Company Quick10K Filing
Enel Generacion Chile
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$0.00 8,202 $143,285
20-F 2019-04-30 Annual: 2018-12-31
20-F 2018-04-27 Annual: 2017-12-31
20-F 2017-04-27 Annual: 2016-12-31
20-F 2016-05-02 Annual: 2015-12-31
20-F 2015-04-30 Annual: 2014-12-31
20-F 2014-04-01 Annual: 2013-12-31
20-F 2013-03-21 Annual: 2012-12-31
20-F 2012-04-05 Annual: 2011-12-31
20-F 2011-05-31 Annual: 2010-12-31
20-F 2010-06-11 Annual: 2009-12-31
EOCC 2018-12-31
Part I
Item 1. Identity of Directors, Senior Management and Advisers
Item 2. Offer Statistics and Expected Timetable
Item 3. Key Information
Item 4. Information on The Company
Item 4A. Unresolved Staff Comments
Item 5. Operating and Financial Review and Prospects
Item 6. Directors, Senior Management and Employees
Item 7. Major Shareholders and Related Party Transactions
Item 8. Financial Information
Item 9. The Offer and Listing
Item 10. Additional Information
Item 11. Quantitative and Qualitative Disclosures About Market Risk
Item 12. Description of Securities Other Than Equity Securities
Part II
Item 13. Defaults, Dividend Arrearages and Delinquencies
Item 14. Material Modifications To The Rights of Security Holders and Use of Proceeds
Item 15. Controls and Procedures
Item 16. Reserved
Item 16A. Audit Committee Financial Expert
Item 16B. Code of Ethics
Item 16C. Principal Accountant Fees and Services
Item 16D. Exemptions From The Listing Standards for Audit Committees
Item 16E. Purchases of Equity Securities By The Issuer and Affiliated Purchasers
Item 16F. Change in Registrant's Certifying Accountant
Item 16G. Corporate Governance
Item 16H. Mine Safety Disclosure
Part III
Item 17. Financial Statements
Item 18. Financial Statements
EX-1.1 a19-8584_1ex1d1.htm
EX-8.1 a19-8584_1ex8d1.htm
EX-12.1 a19-8584_1ex12d1.htm
EX-12.2 a19-8584_1ex12d2.htm
EX-13.1 a19-8584_1ex13d1.htm

Enel Generacion Chile Earnings 2018-12-31

EOCC 20F Annual Report

Balance SheetIncome StatementCash Flow

Comparables ($MM TTM)
Ticker M Cap Assets Liab Rev G Profit Net Inc EBITDA EV G Margin EV/EBITDA ROA
SHPG 167,103 97,348 37,430 15,702 2,714 5,227 9,077 177,968 17% 19.6 5%
EOCC 143,285 3,669,228 1,671,737 0 0 0 0 143,285 0%
BCEL 90,348 227 8 0 0 -18 -18 90,193 -5,033.4 -8%
UBER 76,613 30,980 15,072 6,265 0 -6,248 -5,579 67,526 0% -12.1 -20%
TWX 74,606 68,997 39,192 31,532 13,501 5,786 9,576 91,246 43% 9.5 8%
AET 66,578 57,103 38,540 61,233 30,264 3,690 5,387 67,966 49% 12.6 6%
DVMT 60,080 115,520 111,401 91,601 27,175 3,386 5,498 102,737 30% 18.7 3%
ESRX 53,843 55,442 34,869 101,353 8,926 4,910 6,726 63,111 9% 9.4 9%
PX 47,321 19,979 13,229 12,037 0 1,508 3,763 54,918 0% 14.6 8%
GLD 35,933 36,143 184 0 0 3,747 3,747 35,933 9.6 10%

20-F 1 a19-8584_120f.htm 20-F

Table of Contents

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 20-F

 


 

o

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

 

 

OR

 

 

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018

 

 

OR

 

 

o

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

for the transition period from                      to

 

 

OR

 

 

o

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

 

Date of event requiring this shell company report . . . . . . . . . . . . . . . . . . .

 

Commission file number: 1-13240

 


 

ENEL GENERACIÓN CHILE S.A.

(Exact name of Registrant as specified in its charter)

 


 

ENEL GENERACIÓN CHILE 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

 

 

 

None

 

 

 

Securities registered or to be registered pursuant to Section 12(g) of the Act: Common Stock, no par value*

 


*Not for trading, but only in connection with the registration of American Depositary Shares, each representing 30 shares of common stock, pursuant to the requirements of the Securities and Exchange Commission.

 


Table of Contents

 

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

 

US$ 205,881,000

 

7.875%

 

Notes due February 1, 2027

US$ 70,780,000

 

7.325%

 

Notes due February 1, 2037

US$ 40,416,000

 

8.125%

 

Notes due February 1, 2097

US$ 400,000,000

 

4.250%

 

Notes due April 15, 2024     

(Title of Class)

 


 

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

x Yes   o No

 

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

o Yes   x No

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:

x Yes   o No

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

x Yes   o No

 

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

 

Large accelerated filer x

 

Accelerated filer o

 

Non-accelerated filer o

 

Emerging growth company o

 

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards † provided pursuant to Section 13(a) of the Exchange Act. o

 

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

 

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

 

U.S. GAAP o

 

International Financial Reporting Standards as issued
by the International Accounting Standards Board
x

 

Other o

 

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

o Item 17   o Item 18

 

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

o Yes   x No

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

 

Shares of Common Stock:

8,201,754,580

 


Table of Contents

 

Enel Generation Chile’s Organizational Chart (1)

As of December 31, 2018

 

 

 


(1)         Only principal operating subsidiaries are presented here. The percentage listed in the box for each of Enel Generation’s consolidated subsidiaries represents its economic interest in such consolidated subsidiary.

(2)         Excluding treasury stock.

 

2


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TABLE OF CONTENTS

 

 

 

Page

GLOSSARY

4

INTRODUCTION

7

PRESENTATION OF INFORMATION

8

FORWARD-LOOKING STATEMENTS

10

PART I

 

 

Item 1.

Identity of Directors, Senior Management and Advisers

11

Item 2.

Offer Statistics and Expected Timetable

11

Item 3.

Key Information

11

Item 4.

Information on the Company

21

Item 4A.

Unresolved Staff Comments

47

Item 5.

Operating and Financial Review and Prospects

47

Item 6.

Directors, Senior Management and Employees

64

Item 7.

Major Shareholders and Related Party Transactions

71

Item 8.

Financial Information

73

Item 9.

The Offer and Listing

75

Item 10.

Additional Information

78

Item 11.

Quantitative and Qualitative Disclosures About Market Risk

93

Item 12.

Description of Securities Other Than Equity Securities

96

PART II

 

 

Item 13.

Defaults, Dividend Arrearages and Delinquencies

97

Item 14.

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

97

Item 15.

Controls and Procedures

97

Item 16.

Reserved

98

Item 16A.

Audit Committee Financial Expert

98

Item 16B.

Code of Ethics

98

Item 16C.

Principal Accountant Fees and Services

99

Item 16D.

Exemptions from the Listing Standards for Audit Committees

99

Item 16E.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

99

Item 16F.

Change in Registrant’s Certifying Accountant

99

Item 16G.

Corporate Governance

99

Item 16H.

Mine Safety Disclosure

100

PART III

 

 

Item 17.

Financial Statements

101

Item 18.

Financial Statements

101

Item 19.

Exhibits

101

 

3


Table of Contents

 

GLOSSARY

 

AFP

 

Administradora de Fondos de Pensiones

 

A legal entity that manages a Chilean pension fund.

 

 

 

 

 

CDEC

 

Centro de Despacho Económico de Carga

 

The autonomous entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand in the SIC and SING that was replaced by the CEN in November 2017.

 

 

 

 

 

Celta

 

Compañía Eléctrica Tarapacá S.A.

 

Celta was a former Chilean generation subsidiary of Enel Generation that operated plants in the SING and the SIC. Celta merged into GasAtacama in November 2016.

 

 

 

 

 

CEN

 

Coordinador Eléctrico Nacional

 

An autonomous entity in charge of coordinating the efficient operation of the SEN, dispatching generation units to satisfy demand and known as the National Electricity Coordinator. It replaced the CDEC for both the SIC and SING in November 2017.

 

 

 

 

 

Chilean Stock Exchanges

 

Chilean Stock Exchanges

 

The two principal stock exchanges located in Chile: the Santiago Stock Exchange and the Electronic Stock Exchange.

 

 

 

 

 

CMF

 

Comisión para el Mercado Financiero

 

Chilean Financial Market Commission, the governmental authority that supervises the financial markets. Formerly known as the Chilean Superintendence of Securities and Insurance or SVS in its Spanish acronym.

 

 

 

 

 

CNE

 

Comisión Nacional de Energía

 

Chilean National Energy Commission, governmental entity with responsibilities under the Chilean regulatory framework.

 

 

 

 

 

DCV

 

Depósito Central de Valores S.A.

 

Chilean Central Securities Depositary.

 

 

 

 

 

Enel

 

Enel S.p.A.

 

An Italian energy company with multinational operations in the power and gas markets. A 61.9% beneficial owner of Enel Chile as of December 31, 2018, and our ultimate parent company.

 

 

 

 

 

Enel Américas

 

Enel Américas S.A.

 

An affiliated Chilean publicly held limited liability stock corporation, with subsidiaries engaged primarily in the generation, transmission and distribution of electricity in Argentina, Brazil, Colombia, and Perú, and controlled by Enel. Formerly known as Enersis S.A.

 

 

 

 

 

Enel Chile

 

Enel Chile S.A.

 

Our parent company, a Chilean publicly held limited liability stock corporation, with subsidiaries engaged primarily in the generation and distribution of electricity in Chile, and which is controlled by Enel. Formerly known on an interim basis as Enersis Chile. S.A. Owner of 93.6% of our shares as of December 31, 2018.

 

4


Table of Contents

 

Enel Distribution

 

Enel Distribución Chile S.A.

 

An affiliated Chilean publicly held limited liability stock corporation owned by Enel Chile, engaged in the electricity distribution business with operations in the Santiago Metropolitan Region. Formerly known on an interim basis as Chilectra Chile S.A. and prior to that as Chilectra S.A.

 

 

 

 

 

Enel Generation

 

Enel Generación Chile S.A.

 

Our company, a Chilean publicly held limited liability stock corporation, engaged in the electricity generation business with operations in Chile. Registrant of this Report. Formerly known as Empresa Nacional de Electricidad S.A. or Endesa Chile.

 

 

 

 

 

EGP Chile

 

Enel Green Power Chile Ltda.

 

A Chilean limited liability company, with non-conventional renewable electricity generation operations and since April 2, 2018, a consolidated subsidiary of Enel Chile.

 

 

 

 

 

EGPL

 

Enel Green Power Latin America S.A.

 

A Chilean closely held limited liability stock corporation that merged with Enel Chile on April 2, 2018. As a result, Enel Chile now consolidates EGP Chile.

 

 

 

 

 

GasAtacama

 

GasAtacama Chile S.A.

 

An affiliated Chilean closely held limited liability stock corporation, engaged in gas transportation and electricity generation in northern Chile and our subsidiary.

 

 

 

 

 

GasAtacama Holding

 

Inversiones GasAtacama Holding Ltda.

 

A holding company subsidiary that previously held GasAtacama. GasAtacama Holding merged into Celta during 2016, which later merged into GasAtacama.

 

 

 

 

 

Gener

 

AES Gener S.A.

 

A Chilean generation company and our competitor in Chile.

 

 

 

 

 

GNL Quintero

 

GNL Quintero S.A.

 

A company created to develop, build, finance, own and operate a LNG regasification facility at Quintero Bay at which LNG is unloaded, stored and regasified. We sold our 20% stake in this company to Enagas Chile S.p.A., an unaffiliated company, in September 2016.

 

 

 

 

 

HidroAysén

 

Centrales Hidroeléctricas de Aysén S.A.

