extraordinary Shareholders' Meeting with the consenting vote of two-thirds of the issued shares with voting rights.

Article 40: Once the Company is dissolved, the liquidation shall be performed by a Liquidation Committee formed by three people, shareholders or not, chosen by the Shareholders' Meeting, and who shall have the powers, duties and obligations established in the law or regulations. If the Company is dissolved as a result of all the shares being held by one person through an uninterrupted period of at least ten days, liquidation shall be unnecessary.

Article 41: The liquidators shall convene an Ordinary Shareholders' Meeting in the month of April each year to report on the state of the liquidation. Should the liquidation not be completed within two years, a new election of liquidators shall be made, the same persons being re-eligible. The position of liquidators is remunerated and the Ordinary Shareholders' Meeting shall set the remuneration. The position of liquidator is revocable by an Ordinary or Extraordinary Shareholders' Meeting. Liquidators shall be suspended from their positions by overriding legal incapacity or by their declaration of bankruptcy.

CHAPTER EIGHT

General Provisions

Article 42: The differences which may arise between the shareholders as such, or between them and the Company or its officers, either during its existence or its dissolution, will be solved by an arbitrator named by common accord between both parties, who will exercise the role as arbitrator in such a proceeding, and must decide according to Law. In the absence of such an agreement, the arbitrator shall be designated by Common Courts at the request of either party, in which case such nomination must be from attorneys who teach or who have taught for at least three consecutive years as Professors of Economic or Commercial Law in the Department of Law at the Universidad de Chile, Universidad Católica de Chile or Universidad Católica de Valparaíso. Notwithstanding the above, in the event of a conflict, the plaintiff may withdraw his recognition of the authority of the arbitrator, and submit to the jurisdiction of the Common Justice, a right that cannot be exercised by the directors, managers, administrators and senior executives of the Company, nor by those shareholders that individually hold, directly and indirectly, shares whose book or market value exceeds 5,000 Unidades de Fomento, according to the value of this unit on the date of presentation of the demand.    

Article 43: In all matters that are not expressly addressed within these bylaws, the provisions of Law No.18,046, its amendments and regulations applicable to open joint-stock companies and those contained within Decree Law No. 3,500 in the case foreseen in Article 111 of that Decree Law.

Article 44: The Company will continue to be subject to Resolution No. 667 of the Honorable Resolution Commission (the former antitrust authority), dated as of October 30, 2002, on the understanding that (i) the

vii

restrictions imposed by it will not apply to the Company in respect of Enersis Chile S.A. and (ii) given that the companies will not participate in any way in relevant markets located in the Republic of Chile, the Company will be able to merge with Endesa Américas S.A. and Chilectra Américas S.A.

TRANSITORY ARTICLES

First Transitory Article: The capital of the Company is 6,763,204,424 (six billion seven hundred and sixty three million two hundred and four thousand four hundred and twenty four) United States dollars divided into 57,452,641,516 (fifty seven billion four hundred and fifty two million six hundred and forty one thousand five hundred and sixteen) registered ordinary shares, all of the same series and with no par value, which have been fully subscribed and paid for prior to this date.

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EX-8.1

Exhibit 8.1

List of Principal Subsidiaries

Subsidiaries.	Jurisdiction	Short Name
Enel Generación Costanera S.A.	Argentina	Costanera
Dock Sud S.A.	Argentina	Dock Sud
Empresa Distribuidora Sur S.A.	Argentina	Edesur
Enel Generación El Chocón S.A.	Argentina	El Chocón
Ampla Energia e Serviços S.A.	Brazil	Ampla
EGP Cachoeira Dourada S.A.	Brazil	Cachoeira Dourada
Central Geradora Termelétrica Fortaleza S.A.	Brazil	Fortaleza
Enel CIEN S.A.	Brazil	CIEN
Companhía Energética de Ceará S.A.	Brazil	Coelce
Enel Brasil S.A.	Brazil	Enel Brasil
Codensa S.A. E.S.P.	Colombia	Codensa
Emgesa S.A. E.S.P.	Colombia	Emgesa
Enel Generación Perú S.A.A.	Peru	Enel Generación Perú
Enel Distribución Perú S.A.A.	Peru	Enel Distribución Perú
Enel Generación Piura S.A.	Peru	Enel Generación Piura

EX-12.1

Exhibit 12.1

302 CERTIFICATION

I, Luca D’Agnese certify that:

1. I have reviewed this annual report on Form 20-F of Enel Américas S.A.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5. The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 28, 2017

/s/ Luca D’Agnese

Luca D’Agnese.

Chief Executive Officer

EX-12.2

Exhibit 12.2

302 CERTIFICATION

I, Javier Galán A., certify that:

1. I have reviewed this annual report on Form 20-F of Enel Américas S.A.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5. The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 28, 2017

/s/ Javier Galán A.

Javier Galán A.

Chief Financial Officer

EX-13.1

Exhibit 13.1

906 CERTIFICATION

The certification set forth below is being submitted in connection with the Annual Report on Form 20-F for the year ended December 31, 2016 for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 (the “Exchange Act”) and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Luca D’Agnese, the Chief Executive Officer, and Javier Galán A., the Chief Financial Officer, of Enel Américas S.A., each certifies that, to the best of their knowledge:

1. the report fully complies with the requirements of Section 13(a) or 15(d) of the Exchange Act; and

2. the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Enel Américas.

Date: April 28, 2017

/s/ Luca D’Agnese

Name: Luca D’Agnese

Chief Executive Officer

/s/ Javier Galán A.

Name: Javier Galán A.

Chief Financial Officer

EX-23.1

EY Audit SpA Avda. Presidente Riesco 5435, piso 4, Santiago   Tel: +56 (2) 2676 1000 www.eychile.cl         Exhibit 23.1  

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement on Form F-3 (No. 333-214079) of Enel Américas S.A and in the related Prospectus of our reports dated April 27, 2017, with respect to the consolidated financial statements of Enel Américas S.A. and subsidiaries, and the effectiveness of internal control over financial reporting of Enel Américas S.A. and subsidiaries, included in this Annual Report (Form 20-F) for the year ended December 31, 2016.

/s/ EY Audit SpA.                

EY Audit SpA.

Santiago, Chile

April 27, 2017

EX-23.2

	KPMG Auditores Consultores Ltda. Av. Isidora Goyenechea 3520, Piso 2 Las Condes, Santiago, Chile	Exhibit 23.2
		Teléfono  +56 (2) 2798 1000 Fax  +56 (2) 2798 1001 www.kpmg.cl

Consent of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Enel Generación Chile S.A. (Enel Generación Chile) Formerly Named Empresa Nacional de Electricidad S.A. (Endesa−Chile):

We consent to the incorporation by reference in the registration statement (No. 333-214079)on Form F-3 of Enel Américas S.A. ofour report dated April 29, 2016, with respect to the consolidated statement of financial position of Enel Generación Chile and subsidiaries as of December 31, 2015, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for the years ended December 31, 2015 and 2014, which report appears in the 2016 annual report on Form 20-F of Enel Américas S.A..

/s/ KPMG

KPMG Auditores Consultores Ltda.

Santiago, Chile

April 27, 2017

KPMG Auditores Consultores Ltda, a Chilean limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.