 

A company created to develop a hydroelectric project in the Aysén region, southern Chile. We owned 51% of HidroAysén and Colbún, an unaffiliated company, owned the remaining 49%. The company terminated its activities in 2017.

 

 

 

 

 

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.

 

 

 

 

 

NCRE

 

Non-Conventional Renewable Energy

 

Energy sources that are continuously replenished by natural processes, such as wind, biomass, mini-hydro, geothermal, wave, solar or tidal energy.

 

5


Table of Contents

 

OSM

 

Ordinary Shareholders’ Meeting

 

Ordinary Shareholders’ Meeting.

 

 

 

 

 

Pehuenche

 

Empresa Eléctrica Pehuenche S.A.

 

A Chilean publicly held limited liability stock corporation engaged in the electricity generation business, owner of three power stations in the Maule River basin and our subsidiary.

 

 

 

 

 

SEF

 

Superintendencia de Electricidad y Combustible

 

Chilean Superintendence of Electricity and Fuels, the governmental authority that supervises the Chilean electricity industry.

 

 

 

 

 

SEN

 

Sistema Eléctrico Nacional

 

The National Electricity System is the Chilean national interconnected electricity system formed in November 2017 through the integration of the SIC and SING.

 

 

 

 

 

SIC

 

Sistema Interconectado Central

 

Chilean central interconnected electricity system that was integrated with the SING in November 2017 to form a single interconnected system, the SEN.

 

 

 

 

 

SING

 

Sistema Interconectado del Norte Grande

 

Chilean interconnected electric system operating in northern Chile that was integrated with the SIC in November 2017 to form a single interconnected system, the SEN.

 

 

 

 

 

UF

 

Unidad de Fomento

 

Chilean inflation-indexed, Chilean peso-denominated monetary unit equivalent to Ch$ 27,565.79 as of December 31, 2018.

 

 

 

 

 

UTA

 

Unidad Tributaria Anual

 

Chilean annual tax unit. One UTA equals 12 Unidades Tributarias Mensuales (“UTM”), a Chilean inflation-indexed monthly tax unit used to define fines, among other purposes. For December 2018, one UTM was equivalent to Ch$ 48,353 and one UTA was equivalent to Ch$ 580,236.

 

6


Table of Contents

 

INTRODUCTION

 

As used in this Report on Form 20-F (the “Report”), first person personal pronouns such as “we,” “us” or “our”, as well as “Enel Generación Chile”, “Enel Generation” or the “Company”, refer to Enel Generación Chile S.A. and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries, jointly-controlled entities and associates is expressed in terms of our economic interest as of December 31, 2018.

 

We are a Chilean company engaged in the electricity generation business in Chile directly and through our subsidiaries and jointly-controlled entities and are the surviving company spun off from Empresa Nacional de Electricidad S.A. (“Endesa Chile”).

 

We are a publicly held limited liability stock corporation originally organized on December 1, 1943 under the laws of the Republic of Chile. During 2016, we completed a corporate reorganization to separate our Chilean businesses from our non-Chilean businesses. On October 18, 2016, and as part of this process, (i) Endesa Chile changed its name to Enel Generación Chile S.A.; (ii) Chilectra Chile S.A. changed its name to Enel Distribución Chile S.A.; and (iii) Enersis Chile S.A. changed its name to Enel Chile S.A. For additional information relating the company and the corporate reorganization completed in 2016, please see “Item 4. Information on the Company — A. History and Development of the Company” and “— The 2016 Reorganization”.

 

As of the date of this Report and after giving effect to the 2018 Reorganization, (i) our direct controlling entity, Enel Chile S.A. (“Enel Chile”), owns 93.6% of our shares and (ii) Enel S.p.A. (“Enel”), an Italian energy company with multinational operations in the power and gas markets, beneficially owns 61.9% of Enel Chile as of December 31, 2018, and is our ultimate controlling shareholder with an economic interest of 57.9% in our Company. For additional information relating to the 2018 Reorganization, see “Item 4. Information on the Company — A. History and Development of the Company — The 2018 Reorganization”.

 

7


Table of Contents

 

PRESENTATION OF INFORMATION

 

Financial Information

 

In this Report, unless otherwise specified, references to “U.S. dollars” or “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; and references to “UF” are to Unidades de Fomento. The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is adjusted daily to reflect changes in the official Consumer Price Index (“CPI”) of the Chilean National Institute of Statistics (Instituto Nacional de Estadísticas or “INE”). The UF is adjusted in monthly cycles. Each day in the period beginning on the tenth day of the current month through the ninth day of the succeeding month, the nominal peso value of the UF is indexed in order to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month. As of December 31, 2018, one UF was equivalent to Ch$ 27,565.79. The U.S. dollar equivalent of one UF was US$ 39.68 as of December 31, 2018, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2018 of Ch$ 694.77 per US$ 1.00. The U.S. dollar observed exchange rate (dólar observado) (the “Observed Exchange Rate”), which is reported by the Central Bank of Chile and published daily on its webpage, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Unless the context specifies otherwise, all amounts translated from Chilean pesos to U.S. dollars or vice versa, or from UF to Chilean pesos, have been carried out at the rates applicable as of December 31, 2018.

 

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.

 

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. Our participation in associated companies over which we exercise significant influence are included in our consolidated financial statements using the equity method. For detailed information regarding consolidated entities, jointly-controlled entities and associated companies, see Appendices 1, 2 and 3 to the consolidated financial statements.

 

Solely 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, 2018, as defined in “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”. The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. No representation is made that the Chilean peso or U.S. dollar amounts shown in this Report could have been or could be converted into U.S. dollars or Chilean pesos, as the case may be, at such rate or at any other rate. See “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”.

 

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

 

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

 

8


Table of Contents

 

TW equals 1,000 GW, one GW equals 1,000 MW and one MW equals 1,000 kW. The installed capacity we are presenting in this Report corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its own operation.

 

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

 

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

 

Calculation of Economic Interest

 

References are made in this Report to the “economic interest” of Enel Generation 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 associate company and 40% is directly held by our 60%-owned subsidiary, our economic interest in such associate would be 60% times 40% plus 6%, equal to 30%.

 

Rounding

 

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.

 

9


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FORWARD-LOOKING STATEMENTS

 

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

 

·                           our capital investment program;

 

·                           trends affecting our financial condition or results from operations;

 

·                           our dividend policy;

 

·                           the future impact of competition and regulation;

 

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

 

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

 

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

 

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

 

·                           demographic developments, political events, economic fluctuations and interventionist measures by authorities in Chile;

 

·                           water supply, droughts, flooding and other weather conditions;

 

·                           changes in Chilean environmental regulations and the regulatory framework of the electricity industry;

 

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

 

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

 

·                           the factors discussed below under “Risk Factors.”

 

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

 

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

 

10


Table of Contents

 

PART I

 

Item 1.   Identity of Directors, Senior Management and Advisers

 

Not applicable.

 

Item 2.   Offer Statistics and Expected Timetable

 

Not applicable.

 

Item 3.   Key Information

 

A.                     Selected Financial Data.

 

The following selected consolidated financial data should be read in conjunction with our consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2018, and 2017 and for each of the years in the three-year period ended December 31, 2018, are derived from our audited consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2016, 2015 and 2014, and for the years ended December 31, 2015, and 2014 are derived from our consolidated financial statements not included in this Report. Our consolidated financial statements were prepared in accordance with IFRS, as issued by the IASB.

 

Amounts in the tables 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, 2018, has been converted at the U.S. dollar Observed Exchange Rate (dólar observado) for that date of Ch$ 694.77 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 “Item 3. Key Information — A. Selected Financial Data — Exchange Rates” below.

 

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

 

 

 

As of and for the year ended December 31,

 

 

 

2018(1)

 

2018

 

2017

 

2016

 

2015

 

2014

 

 

 

(US$ millions)

 

 

 

(Ch$ millions)

 

Consolidated Statement of Comprehensive Income Data

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues and other operating income

 

2,189

 

1,521,054

 

1,634,937

 

1,659,727

 

1,543,810

 

1,230,975

 

Operating costs(2)

 

(1,521

)

(1,056,671

)

(1,171,077

)

(1,228,341

)

(1,141,991

)

(978,713

)

Operating income

 

668

 

464,383

 

463,860

 

431,386

 

401,819

 

252,262

 

Financial results(3)

 

(69

)

(47,947

)

(36,610

)

(35,679

)

(114,252

)

(77,345

)

Other gains(4)

 

5

 

3,435

 

113,089

 

121,491

 

4,015

 

42,652

 

Share of profit (loss) of associates and joint ventures accounted for using the equity method

 

5

 

3,281

 

(2,697

)

7,878

 

8,905

 

(54,353

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income before income taxes

 

609

 

423,152

 

537,642

 

525,077

 

300,487

 

163,216

 

Income tax expense

 

(151

)

(104,947

)

(112,100

)

(83,217

)

(76,656

)

(94,058

)

Net income

 

458

 

318,205

 

425,542

 

441,860

 

223,831

 

69,158

 

Profit after tax from discontinued operations

 

 

 

 

79,572

 

411,190

 

489,919

 

Net income for the year

 

458

 

318,205

 

425,542

 

521,432

 

635,021

 

559,077

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to the parent Company

 

445

 

309,029

 

418,454

 

472,558

 

392,868

 

276,027

 

Net income attributable to non-controlling interests

 

13

 

9,176

 

7,088

 

48,874

 

242,153

 

283,050

 

Basic and diluted earnings per share (Ch$/US$ per share)

 

0.05

 

37.7

 

51.0

 

52.8

 

25.9

 

6.8

 

Basic and diluted earnings per share (Ch$/US$ per ADS)

 

1.63

 

1,130

 

1,531

 

1,583

 

777

 

204

 

Total Basic and diluted earnings per share (Ch$/US$ per share)

 

0.05

 

37.7

 

51.0

 

57.6

 

47.9

 

33.5

 

Total Basic and diluted earnings per ADS (Ch$/US$ per ADS)

 

1.63

 

1,130

 

1,531

 

1,729

 

1,437

 

1,005

 

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

 

0.03

 

22.6

 

28.1

 

14.6

 

20.4

 

21.6

 

Cash dividends per ADS (Ch$/US$ per ADS)(5)

 

0.98

 

678

 

864

 

437

 

612

 

647

 

Number of shares of common stock (millions)

 

8,202

 

8,202

 

8,202

 

8,202

 

8,202

 

8,202

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Statement of Financial Position Data

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-current assets and disposal groups held for sale or distribution to owners

 

 

 

4,205

 

12,993

 

3,889,706

 

7,979

 

Total assets

 

5,281

 

3,669,228

 

3,554,462

 

3,399,682

 

7,278,770

 

7,237,672

 

Non-current liabilities

 

1,551

 

1,077,856

 

1,022,092

 

1,114,145

 

1,207,005

 

2,321,048

 

Liabilities associated with disposal groups held for sale or distribution to owners

 

 

 

 

 

1,851,784

 

5,490

 

Equity attributable to the parent company

 

2,836

 

1,970,521

 

1,961,518

 

1,700,962

 

2,648,190

 

2,700,280

 

Equity attributable to non-controlling interests

 

39

 

26,970

 

27,496

 

28,798

 

895,700

 

823,606

 

Total equity

 

2,875

 

1,997,491

 

1,989,014

 

1,729,760

 

3,543,890

 

3,523,886

 

Capital stock(6)

 

919

 

638,289

 

638,289

 

638,289

 

1,537,723

 

1,537,723

 

Other Consolidated Financial Data

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures (CAPEX)(7)

 

320

 

222,327

 

206,776

 

194,880

 

537,805

 

421,314

 

Depreciation, amortization and impairment losses(8)

 

170

 

117,866

 

117,282

 

163,386

 

115,042

 

113,766

 

 


(1)                  Solely for the convenience of the reader, Chilean peso amounts have been converted into U.S. dollars at the exchange rate of Ch$ 694.77 per U.S. dollar, as of December 31, 2018.

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

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

(4)                  Please refer to Note 31 of the Notes to our consolidated financial statements.

(5)                  One ADS = 30 shares of common stock. Please refer to Item 9.

(6)                  Capital stock represents issued capital plus share premium.

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

(8)                  For further detail please refer to Notes 27 and 29 of the Notes to our consolidated financial statements.

 

 

 

As of and for the year ended December 31,

 

 

 

2018

 

2017

 

2016

 

2015

 

2014

 

OPERATING DATA

 

 

 

 

 

 

 

 

 

 

 

Installed capacity (MW)(1)

 

6,274

 

6,351

 

6,351

 

6,351

 

6,351

 

Generation (GWh)(1)

 

17,373

 

17,073

 

17,564

 

18,294

 

18,063

 

 

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Exchange Rates

 

Fluctuations in the exchange rate between the Chilean peso and the U.S. dollar will affect the U.S. dollar equivalent of the peso price of our shares of common stock on the Santiago Stock Exchange (Bolsa de Comercio de Santiago) and the Chilean Electronic Stock Exchange (Bolsa Electrónica de Chile). These exchange rate fluctuations affect the price of our American Depositary Shares (“ADSs”) and the conversion of cash dividends relating to the common shares represented by ADSs from Chilean pesos to U.S. dollars. In addition, to the extent that significant financial liabilities of the Company are denominated in foreign currencies, exchange rate fluctuations may have a significant impact on earnings.

 

In Chile, there are two currency markets, the Formal Exchange Market (Mercado Cambiario Formal) and the Informal Exchange Market (Mercado Cambiario Informal). The Formal Exchange Market is comprised of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market is comprised of entities that are not expressly authorized to operate in the Formal Exchange Market, such as certain foreign currency 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, 2018, the U.S. dollar Observed Exchange Rate was Ch$ 694.77 per US$ 1.00.

 

As of April 22, 2019, the U.S. dollar Observed Exchange Rate was Ch$ 663,91 per US$ 1.00.

 

Calculation of the appreciation or devaluation of the Chilean peso against the U.S. dollar in any given period is made by determining the percent change between the reciprocals of the Chilean peso equivalent of US$ 1.00 at the end of the preceding period and the end of the period for which the calculation is being made. For example, to calculate the devaluation of the year-end Chilean peso in 2018, one determines the percentage of change between the reciprocal of Ch$ 694.77, the value of one U.S. dollar as of December 31, 2018, or 0.001439, and the reciprocal of Ch$ 614.75, the value of one U.S. dollar as of December 31, 2017, or 0.001627. In this example, the percentage change between the two periods is -11.5%, which represents the 2018 year-end devaluation of the Chilean peso against the 2017 year-end U.S. dollar. A positive percentage change means that the Chilean peso appreciated against the U.S. dollar, while a negative percentage change means that the Chilean peso devaluated against the U.S. dollar.

 

The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2014 through December 31, 2018, based on information published by the Central Bank of Chile.

 

 

 

Ch$ per US$(1)

 

 

 

Period End

 

Appreciation (Devaluation)

 

 

 

(in Ch$)

 

(in %)

 

Year ended December 31,

 

 

 

 

 

2018

 

694.77

 

(11.5

)

2017

 

614.75

 

8.9

 

2016

 

669.47

 

6.1

 

2015

 

710.16

 

(14.6

)

2014

 

606.75

 

(13.5

)

 


Source: Central Bank of Chile.

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

 

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B.                     Capitalization and Indebtedness.

 

Not applicable.

 

C.                     Reasons for the Offer and Use of Proceeds.

 

Not applicable.

 

D.                     Risk Factors.

 

Chilean economic fluctuations, certain economic interventionist measures by governmental authorities as well as political events or financial or other crises in any region worldwide may affect our results of operations, financial condition and liquidity as well as the value of our securities.

 

All of our operations are located in Chile. Accordingly, our revenues are affected by the performance of the Chilean economy. If local, regional or worldwide economic trends adversely affect the Chilean economy, our financial condition and results from operations could be adversely affected. Insufficient cash flows could result in the inability to meet our debt obligations and the need to seek waivers to comply with restrictive debt covenants and increasing costs for subsequent financings.

 

The Chilean government has exercised in the past, and continues to exercise, a substantial influence over many aspects of the private sector, which may result in changes to economic or other policies.

 

Future adverse developments in Chile or changes in policies regarding exchange controls, regulations and taxation may impair our ability to execute our business plan, which could adversely affect our results of operations and financial condition. Inflation, devaluation, social instability and other political, economic or diplomatic developments could also reduce our profitability. In addition, Chilean financial and securities markets are influenced by economic and market conditions in other countries, and may be affected by events in other countries, which could adversely affect the value of our securities.

 

Our business depends heavily on hydrological conditions.

 

Approximately 55% of our installed generation capacity in 2018 was hydroelectric. Accordingly, dry hydrological conditions could adversely affect our business, results of operations and financial condition. Our results have been adversely affected when hydrological conditions in Chile have been significantly below average.

 

We have entered into certain agreements with the Chilean government and local irrigators regarding the use of water for hydroelectric generation purposes, during periods of low water levels, if droughts persist, we may face increased pressure by the Chilean government or other third parties to restrict our water use further.

 

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

 

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

 

·                           Our thermal plants require water for cooling and droughts in extreme situations may reduce the availability of water and increase the cost of transportation. As a result, we have had to purchase water for our San Isidro power plant from agricultural areas that are also experiencing water shortages. These water purchases may increase our operating costs and may require us to negotiate with the local communities.

 

·                           Thermal power plants that burn natural gas generate emissions such as nitrogen oxide (NO), carbon dioxide (CO2) and carbon monoxide (CO) gases. When operating with diesel they release NO, sulfur dioxide (SO2) and particulate matter into the atmosphere. Coal fired plants generate SO2 and NO emissions. Therefore, greater thermal plant use during droughts generally increases the risk of producing higher levels of greenhouse gas emissions, which also decreases our operating income due to the payment of so-called “green taxes.”

 

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

 

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

 

Our businesses and the tariffs that we charge to our customers are subject to extensive regulation and these regulations may adversely affect our profitability. For example, governmental authorities might impose rationing policies during droughts or prolonged failures of power facilities, which may adversely affect our business, results of operations and financial condition. Our operating subsidiaries are also subject to environmental regulations that, among other things, require us to perform environmental impact studies for future projects and obtain construction and operating permits from both local and national regulators. The governmental authorities may withhold the approval of these environmental impact studies and therefore their processing time may be longer than expected. Similarly, electricity regulations issued by governmental authorities may affect the ability of our generation companies to collect revenues sufficient to cover their operating costs.

 

Environmental regulations for existing and future generation capacity have become stricter and require increased capital investments. Any delay in meeting the standards constitutes a violation of the regulations. Failure to certify the original implementation and ongoing emission standard requirements of such monitoring system may result in significant penalties and sanctions or legal claims for damages. We expect that even more restrictive emission limits will be established in the future. We are also subject to an annual green tax, based on our emission of pollutants in the previous year, and such taxes may increase in the future, and discourage thermal electricity generation.

 

Changes in the regulatory framework are often submitted to the legislators and administrative authorities and, some of these changes could have a material adverse impact on our business, results of operations and financial condition.

 

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

 

Our electricity businesses are subject to regulatory fines for any breach of current regulations, including energy supply failures. Such fines may be imposed for a maximum of 10,000 Annual Tax Units (“UTA” in its Spanish acronym), or Ch$ 5.8 billion using the UTA as of December 31, 2018. Our electricity generation subsidiaries are supervised by local regulatory authorities and are subject to fines in cases where, in the opinion of the regulatory authority, operational failures affecting the regular energy supply to the system, including coordination issues, are the fault of the generator. Regulations establish a compensation fee to end customers when energy is interrupted more than the standard allowed time due to events or failures affecting transmission facilities. Compensation is a proportion of the energy not supplied with a minimum value between 20,000 UTA (Ch$ 11.6 billion) and the previous year’s energy sales revenues in the case of generators. Fines may also be associated with breach of regulations.

 

In 2015, the CDEC-SING audited GasAtacama’s thermal power plant and reported its findings to the Superintendence of Electricity and Fuels (“SEF”), which in August 2016 fined GasAtacama 10,000 UTA (Ch$ 5.8 billion) for allegedly providing inaccurate information to the CDEC-SING. In 2017, Gener and Engie, both competitors, demanded that Enel Generation pay US$ 65.8 million and US$ 160 million, respectively, as compensation for the alleged additional costs attributed to GasAtacama in the system. These costs were associated with the technical minimum capacity reported by GasAtacama at 310 MW, with a 30-hour minimum operating time that the CEN later estimated to be only 118 MW and a 2-hour minimum operating time. Further compensation claims from other market players may arise in the future and further fines to any of our plants could adversely affect our business, results of operations and financial condition.

 

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

 

In order to pay our obligations, we may rely on cash from dividends, loans, interest payments, capital reductions and other distributions from our subsidiaries. Such payments and distributions to us are subject to legal constraints such as dividend restrictions and fiduciary obligations.

 

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

 

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

 

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

 

We are involved in litigation proceedings.

 

We are 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 lawsuits and proceedings against us. For further information on litigation proceedings, please see “Item 8. Financial Information — A. Consolidated Statements and Other Financial Information — Legal Proceedings” and Note 35.3 of the Notes to our consolidated financial statements.

 

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

 

Our power plant projects may be delayed in obtaining regulatory approvals, or may face shortages and increases in the price of equipment, materials or labor, and they may be subject to construction delays, strikes, adverse weather conditions, natural disasters, civil unrest, accidents, and human error. Any such event could adversely impact our business, results of operations and financial condition.

 

Market conditions at the time when the projects are initially approved may differ significantly from those that prevail when the projects are completed, which in some cases make such projects commercially unfeasible. This has been the case with many of our former projects, which were initially planned under very different market conditions with higher energy prices prevailing in the market and less competition. Deviations in these assumptions, including the estimates of the timing and expenditures related to these projects, may lead to cost over-runs and a completion time widely exceeding our initial estimates, which in turn may have a material adverse effect on our business, results of operation and financial condition.

 

The operation of our coal-fired thermal power plants may affect our goodwill with stakeholders, due to greenhouse gas emissions, which could adversely affect the environment and local residents. In addition, communities might have their own interests and different perceptions of the company, or be influenced by other stakeholders or motivations unrelated to the project. Therefore, if the company fails to engage with its relevant stakeholders, it might face opposition, which could adversely affect our reputation, stall operations or result in a lawsuit. Our reputation is the foundation of our relationship with key stakeholders. If we are unable to effectively manage real or perceived issues that could affect us negatively, our business, results of operations and financial condition could be adversely affected.

 

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

 

Political events or financial or other crises in any region worldwide can have a significant impact in Chile, and consequently, may adversely affect our operations as well as our liquidity.

 

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

 

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

 

The U.S. federal government has experienced shutdowns in recent times, including the 2018-2019 U.S. government shutdown, which affected the SEC among many other federal agencies, and extended for 35 days, the longest federal government shutdown in

 

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U.S. history. Even temporary or threatened U.S. government shut-downs could have a material adverse effect on the timing, execution and increased expense associated with our international financings and our M&A activities.

 

An international financial crisis and its disruptive effects on the financial industry could adversely impact our ability to obtain new 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 Chilean and international capital markets or increase the interest rates available to us. Reduced liquidity, in turn, could adversely affect our capital expenditures, our long-term investments and acquisitions, our growth prospects and our dividend payout policy.

 

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

 

On an ongoing basis, we review acquisition prospects that may increase our market coverage or 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 of expenses related to tangible assets and the diversion of management’s attention from other business concerns. In addition, integrating acquired businesses may be difficult, expensive, time-consuming and a strain on our resources and our relationships with our employees and customers and ultimately may not be successful or achieve the benefits expected. Any delays or difficulties encountered in connection with acquisitions and the integration of their businesses 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 granted by the Chilean Water Authority (Dirección General de Aguas) for the supply of water from rivers and lakes near our production facilities. Under current law, these water rights are (i) for unlimited duration, (ii) absolute and unconditional property rights and (iii) not subject to further challenge. Chilean generation companies must pay an annual license fee for unused water rights. New hydroelectric facilities are required to obtain water rights, the conditions of which may affect design, timing or profitability of a project.

 

In addition, Chilean Congress has discussed amendments to the Water Code since 2014 in order to prioritize the use of water by defining its access as a basic human need that must be guaranteed by the State. The amendment will establish that water use for human consumption, domestic subsistence and sanitation will always take precedence, in both the granting and limiting the exercise of rights of exploitation. Restrictions enacted to preserve environmental flows would reduce water availability for generation purposes.

 

Any limitations on our water rights, our need for additional water rights, or our unlimited duration of water concessions could have a material adverse effect on our hydroelectric development projects and our profitability. As of the date of this Report, no resolutions have been adopted and the uncertainty remains.

 

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

 

The Chilean peso has been subject to devaluations and appreciations against the U.S. dollar and may be subject to significant fluctuations in the future. Historically, a significant portion of our consolidated indebtedness has been denominated in U.S. dollars. Although a substantial portion of our operating cash flows is linked to the U.S. dollar (primarily coming from the generation business), we generally have been and will continue to be exposed to fluctuations of the Chilean peso against the U.S. dollar, which is due to time lags and other limitations to pegging our tariffs to the U.S. dollar and the potential difficulty of obtaining loans in the same currency as our operating cash flow.

 

Because of this exposure, the value of cash generated by our subsidiaries in U.S. dollars can decrease substantially due to peso devaluations against the U.S. dollar. Future volatility in the exchange rate of the currency in which we receive revenues or incur expenditures may adversely affect our business, results of operations and financial condition.

 

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Our long-term electricity 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 electricity sales contracts into which we have entered. We have material obligations as selling parties under long-term fixed-price electricity sales contracts. Prices in these contracts are indexed according to different commodities, exchange rates and inflation. 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 Chile owns 93.6% of our shares and Enel’s economic interest in us is 57.9%. Through its control of Enel Chile, Enel 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, the adoption of our dividend policy. Enel also exercises significant influence over our business strategy and operations. Its interests, in some cases, may differ from those of our minority shareholders. Certain conflicts of interest affecting Enel in these matters may be resolved in a manner that is different from interests of our company or of our minority shareholders.

 

After giving effect to the 2018 Reorganization, the ownership interest of our minority shareholders was considerably reduced, from 40% to 6.4% and their ability to influence the outcome of any matter that is or can be subject to shareholder approval, including the appointment of directors, acquisitions or disposition of substantial assets, the issuance of capital stock and other securities and the payment of dividends on our securities, will be very limited. However, as long as there are minority shareholders, potential conflicts of interests may continue to arise. The increase in the controlling interest may not necessarily eliminate the potential conflicts of interests between us and the business formerly held by EGPL that are now owned by Enel Chile, through EGP Chile.

 

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

 

Our primary facilities include power plants. Our facilities may be damaged by earthquakes, fires and other catastrophic disasters arising from natural or accidental human causes, as well as acts of protest, vandalism, riot, and terrorism. A catastrophic event could cause prolonged unavailability of our assets, disruptions in our business, significant decreases in revenues due to lower demand or significant additional costs to us not covered by our business interruption insurance. There may be lags between a major accident or catastrophic event and the final reimbursement from our insurance policies, which typically carry a deductible and are subject to per event policy maximum amounts.

 

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

 

As of December 31, 2018, our consolidated debt totaled Ch$ 841 billion.

 

Some of our debt agreements are subject to (1) financial covenants, (2) affirmative and negative covenants, (3) events of default and (4) mandatory prepayments for contractual breaches, 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 breach any of these contractual provisions, our debtholders may demand immediate repayment, and a significant portion of our indebtedness could become due and payable. We may be unable to refinance our indebtedness or obtain such refinancing on terms acceptable to us. In the absence of such refinancing, we could be forced to dispose of assets in order to make the payments due on our indebtedness under circumstances that might not be favorable to obtaining the best price for such assets. Furthermore, we may be unable to sell our assets quickly enough, or at sufficiently high prices, to enable us to make such payments.

 

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

 

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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 unaffiliated companies to deliver the electricity we sell. This dependence exposes us to several risks. If transmission is disrupted, or transmission capacity is inadequate, we may be unable to sell and deliver our electricity. If a region’s power transmission infrastructure is inadequate, our recovery of sales costs and profits may be insufficient. If restrictive transmission price regulation is imposed, transmission companies upon whom we rely may not have sufficient incentives to invest in expansion of their transmission infrastructure, which could adversely affect our operations and financial results. The construction of new transmission lines may take longer than in the past, mainly because of social and environmental requirements that are creating uncertainty as to the timing of project completion.

 

There have been blackout events in the past due to the failure of transmission lines, which exposed weaknesses in the transmission grid and its need for expansion and technological improvements to increase its reliability. Additional failures of transmission lines may occur in the future.

 

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 or if we are unable to retain key employees.

 

A large percentage of our employees is members of unions and has 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. Chilean law provides legal mechanisms for judicial authorities to impose a collective bargaining agreement if the parties are unable to come to an agreement, which may materially increase our costs beyond what we have budgeted.

 

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

 

The price and liquidity of our common stock and ADSs may be adversely affected by the small minority interest remaining after completion of the 2018 Reorganization, the limited market for our ADSs since they were delisted from the NYSE and now trade in the over-the-counter market in the U.S. and the relative illiquidity and volatility of the Chilean securities markets.

 

Following completion of the 2018 Reorganization, only 6.4% of our common stock is held by minority shareholders. As of the end of 2018, ADSs comprised only approximately 0.64% of the total outstanding shares of our common stock. Accordingly, our common stock and ADSs are not widely held and the volume of trading has been relatively low and sporadic. As a result, the market for our shares of common stock and ADSs has become more limited and our common stock and ADSs are subject to increased price volatility and reduced liquidity. In addition, the lack of market liquidity could also increase the difficulty of selling our securities in large blocks without adversely affecting their price. There can be no assurance that an active trading market for our common stock or ADSs can be sustained in Chile or the U.S.

 

At the end of 2018, we voluntarily delisted our ADSs from trading on the NYSE and our ADSs are now quoted in the over-the-counter market on the OTC Pink, an inter-dealer electronic quotation and trading system for equity securities operated by OTC Markets, Inc. Quotation of our ADSs on the OTC Pink may limit the liquidity and price of our ADSs more than if our ADSs were listed and traded on the NYSE or another national securities exchange. Trading in securities quoted in the over-the-counter markets is often thin, volatile, and characterized by wide fluctuations in trading prices due to many factors that may have little to do with our operations or business prospects. In addition, the over-the-counter markets are not a stock exchange and trading of securities in the over-the-counter markets is often more sporadic than trading of securities listed on the NYSE or other national securities exchanges. Some investors may perceive our ADSs to be less attractive because they are traded in the over-the-counter market. In addition, as an OTC Pink company, we may not have the analyst coverage that accompanies companies listed on national securities exchanges. Furthermore, institutional and other investors may have investment guidelines that restrict or prohibit investing in securities quoted on the OTC Pink. These factors may have an adverse impact on the trading, liquidity and price of our ADSs and holders of ADSs may have difficulty selling their ADSs.

 

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Following the 2018 Reorganization, the primary market for our shares of common stock is now the Santiago Stock Exchange. However, we cannot assure you that our shares will continue to meet the criterial for continued listing on the Chilean Stock Exchanges and our common stock may be delisted from one or both of the Chilean Stock Exchanges. Our common stock may also lose the “sufficient stock market liquidity” (presencia bursátil) status on the Chilean Stock Exchanges, which would result in loss of a capital gains tax exemption for certain holders of our shares under Chilean law.

 

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. In addition, the liquidity and the market for our shares and 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, the 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 decrease capital flows to Chile. Such a decrease would adversely affect the general Chilean economy and the interest of investors in our shares in particular.

 

The price or the liquidity of our shares and ADSs may be negatively affected by events in Latin American markets or the global economy in general.

 

Lawsuits against us brought outside Chile or complaints against us based on foreign legal concepts may be unsuccessful.

 

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

 

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 operate in an industry that requires the continued operation of sophisticated information technology, control and communications systems (“IT Systems”) and network infrastructure. In addition, we use our IT Systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. In our generation business, IT Systems are critical in controlling and monitoring our power plants’ operations, maintaining generation and network performance, generating invoices to bill customers, achieving operating efficiencies and meeting our service targets and standards. The operation of our generation system is dependent not only on the physical interconnection of our facilities with the electricity network infrastructure, but also on communications among the various parties connected to the network. The reliance on IT Systems to manage the information and communication among and between those parties has increased significantly since the deployment of intelligent grids.

 

Our generation facilities, IT Systems and other infrastructure, as well as the information processed in our IT Systems could be affected by cybersecurity incidents, including those caused by human error. Our industry has begun to see an increase in the volume and sophistication of cyber security incidents from international activist organizations, nation states and individuals, being among the emerging risks identified in our planning process. Cybersecurity incidents could harm our businesses by limiting our generating capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or exposing us to liability. Our generation system is part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident in the electric transmission grid, network infrastructure, fuel sources or our third party service providers’ operations could also negatively impact our business.

 

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In addition, our business requires the collection and retention of personally identifiable information of our customers, employees and shareholders, who expect that we will adequately protect the privacy of such information. Cybersecurity breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs associated with notifying and protecting affected persons. This could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely affect our results of operations, as well as our reputation with customers, shareholders and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. The cybersecurity threat is dynamic and evolves continually and, in the electricity industry, is increasing in sophistication, magnitude and frequency. There can be no assurance that we can implement adequate preventative measures or accurately assess the likelihood of a cyber-incident. We are unable to quantify the potential impact of cybersecurity incidents on our business and our reputation. These potential cybersecurity incidents and corresponding regulatory action could result in a material decrease in revenues and may result in significant additional costs, including penalties, third party claims, repair costs, additional insurance expense, litigation costs, notification and remediation costs, security costs and compliance costs. While we maintain property and casualty insurance, there can be no assurance that liabilities or losses we may incur, including as a result of cybersecurity litigation, will be covered under such policies or that the amount of insurance will be adequate.

 

Item 4.   Information on the Company

 

A.                     History and Development of the Company.

 

We are a publicly held limited liability stock corporation originally organized on December 1, 1943 under the laws of the Republic of Chile. Since 1943, we have been registered in Santiago with the CMF under Registration No. 0114. We have also been registered with the SEC under the commission file number 001-13240 since 1994. Our full name is Enel Generación Chile S.A. and we are also known commercially as “Enel Generación Chile” or “Enel Generación”. Our shares are listed and traded on the Chilean Stock Exchanges and our ADSs were listed and traded on the NYSE until December 28, 2018. Following the 2018 Reorganization (described below), Enel Chile now owns 93.6% of our shares of common stock and ADSs, which by the end of 2018 comprised only approximately 0.64% of the total outstanding shares of common stock. We determined that the costs associated with continuing the listing of our ADSs on the NYSE exceed the benefits received by us, as our primary market for the shares is now the Santiago Stock Exchange. As a result, we decided to file an application for voluntary delisting from the NYSE as part of our effort to reduce operational expenses.

 

Our contact information in Chile is:

 

Contact Person:

 

Nicolás Billikopf

Street Address:

 

Santa Rosa 76, Santiago, Código Postal 8330099, Chile

Email:

 

nicolas.billikopf@enel.com

Telephone:

 

(56-2) 2353-4628

Web site:

 

www.enelgeneracion.cl

 

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

 

We are an electric utility company engaged, directly and through our subsidiaries and affiliates, in the generation businesses in Chile. As of December 31, 2018, we had 6,274 MW of installed capacity, with 28 generation facilities and a total of 111 generation units. Of our total installed capacity, 55% consists of hydroelectric power plants and includes, among others, Ralco with 689 MW, Pehuenche with 568 MW, El Toro with 449 MW, Rapel with 376 MW, and Antuco with 319 MW. 77% of our thermoelectric installed capacity is gas/fuel oil power plants (2,104 MW), and the remaining is coal-fired steam power plants (636 MW). As of December 31, 2018, we had consolidated assets amounting to Ch$ 3,669 billion and operating revenues of Ch$ 1,521 billion.

 

The Chilean government owned Enel Generation from our incorporation in 1943 until 1987, when a privatization process through a series of public offerings commenced. The privatization process was completed in 1989.

 

The 2018 Reorganization

 

On August 25, 2017, Enel Chile proposed a corporate reorganization (the “2018 Reorganization”) to consolidate Enel’s conventional and non-conventional renewable energy businesses in Chile under one company, Enel Chile, which will become Enel’s only vehicle to invest in Chile. The 2018 Reorganization involved the following transactions:

 

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·                  a cash tender offer by Enel Chile of all outstanding shares of our common stock, including ADS. The tender offer was subject to the condition that the tendering holders of Enel Generation shares and ADSs use Ch$236 of the Ch$590 tender offer consideration for each Enel Generation share and Ch$7,080 of the Ch$17,700 tender offer consideration for each Enel Generation ADS to subscribe for shares of our common stock at a subscription price of Ch$82 per Enel Chile share (or Ch$2,460 per Enel Chile ADS) (the “Enel Chile U.S. Share/ADS Subscription Condition”);

 

·                  a capital increase to make available a sufficient number of shares of common stock of Enel Chile to deliver to tendering holders of Enel Generation shares and ADSs to satisfy all conditions precedent; and

 

·                  a merger pursuant to which Enel Green Power Latin América S.A. (“EGPL”) merged into Enel Chile. EGPL was a closely held stock corporation organized under the laws of the Republic of Chile. Before the 2018 Reorganization, EGPL was a member of the Enel Green Power group of companies. Enel Green Power is a transnational company dedicated to electricity generation with renewable resources, which in turn is controlled by Enel. EGPL was a renewable energy generation holding company engaged, through its wholly owned subsidiary Enel Green Power Chile Ltda. (“EGP Chile”), in the electricity generation business in Chile.

 

The different steps of the 2018 Reorganization were approved by the respective shareholders of Enel Chile, Enel Generation and EGPL at their extraordinary shareholders’ meetings held on December 20, 2017. The tender offer occurred between February 16, 2018, and March 22, 2018, the preemptive rights offering in connection with the capital increase took place between February 15, 2018, and March 16, 2018, and the 2018 Reorganization, in the aggregate, was completed and effective on April 2, 2018.

 

As a result of the consummation of the 2018 Reorganization, Enel Chile remains as our major shareholder. Currently, Enel Chile consolidates the Chilean electricity generation business through us, the Chilean electricity distribution business through Enel Distribution and the Chilean non-conventional renewable electricity generation business through EGP Chile. Enel remains as the majority shareholder of Enel Chile, owning 61.9% (excluding treasury stock) of the company, and, through its majority ownership of Enel Chile, also remains as our majority owner and ultimate parent company.

 

During the last few years, our business strategy has focused on increasing our shareholdings in subsidiaries, selling certain non-strategic assets and reducing the number of companies by simplifying our corporate structure, mainly through mergers.

 

We have conducted the following sales of non-core assets over the past few years:

 

·                           On September 14, 2016, we sold our 20% equity interest in GNL Quintero S.A. (“GNL Quintero”), to Enagás Chile S.p.A. We obtained the 20 % interest in GNL Quintero in 2007, as part of a consortium we formed along with ENAP, Metrogas and British Gas to build the LNG regasification facility in the Quintero Bay. Partial commercial operations of the facility began in September 2009 and full commercial operations began on January 1, 2011.

 

·                           On December 16, 2016, we sold our 42.5% equity interest in Electrogas S.A. (“Electrogas”). Electrogas is a company dedicated to the transportation of natural gas and other fuels, which serves our San Isidro and Quintero power plants, among others. We received the proceeds of this sale, amounting to US$ 180 million (Ch$ 115 billion at that time) on February 7, 2017.

 

In order to simplify our corporate structure, we have continued to reduce the number of our companies over the last three years:

 

·                           During 2016, Inversiones GasAtacama Holding Ltda. merged into Celta, which in turn merged into GasAtacama, the surviving company, on November 1, 2016. Celta was our investment vehicle through which we owned the San Isidro thermal plants, the Pangue hydroelectric plant and the Tarapacá thermal generation facility in addition to our interest in Central Éolica Canela S.A, that owned the Canela wind farms.

 

·                           On November 9, 2017, GasAtacama purchased the 25% minority interest of Central Éolica Canela S.A., which was later dissolved on December 22, 2017. Our economic interest in GasAtacama was 97.4% as of December 31, 2018.

 

The 2016 Reorganization

 

During 2016, we completed a corporate reorganization to separate our Chilean businesses from our non-Chilean businesses (the “2016 Reorganization”). The 2016 Reorganization involved the separation of the respective Chilean and non-Chilean electricity generation, transmission and distribution businesses of Endesa Chile, Chilectra S.A. (“Chilectra”) and Enersis S.A. (“Enersis”) by

 

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means of a “demerger” under Chilean law and the subsequent distribution of the shares of the newly created entities to each company’s respective shareholders (collectively, the “Spin-Offs”). The “demerger” or separation of the businesses occurred on March 1, 2016, and the Spin-Offs were effective in April 2016, with the creation and public listing of the shares of the newly incorporated entities: (i) Enersis Chile S.A., which held the Chilean businesses of Enersis, (ii) Endesa Américas S.A., which held the non-Chilean businesses of Endesa Chile, and (iii) Chilectra Américas S.A., which held the non-Chilean businesses of Chilectra. The 2016 Reorganization also involved the merger between the companies holding the non-Chilean assets. The merger became effective on December 1, 2016, and merged Endesa Américas S.A. and Chilectra Américas S.A. with and into Enersis Américas S.A. (currently Enel Américas S.A.), with the latter continuing as the surviving company.

 

As part of this process, we changed our name to Enel Generación Chile S.A. on October 18, 2016. That same date, (i) Chilectra changed its name to Enel Distribución Chile S.A.; and (ii) 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. Although we have considered how these investments will be financed as part of our budget process, we have not committed to any particular financing structure, and investments will depend on the prevailing market conditions at the time the cash flows are needed.

 

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

 

For the 2019-2021 period, we expect to make capital expenditures of Ch$ 367 billion, related to investments currently in progress, maintenance of generation plants and in studies required to develop other potential generation projects. For further detail regarding these projects, please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Development.”

 

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

 

 

 

Estimated
2019-2021

 

2018

 

2017

 

2016

 

 

 

(in millions of Ch$)

 

Capital Expenditure(1)

 

367,252

 

222,327

 

206,776

 

194,880

 

 


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

 

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

 

Capital Expenditures in 2018, 2017 and 2016

 

Our capital expenditures in the last three years were principally related to the optimization of the 350 MW Bocamina II power plant, improvements to the Tarapacá coal-fired power plant, the construction of the 150 MW Los Cóndores power plant and maintenance of our current power plants. Investments related to the Bocamina II and Tarapacá power plants focused on making improvements to reduce environmental impact. These improvements were the consequence of environmental injunctions in the case of Bocamina II and new environmental regulations in the case of Tarapacá. The improvements to Bocamina II were completed in 2018, while those of Tarapacá in 2017.

 

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Our material plans in progress include Los Cóndores project, which began construction in 2014 with completion expected during 2020. For further detail of the Los Cóndores project, please see “Item 4. Information on the Company — D. Property, Plant and Equipment. — Projects Under Construction.”

 

A portion of our capital expenditures is reserved for maintenance, and for the assurance of quality and operational standards of our facilities.  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 that operates in Chile. Our core business is electricity generation. We also participate in other activities but that are not core businesses and represent less than 1% of our 2018 revenues. We do not report them as separate business segment in this Report nor in our consolidated financial statements.

 

The table below presents our revenues:

 

 

 

Year ended December 31,

 

Change

 

Revenues

 

2018

 

2017

 

2016

 

2018 vs. 2017

 

 

 

(in millions of Ch$)

 

(in %)

 

Generation

 

1,521,054

 

1,634,937

 

1,659,727

 

(7.0

)%

Other businesses and intercompany transaction adjustments

 

 

 

 

n.a.

 

Total revenues

 

1,521,054

 

1,634,937

 

1,659,727

 

(7.0

)%

 

For further financial information related to our revenues, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 39 of the Notes to our consolidated financial statements.

 

We are a generation company in the SEN, representing 32.8% of the electricity market share in 2018.

 

As of December 31, 2018, we accounted for 26.5% of SEN’s total generation capacity, measured by the installed capacity, according to figures published by the National Electricity Coordinator (“CEN” in its Spanish acronym). Hydroelectric, thermal and wind power represent 55%, 44% and 1% of our total installed capacity in Chile, respectively.

 

For additional detail on our historical capacity, see “Item 4. Information on the Company — D. Property, Plant and Equipment.”

 

The following tables summarize the information relating to our capacity, electricity generation and energy sales:

 

ELECTRICITY DATA

 

 

 

Year ended December 31,

 

 

 

2018

 

2017

 

2016

 

Number of generating units(1)

 

111

 

111

 

111

 

Installed capacity (MW)(2)(3)

 

6,274

 

6,351

 

6,351

 

Electricity generation (GWh)

 

17,373

 

17,073

 

17,564

 

Energy sales (GWh)

 

23,343

 

23,356

 

23,689

 

 


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

(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, according to criteria defined by such authorities and relevant contracts.

(3)     The 2018-installed capacity differs from previous years since the CEN reviewed the capacity of each generation unit and adjusted their capacity.

 

Our consolidated electricity generation in 2018 were 17,373 GWh and our energy sales was 23,343 GWh, which represents a 1.8% increase and a 0.1% decrease, respectively, when compared to 2017, respectively.

 

Dividing the electricity generation business into hydroelectric, thermoelectric and other generation is customary in the electricity industry, because each generation type has significantly different variable costs. Thermoelectric generation, for instance, requires the

 

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purchase of fuel, which generally leads to higher variable costs than hydroelectric generation from reservoirs or rivers that normally has minimal variable costs. Of our total consolidated generation in 2018, 63% was from hydroelectric sources, 36% was from thermal sources, and less than 1% was from wind energy, which is generated by the Canela I and Canela II wind farms, subsidiaries of GasAtacama.

 

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

 

GENERATION BY TYPE OF ENERGY (GWh)

 

 

 

Year ended December 31,

 

 

 

2018

 

2017

 

2016

 

 

 

Generation

 

%

 

Generation

 

%

 

Generation

 

%

 

Hydroelectric generation

 

10,681

 

63.2

 

9,392

 

55.0

 

8,815

 

50.2

 

Thermal generation

 

6,268

 

36.1

 

7,292

 

42.7

 

8,379

 

47.7

 

Wind generation — NCRE (1)

 

131

 

0.8

 

129

 

0.8

 

107

 

0.6

 

Mini-hydro generation — NCRE (2) 

 

293

 

1.7

 

260

 

1.5

 

263

 

1.5

 

Total generation

 

17,373

 

100

 

17,073

 

100

 

17,564

 

100

 

 


(1)                  Electricity generated by the Canela I and Canela II wind farms.

(2)                  Electricity generated by the Palmucho and the Ojos de Agua mini-hydroelectric plants.

 

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

 

ELECTRICITY SALES BY CUSTOMER TYPE (GWh)

 

 

 

Year ended December 31,

 

 

 

2018

 

2017

 

2016

 

 

 

Sales

 

% of Sales
Volume

 

Sales

 

% of Sales
Volume

 

Sales

 

% of Sales
Volume

 

Regulated customers

 

15,254

 

65.3

 

17,029

 

72.9

 

18,516

 

78.2

 

Unregulated customers

 

7,338

 

31.4

 

5,586

 

23.9

 

4,321

 

18.2

 

Total contracted sales(1)

 

22,592

 

96.8

 

22,615

 

96.8

 

22,838

 

96.4

 

Electricity pool market sales

 

752

 

3.2

 

742

 

3.2

 

852

 

3.6

 

Total electricity sales

 

23,343

 

100

 

23,356

 

100

 

23,689

 

100

 

 


(1)                  Includes sales to distribution companies not backed by contracts.

 

Dividing sales by customer type in terms of regulated and unregulated customer is useful in managing and understanding the business. We sell electricity to regulated customers through distribution companies and to unregulated customers directly. The sales to distribution companies to supply the distributors’ regulated customers, that is, either residential, commercial or others, are classified as regulated sales and are subject to government regulated electricity tariffs. The sales of generation companies to distribution companies to supply the distributors’ unregulated customers are also classified as unregulated sales and are also governed by contracts at a freely negotiated prices and terms. We directly sell to large commercial and industrial customers and other generators are classified as unregulated sales and are generally governed by contracts with freely negotiated prices and terms. Finally, pool market sales are the sales that take place when generation companies are dispatched by the CEN in excess of their contractual obligations and therefore must sell their surplus electricity in the pool market, or when the generators electricity dispatched is less than their contractual commitments with their customers and therefore must purchase the deficit in the pool market. These purchase and sale transactions among electricity companies are normally carried out in the pool market at the spot price, and do not require a contractual agreement.

 

The regulatory framework often requires that electricity distribution companies have contracts to support their commitments to small volume customers. Chilean regulations also determine which customers can purchase energy directly in the electricity pool market.

 

We attempt to minimize the risk of electricity generation deficits resulting from poor hydrological conditions in any given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated electricity production in a dry year. We

 

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consider the available statistical information concerning rainfall, mountain snow and ice, when they are expected to melt, hydrological levels and the capacity of key reservoirs to determine our estimated production for a dry year. 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 to cover the cost of spot market purchases.

 

In 2022, distribution company contracts awarded in the August 2016 auction will come into effect and therefore the tariffs of our regulated contracts will decrease by 6% as a consequence of the lower prices offered by NCRE providers in the energy auction for distribution companies. In 2024, contracts awarded in the November 2017 auction will come into effect with an average price of US$ 32.5 per MWh, which is 31.7% lower than the average price of the previous tender process. We routinely participate in energy bids and we have been awarded long-term energy sale contracts that incorporate the expected variable costs considering changes to the most relevant variables. These contracts secure the sale of our current and expected new capacity and allow us to stabilize our income.

 

In November 2017, the outcome of the latest bidding process was announced. This process tendered 2,200 GWh per year to be delivered between 2024 and 2043. The total amount of energy tendered was based on renewable energy offers, thus representing a milestone in the industry. We were awarded 54% of the tender, corresponding to 1.2 TWh at an average price of US$ 34.7 per MWh with a mix of wind, solar and geothermal generation. These prices are 6.8% higher than the average price.

 

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 hydrology, the amount of our thermal generation increases. This involves an increase in the amount of fuels required and the costs of its transportation to the thermal generation power plants. Under dry conditions, electricity that we have contractually agreed to provide may exceed the amount of electricity that we are able to generate. Therefore, to satisfy our contractual commitments, we may be required to purchase electricity in the pool at spot market prices. The cost of these purchases at spot prices, under certain circumstances, may 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 given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated electricity production in a dry year. We consider the available statistical information concerning rainfall, mountain snow and ice and when they are expected to melt, hydrological levels and the capacity of key reservoirs to determine our estimated production for a dry year. 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.

 

Seasonality

 

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

 

The generation business is affected by seasonal changes throughout the year. During normal hydrological years, snowmelts typically occur during the warmer months of October through March. These snowmelts increase the level of water in our reservoirs. The months with most precipitation are typically May through August.

 

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 adversely affect our generation capacity. For example, severe prolonged drought conditions or reduced rainfall levels in Chile 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

 

We own and operate 111 generation units in Chile both directly and through our subsidiaries GasAtacama and Pehuenche. Of these generation units, 38 are hydroelectric, with a total installed capacity of 3,456 MW, representing 55% of our total installed

 

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capacity in Chile. There are 22 thermal generation units that operate with gas, coal or oil with a total installed capacity of 2,740 MW, representing 44% of our total installed capacity in Chile. There are 51 wind powered generation units with an aggregate installed capacity of 78 MW, representing 1% of our total installed capacity in Chile. On November 21, 2017, the integration of the SIC and the SING into one interconnected system was completed and resulted in the creation of the SEN, a new national interconnected system that extends from Arica in the north of Chile to Chiloé in the south of Chile.

 

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

 

Our total gross electricity generation in Chile accounted for 23.2 % of total gross electricity generation in Chile during 2018.

 

The following table sets forth the electricity generation by each of our generation companies:

 

ELECTRICITY GENERATION BY COMPANY (GWh)

 

 

 

Year ended December 31,

 

 

 

2018

 

2017

 

2016

 

Enel Generation

 

11,314

 

10,976

 

11,538

 

Pehuenche

 

2,794

 

2,443

 

2,369

 

GasAtacama

 

3,265

 

3,654

 

3,657

 

Total

 

17,373

 

17,073

 

17,564

 

 

The following table sets forth the electricity generation by type:

 

ELECTRICITY GENERATION BY TYPE (GWh)

 

 

 

Year ended December 31,

 

 

 

2018

 

2017

 

2016

 

 

 

Generation

 

%

 

Generation

 

%

 

Generation

 

%

 

Hydroelectric generation

 

10,974

 

55.0

 

9,392

 

55.0

 

8,815

 

50.2

 

Thermal generation

 

6,268

 

42.7

 

7,292

 

42.7

 

8,379

 

47.7

 

Wind generation — NCRE(1)

 

131

 

0.8

 

129

 

0.8

 

107

 

0.6

 

Mini-hydro generation — NCRE(2)

 

293

 

1.5

 

260

 

1.5

 

263

 

1.5

 

Total generation

 

17,373

 

100

 

17,073

 

100

 

17,564

 

100

 

 


(1)                  Electricity generated by the Canela I and Canela II wind farms.

(2)                  Electricity generated by the Palmucho and the Ojos de Agua mini-hydroelectric plants.

 

Water Agreements

 

Water agreements refer to the right of a user to utilize water from a particular source, such as a river, stream, pond or groundwater. In times of good hydrological conditions, water agreements are generally not complicated or contentious. However, in times of poor hydrological conditions, water agreements protect our right to use water resources for hydroelectric generation.

 

Through our subsidiaries, we have three agreements in force with the purpose of utilizing water for both irrigation and hydroelectric generation more efficiently. Two of them are agreements between Enel Generation and the Chilean Water Works Authority (“DOH” in its Spanish acronym) and are related to the water consumption during the most intense irrigation period (normally from September to April) from Laja Lake and Maule Lagoon, both located in southern Chile. Enel Generation signed the first agreement with the DOH related to Laja Lake and Maule Lagoon on October 24, 1958, and September 9, 1947, respectively.

 

After four years of studies and dialogue with different sectors making use of water from the Laja Lake, on November 16, 2017, the Operation and Recovery of Laja Lake Agreement was signed, which complements the agreement signed with the DOH in 1958. This agreement provides reasonable irrigation security to irrigators in the area, giving priority to extractions for irrigation when the reservoir is at low levels, which are also used by generation. It also contemplates the use of a certain volume of water to maintain the scenic beauty of Salto del Laja, a well-known tourist attraction in the area. It also significantly improves the flexibility in the use of water, eliminating most of the restrictions that existed in the form of water extraction, replacing it by annual volumes that will manage

 

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irrigation and generation according to their needs. Another agreement was signed in October 2018 between our subsidiary Pehuenche and the irrigators of the Maule Lagoon Monitoring Board to optimize the use of water during drought periods. These agreements allow us to use the water more efficiently and to avoid further litigation with the local community, especially with farmers.

 

Thermal Generation

 

Our thermal electricity generation facilities use mostly LNG, coal and to a lesser extent, diesel. This mix allows us to use other fuels if the price of LNG were to be relatively too high, if there were to be a shortage of supply, or another circumstance were to make LNG unavailable. To satisfy our natural gas and transportation requirements, we signed a long-term gas supply contract with suppliers that establishes maximum supply amounts and prices, as well as long-term gas transportation agreements with the pipeline companies. Gasoducto GasAndes S.A. and Electrogas S.A. are our current gas transportation providers. Since March 2008, all of our natural gas units can operate using either natural gas or diesel and since December 2009, San Isidro, San Isidro 2 and Quintero power plants operate using LNG.

 

The LNG contract is the largest supply contract and is based on long-term agreements between us and Quintero LNG Terminal for regasification services and British Gas for supply. Our LNG Sale and Purchase Agreement is in force through 2030 and is indexed to the Henry Hub/Brent commodity prices. During 2018, the Quintero LNG Terminal unloaded 44 shipments, with a content equivalent to 3,523 million cubic meters of natural gas, of which 1,096 million cubic meters corresponded to our generation and commercialization requirements.

 

Regarding the supply of natural gas, a milestone was achieved during the last quarter of 2018. In a new environment of cooperation and promotion of energy integration by governments and private actors in Argentina and Chile, and after eleven years of interrupted gas supply, it was possible to reactivate the import of natural gas from Argentina. In this context, we signed interruptible supply agreements for natural gas with YPF and Total Austral and the corresponding export permits were obtained in Argentina, allowing the supply of natural gas to begin on December 28, 2018, to be used in the operation of the San Isidro power plant.

 

The agreement of the Nueva Renca thermal power plant that was entered into by AES Gener and subsequently by Empresa Eléctrica Santiago (currently known as Empresa de Mercado Eléctrico S.A.), allowed natural gas to be available to Nueva Renca. With this availability, the electrical energy produced by Nueva Renca, which was approximately 0.5 TWh, accounted for our electrical energy balance and helped to reduce our spot energy purchases.

 

From the point of view of gas commercialization, during 2018, we had five LNG shipment sales transactions, including the sale to Enel Trade of two LNG shipments with delivery to the United Kingdom, continuing the international trading transactions for shipments under the contract with BG Global Energy Ltda. in relevant international markets outside of Latin America.

 

In addition, we, together with ENAP and Agesa, implemented a new agreement for the export of natural gas from the Quintero LNG Terminal to Argentina with Empresa Nacional de Energía Argentina in 2018. Gas shipments totaled 90.6 million cubic meters, of which we contributed 55% of the total exported volume.

 

In 2018, the Terminal Use Agreement signed with GNL Mejillones allowed the unloading of an LNG shipment at this terminal. This agreement allowed the renewal of gas purchase agreements with important mining and industrial customers in the north of Chile, making us the main industrial gas trader in the north of Chile, in addition to having volumes of this gas available to our thermal units connected to the northern gas pipeline network (Taltal and GasAtacama).

 

In relation to the commercialization of LNG by trucks, 2018 was marked by an increase in operations, with a 30% increase compared to the 2017. During 2018, new agreements were reached that will allow the distribution of natural gas to two new cities by truck.

 

With respect to coal-based power plant operations, during 2018, 1,037 kilotons of coal were consumed by Tarapacá and Bocamina power plants. This consumption was equivalent of 2.3 TWh of energy generated by Bocamina 2, 0.6 TWh generated by Bocamina and 0.01 TWh generated by Tarapacá.

 

Generation from NCRE sources

 

Under Chilean law, electricity generation companies must derive a minimum amount of their energy sales from NCRE. This minimum amount depends on the date of execution of the sale contract and ranges from zero, for those signed prior to 2007, to 20%

 

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for those signed starting in July 2013. Currently, our Canela wind farms, Ojos de Agua mini-hydroelectric plant and 40% of the installed capacity of our Palmucho mini-hydroelectric plant qualify as NCRE facilities.

 

Electricity sales and generation

 

The SEN’s electricity sales increased 4.3% during 2018 compared to 2017, as set forth in the following table:

 

ELECTRICITY SALES PER SYSTEM (GWh)

 

 

 

Year ended December 31,

 

 

 

2018

 

2017(1)

 

2016

 

Electricity sales in the SIC

 

 

 

 

 

50,516

 

Electricity sales in the SING

 

 

 

 

 

16,960

 

Total electricity sales (SEN)

 

71,179

 

68,256

 

67,476

 

 


(1)         On November 21, 2017, the SIC and the SING were integrated into one interconnected system and resulted in the creation of SEN.

 

Our electricity sales reached 23,343 GWh in 2018, 23,356 GWh in 2017 and 23,689 GWh in 2016, which represented a  32.8%, 34.2% and 35.1% market share, respectively. The energy purchases to comply with our contractual obligations to third parties decreased by 5% in 2018 when compared to 2017, primarily due to lower energy available under the contract with Nueva Renca, which is included in this total.

 

The following table sets forth our electricity generation and purchases:

 

ELECTRICITY GENERATION AND PURCHASES (GWh)

 

 

 

Year ended December 31,

 

 

 

2018

 

2017

 

2016

 

 

 

(GWh)

 

% of
Volume

 

(GWh)

 

% of
Volume

 

(GWh)

 

% of
Volume

 

Electricity generation

 

17,373

 

74.4

 

17,073

 

73.1

 

17,564

 

74.1

 

Electricity purchases

 

5,970

 

25.6

 

6,283

 

26.9

 

6,125

 

25.9

 

Total

 

23,343

 

100

 

23,356

 

100

 

23,689

 

100

 

 

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

 

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

 

In 2018, 2017 and 2016, we had 294, 152 and 46 customers, respectively. This significant increase in 2018 is mainly due the increase in the number of unregulated customers. Regulated customers of a certain size may exercise their option to become unregulated customers in order to benefit from the current market situation, which offers lower prices than would be paid as regulated customers. In 2018, our customers included 20 regulated customers and 272 unregulated customers.

 

Our generation contracts with unregulated customers are generally on a long-term basis and typically range from five to fifteen years. Such contracts are usually automatically extended at the end of the applicable term, unless terminated by either party upon prior notice. Contracts with unregulated customers may also include specifications regarding power sources and equipment, which may be provided at special rates, as well as provisions for technical assistance to the customer. We have not experienced any supply interruptions under our contracts. If we experienced a force majeure event, as defined in the contract, we are allowed to reject purchases and we have no obligation to supply electricity to our unregulated customers. Disputes are typically subject to binding arbitration between the parties, with limited exceptions.

 

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For the year ended December 31, 2018, our principal distribution customers were (in alphabetical order): Enel Distribution. Grupo CGE, Grupo Chilquinta and Grupo Saesa.

 

Our principal unregulated customers were (in alphabetical order): Compañia Minera Doña Inés de Collahuasi SCM, Enel Distribution, Empresa CMPC S.A., Minera Valle Central S.A. and SCM Minera Lumina Copper Chile.

 

We compete in the SEN primarily with three generation companies, AES Gener, Colbún S.A. (“Colbún”) and Engie.

 

Electricity generation companies compete largely based on price, technical experience and reliability. In addition, because 55% of our installed capacity connected to the SEN is hydroelectric, we have lower marginal production costs than companies whose installed capacity is primarily thermal. Our installed thermal capacity benefits from access to gas from the Quintero LNG Terminal. However, during periods of extended droughts, we may be forced to buy more expensive electricity from thermal generators at spot prices in order to comply with our contractual obligations.

 

ELECTRICITY INDUSTRY STRUCTURE AND REGULATORY FRAMEWORK

 

1. Overview and Industry Structure

 

In the Chilean Electricity Market, there are four categories of local agents: generators, transmitters, distributors and large customers.

 

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

 

 

The Chilean electricity sector is physically divided into three main networks, the SEN and two smaller isolated networks (Aysén and Magallanes). The SEN was created after the integration of the SIC and the SING that took place in November 2017 and extends from Arica in the north to Chiloé in the south. The CEN (Coordinador Eléctrico Nacional), a centralized dispatch center, coordinates the SEN’s operation. Until the interconnection of the SIC and SING in 2017, each system was coordinated by its respective dispatch center, the CDEC-SIC and the CDEC-SING.

 

The industry’s three business segments: generation, transmission and distribution, must operate in an interconnected and coordinated manner in order to supply electricity to final customers at the minimum cost and within the standards of quality and security required by the industry’s rules and regulations.

 

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i)                                        Generators:

 

Generators supply electricity to end customers using the lines and substations that belong to transmission and distribution companies. The generation segment operates competitively and does not require a concession granted by the authority. Generators may sell their energy to unregulated customers, and to other generation companies through contracts at freely negotiated prices, or they may sell to distribution companies to supply regulated customers through contracts governed by bids.

 

The operation of electricity generation companies is coordinated by the CEN, with an efficiency criterion in which the lowest cost producer available is usually required to satisfy demand at any moment in time. Any differences between electricity production and generators’ contracted sales are sold in the spot market at a price equal to the hourly marginal cost of the system.

 

ii)                                    Transmitters:

 

Transmission companies own lines and substations with a voltage above 23 kV flowing from generators’ production points to the centers of consumption or distribution, charging a regulated toll for the use of their installations. The transmission segment is a natural monopoly subject to special industry regulations, including antitrust legislation. Tariffs are regulated, and access must be open and guaranteed under nondiscriminatory conditions.

 

iii)                                Distributors:

 

Distribution companies supply electricity to end customers using electricity infrastructure with less than 23 kV. The distribution segment is a natural monopoly subject to special industry regulations as well, including antitrust legislation. The electricity network is open access and tariffs of distribution are regulated. Distribution companies have the obligation to provide electricity to the regulated customers within their concession area and at regulated prices. They may sell to unregulated customers through contracts at freely negotiated prices.

 

Furthermore, customers are classified according to their demand as “regulated” or “unregulated”. Certain customers have the choice to be either regulated or unregulated, and therefore subject to the respective price regime. Demand requirements to qualify as regulated or unregulated customer are described below under “— 3. Generation Segment — Dispatch, Customers and Pricing”.

 

2. Electricity Law and Authorities

 

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

 

Since its inception, the Chilean electricity industry has been developed primarily by private sector companies. However, nationalization by the government was carried out between 1970 and 1973. During the 1980s, the sector was reorganized through the Chilean Electricity Law, known as Decreto con Fuerza de Ley DFL 1 (“DFL 1”), allowing for the renewed participation of the private sector.

 

The industry is currently governed by the electricity law Ley General de Servicios Eléctricos No. 20,018 and its modifications, under the Electricity Law, known as Decreto con Fuerza de Ley DFL 4 (“DFL 4”), the restated DFL 1, published in 2006 by the Ministry of Economy and its respective Regulations included in Decreto Supremo D.S. No. 327/1998.

 

The Ministry of Energy is the main authority in the energy industry since February 1, 2010. The Ministry of Energy elaborates and coordinates plans, policies and standards for the proper operation of the sector and the development of the industry in Chile.

 

The National Energy Commission (“CNE”, in its Spanish acronym) and the Superintendence of Electricity and Fuel, “SEF,” are also relevant industry authorities. They report to the Ministry of Energy.

 

The CNE is the entity in charge of approving the annual transmission expansion plans, elaborating the indicative plan for the construction of new electricity generation facilities and proposing regulated tariffs to the Ministry of Energy for approval. The SEF inspects and oversees compliance with the law, rules regulations and technical norms applicable to electricity generation, transmission and distribution, liquid fuels and gas.

 

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The Energy Sustainability Agency was created in 2018 and replaced the Energy Efficiency Agency that is in charge of promoting energy efficiency.

 

Additionally, the law provides for a “Panel of Experts,” whose main responsibility is to acts as a court, issuing enforceable resolutions in disputes related to subjects referred to by DFL 4, and other electricity related laws. This panel is comprised of professional experts, all of whom are elected every six years by the antitrust government agency, Tribunal de la Libre Competencia (“TDLC” in its Spanish acronym).

 

The CEN is an independent entity in charge of coordinating the operation of the electricity system with the following objectives:

 

i)                                         maintain service security;

 

ii)                                      guarantee the efficient operation of the facilities connected to the system; and

 

iii)                                   guarantee open access to all transmission networks.

 

The CEN’S main activities include:

 

a)                                     coordination of electricity market operations;

 

b)                                     authorization of connections;

 

c)                                      ancillary services management, implementation of information systems available for the public; and

 

d)                                     monitor competition and payments, among others.

 

The CEN performs the calculation of market balances (energy injections and withdrawals), determines the transfers among generation companies and calculates the hourly marginal cost, which is the price at which energy transfers are carried out in the spot market. However, the CEN does not calculate the prices of generation capacity. Such prices are calculated by the National Energy Commission or CNE.

 

Limits on Integration and Concentration

 

The antitrust legislation established in DFL 211 (modified by Law No. 20,945 in 2016) and the regulations applicable to the electricity industry stated in DFL 4 and Law No. 20,018, have established the criteria to avoid economic concentration and abusive market practices in Chile.

 

Companies can participate in the different market segments (generation, distribution, transmission) to the extent that they are appropriately separated, both from an accounting perspective and a corporate perspective according to the requirements established in DFL 4 and Law No. 20,018 and the antitrust law DL 211 referred to above, in addition to complying with the conditions established in Resolution No 667/2002, listed below.

 

The transmission sector is subject to the greatest restrictions, mainly because of its open access requirements. DFL 4 sets limits to the shareholdings of generation and distribution companies in companies that participate in the national transmission segment of the transmission system.

 

The owners of the National Transmission System (“STN” in its Spanish acronym) must be constituted as limited liability stock corporations.  Individual interests in the STN by companies operating in another electricity or unregulated customer segment cannot exceed, directly or indirectly, 8% of the total investment value of the STN.  The aggregate interest of all such agents in the STN cannot exceed 40% of the total investment value.

 

According to the Electricity Law, there are no restrictions on market concentration for generation and distribution activities.  However, Chilean antitrust authorities have imposed certain measures to increase transparency associated with us and our subsidiaries, through Resolution 667 issued by the TDLC.

 

Resolution 667 states that:

 

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·                       electricity generation and distribution activities cannot be merged. For instance, Enel Chile must continue to keep both business segments separate and manage them as independent business units; and

·                       we, Enel Generation and Enel Distribution are registered with the CMF and must remain subject to the regulatory authority of the CMF and comply with the regulations applicable to publicly held stock corporations, even if any of these companies should lose such designation;

·                       members of the Board of Director must be elected from different and independent groups;

·                       the external auditors of the companies must be different for local statutory purposes.

 

In addition, the Water Utility Services Law also sets restrictions on the overlapping of different utility concessions in the same area, setting restrictions on the ownership of the property for water and sewage service concessions and utilities that are natural monopolies, such as electricity distribution, gas or home telephone networks.  By way of example, an electricity distribution company and a water utility company that belong to the same owner cannot operate in the same concession area.

 

3. Generation Segment

 

The generation segment is comprised of companies that own electricity generation power plants. They operate under market-driven conditions delivering their electricity to end customers through transmission and distribution networks. Generation companies freely determine whether to sell their energy and capacity to regulated or unregulated customers, but the operation of their power plants is determined by the CEN. The surplus or deficit between the generation company’s electricity sales and production is sold or purchased, as the case may be, to other generators at the spot market price.

 

Law No. 20,257 was issued in 2008 to promote the development of NCRE generation. In Chile, NCRE refers to power from wind, solar, geothermal, biomass, ocean (movement of tides, waves and currents, as well as the ocean’s thermal gradient) and mini-hydro plants under 20 MW.

 

Law No. 20,257 required generators, between 2010 and 2014, to supply at least 5% of their total contracted sales with NCRE sources and progressively increases that percentage by 0.5% a year beginning in 2015 with the aim of reaching 10% by 2024. In 2013, Law No. 20,698, modified the previously defined NCRE source minimum requirements, establishing a mandatory 20% share of NCRE source as a percentage of total contracted energy sales by 2025, but allowing contracts signed between 2007 and 2013 to maintain the 10% target by 2024.

 

Dispatch, Customers and Pricing

 

Generation companies may sell to distribution companies, unregulated end customers or to other generation companies through contracts. Generation companies satisfy their contractual sales requirements with dispatched electricity, whether produced by them or purchased from other generation companies in the spot market or through contracts. They balance their contractual obligations with their dispatch by trading deficit and surplus electricity at the spot market price, which is set hourly by the CEN, based on the lowest cost of production of the last kWh dispatched.

 

The CEN operates the electricity system with an approach that minimizes operating costs, while monitoring the quality of the service provided by the generation and transmission companies. To minimize operating costs, it applies an efficiency criterion in which the lowest cost producer available is usually required to satisfy demand at any moment in time. As a result, at any specific level of demand, the appropriate supply will be provided at the lowest possible production cost available in the system. This marginal cost on an hourly basis is the price at which generators trade energy in the spot market, both their injections (sales) and their withdrawals (purchases) to balance their contracted customer sales to their production determined by the CEN.

 

The customers of generation companies are classified by the electricity capacity demand required, explained as follows:

 

i)                                         Unregulated customers: Customers who demand over 5,000 kW of capacity, mainly industrial and mining companies. These customers freely negotiate their electricity supply prices with generators and/or distributors. This customer category also includes those who demand between 500 and 5,000 kW of capacity that have the option to choose between the unregulated regime and the regulated regime and choose the unregulated regime.

 

ii)                                      Distribution companies: Distributors distinguishing between the energy they require to satisfy their regulated customers from their unregulated customers. In the former case, distributors purchase energy from generation companies through an open bid process regulated by the CNE, while they freely negotiated bilateral contracts with unregulated customers.

 

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iii)                                   Generation companies trading on the spot or short-term market: The energy and capacity transactions between generation companies arise from the difference between the electricity produced by a generator, as determined by the CNE, and the contractual obligations of that generator with its customers. The price of energy traded on the spot market is the hourly marginal cost of the system and the price of capacity traded on the spot market at a certain node.

 

Each generator receives a capacity payment set by the CEN based on the generation capacity of each power plant and the available primary resource. This capacity payment replaces the previous “firm capacity” concept. It continues to depend primarily on the availability of such facility, the type of power plant technology, and the resources used to generate. It is the maximum capacity a generator may supply to the system at certain peak hours, considering statistical information, accounting for maintenance time and extremely dry conditions for hydroelectric power plants, but differs from firm capacity because it does not consider the power plants’ contribution to the security of the entire system.

 

Generation costs are passed on to distributors’ regulated end consumers through the “average node price,” which corresponds to a single price determined for each distributor by the CNE, considering the weighted average prices of their current supply contracts for regulated customers. The average node price is adjusted in three instances: (1) every six months, in January and July of each year, based on local and international indexes; (2) upon the entry of a new supply contract with any distribution company; and (3) upon indexation of a supply contract in more than 10%.

 

Rationing

 

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

 

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

 

Water Rights

 

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

 

The Chilean Constitution considers water as a national public good in which real utilization rights are defined. It is similar to holding private property rights over water, as set forth in article 19, paragraph 24: “The rights of individuals over water, recognized or constituted in accordance with the law, grant their holders ownership over such rights.” Notwithstanding the foregoing, paragraph 24 also specifies legal limitations to those water rights.

 

The Chilean Congress is currently discussing amendments to the Water Code with the objective of making water use for human consumption, household subsistence and sanitation a high priority.

 

On November 22, 2016, the Chilean House of Representatives approved an amendment that is being evaluated by the Water Resources, Desertification and Drought Commission of the Chilean Senate. The main aspects of the amendments are as follows:

 

·                      Granting of new water rights, which would be limited to a maximum period of 30 years, extendable over future terms, unless the Water Authority proves the non-use of the resources. The extension would be effective only for used water rights.

·                      The expiration of new non-consumptive water rights that were granted by law, if the holder does not exercise the right of use within eight years.

·                      The expiration of new non-consumptive water rights already granted, if the user does not effectively use the rights within a period of eight years from the date of enactment of the new Water Code. The term can be extended for up to four years only in justified cases such as delays in obtaining permits or environmental approvals.

 

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In January 2019, the President modified this amendment to state that the water rights have an unlimited duration.

 

4. Transmission Segment

 

The transmission segment supplies electricity over lines or substations with a voltage or tension higher than 23 kV from generators’ production points to the centers of consumption or distribution. Transmission systems are comprised of the electricity lines and substations that are not considered part of the distribution network.

 

Given the structural characteristics of the transmission segments, it is subject to special electricity industry regulation. Tariffs are regulated, and access must be open guaranteed under nondiscriminatory conditions.

 

Law No. 20,936 published in July 2016 established a new regulatory framework for all electricity transmission systems in Chile, redefining the system into the following segments: National, Development Poles, Zonal, Dedicated, and International.

 

National and Zonal Transmission Systems planning is a centralized, regulated process carried out by the CEN that annually issues an expansion plan to be approved by the CNE.

 

The expansion of both systems is granted through an open tender process that distinguishes new installations from enlargement of existing installations. The tenders carried out for new installations grant the winner ownership of the installation to be built. The expansion of existing installations, on the other hand, belongs to the owner of the original installation, who is obliged to tender the construction of the required expansion.

 

The remuneration of existing national and zonal transmission installations is determined by a tariff setting process performed every four years. This process determines the Annual Transmission Value that considers efficient operation and maintenance costs and an annual valuation of investments that is based on a discount rate determined by the authority every four years (minimum 7% after tax) and the useful life of the installations.

 

The remuneration of expansions is the value resulting from the respective bid of such expansion for the first 20 years of operations. From year 21 on, such expansion is considered an existing installation and remunerated accordingly.

 

Regulation currently in force states that transmission remuneration is the sum of tariff revenue and usage charge revenue, received for use by the transmission system defined as $/kWh by the CNE.

 

Finally, in the case of a failure in electricity transmission, Law No. 20,936 defines the penalty conditions for the responsible company (transmission, generation or other).

 

Transmission Tariffs

 

Law No. 20,936 introduced changes to the transmission tariff setting process. In transitioning to the implementation of the new law, the current zonal transmission tariff setting process continued as stated by transitory Article No. 20 of Law No. 20,936. The tariff setting process for the 2018-2019 period concluded in October 2018 and has been effective retrospectively since January 1, 2018. The 2020-2023 tariff setting process is now in progress.

 

5. Distribution Segment

 

The distribution segment is comprised of electricity infrastructure with a voltage lower than 23 kV to supply electricity to end customers. Electricity distribution is considered a natural monopoly and companies therefore operate under a public utility concession regime, with service obligations and regulated tariffs for supplying regulated customers. They may sell to unregulated customers at negotiated prices.

 

Customers are classified according to their demand as regulated or unregulated. Regulated customers are those whose connected capacity is below or equal to 5,000 kW and unregulated customers are those whose connected capacity is at least 5,000 kW. Customers with connected capacity between 500 kW and 5,000 kW may choose to be regulated or unregulated, subject to the respective price regime. Clients who choose one category must remain at least four years in the option chosen.

 

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Customers subject to the unregulated price regime may negotiate their electricity supply with any generator or distributor, although they must pay a regulated toll for using the distribution network.

 

Regulated customers with residential generation can sell their surpluses to the distribution company, under certain conditions (regulation of net billing). Since November 2018, Law No. 21,118 permits customers with connected capacity up to 300kW to sell their surpluses.

 

Distribution concessions are given by the Chilean Ministry of Energy for an undefined period and give the right to use public areas for building distribution lines. Distribution companies have the obligation to supply electricity to regulated customers that request service within their concession area, except for customers that have chosen the unregulated regime. A concession may be declared expired if the quality of service does not meet certain minimum standards.

 

Regarding the supply of electricity to regulated customers, DFL 4 establishes that distribution companies must permanently have electricity supply available. They must contract their energy supply through open, non-discriminatory and transparent public tenders. These bidding processes are managed by the CNE and are based on distribution companies’ projections of energy demand. They are carried out at least five years in advance from the expected effective date of the energy supply contract, which has a 20-year term. In case of unforeseen deviations in the projections of demand, the regulator has the authority to carry out short term tenders. There is also a regulated mechanism to remunerate supply not covered by a contract if this were to take place.

 

The latest tender was carried out in 2017. A total 2,200 GWh/year were awarded for the period from January 1, 2024, to December 31, 2043, at an average price of 32.5 US$/MWh, which must be completely sourced from NCRE. For further detail on the outcome of tenders, please see “Item 4. Information on the Company — B. Business overview.”

 

Distribution Tariffs

 

The Chilean distribution tariff model has gone through nine tariff setting process since its privatization in the 1980s.

 

Tariffs charged by distribution companies to end regulated customers are set every four years. Tariffs are determined by the sum of the cost of electricity purchased by the distribution company, a transmission charge and the Value Added from Distribution of electricity (“VAD”), which allows distribution companies to recover their investment and operating costs, including a return on investment, which is set by law. The transmission charge reflects the cost paid for electricity transmission and transformation.

 

The VAD is based on a so-called “efficient model company” within a Typical Distribution Area (“TDA”). It considers the cost of building and operating the company at the minimum cost, fulfilling quality and safety standards of a company within that TDA. Therefore, the CNE classifies all distribution companies according to their TDA, then selects one distribution company from each TDA and estimates its cost as an efficient model company. Distribution companies also carry out their own studies to determine the costs of such company as the efficient model company. Cost estimates include fixed costs, average energy and capacity losses, standard investment costs, and operation and maintenance costs. The annual investment costs are calculated considering the Replacement Cost (“VNR” in its Spanish acronym) of the installations, useful life and a 10% return on assets associated with electricity investments.

 

The VAD of each TDA is determined as a weighted average with one third of the value estimated by the study of the companies and two thirds by the CNE. Preliminary tariffs, with the resulting VAD, are tested to ensure that they provide an industry aggregate rate of return between 6% and 14%.

 

The real return on investment for a distribution company depends on its actual performance relative to the standards chosen by the CNE for the efficient model company. The tariff system allows for a greater return to distribution companies that are more efficient than the model company.

 

Electricity regulation establishes tariff equality mechanisms for electrical services. Law No. 20,928 states that the maximum tariff that distribution companies may charge residential customers must not exceed the average national tariff by more than 10%. The differences arising from the application of this mechanism will be progressively absorbed by the remaining customers subject to regulated prices that are under the mentioned average, except for those residential users whose monthly average consumption of energy in the prior calendar year is lower than or equal to 200 kWh.

 

Additionally, Chilean law provides that transitory subsidies can be granted if the residential customer tariff increases by 5% or more within a six-month period. This subsidy is conferred by the state, its application is a faculty of the government and the last one was granted in 2009.

 

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The tariff setting process for 2016-2020 concluded in August 2017 and had been in effect, retroactively, since November 4, 2016. On December 18, 2017, CNE published a resolution that set the Technical Standard of Quality of Service for Distribution Systems. The Distribution System Technical Service Quality Standards established higher technical and commercial standards, including electricity supply reliability indicators, such as the System Average Interruption Frequency Index (SAIFI), which measures the average number of times a customer’s supply is interrupted in a year; and the System Average Interruption Duration Index (SAIDI), which measures the total number of minutes, on average, that a customer is without electricity in a year, among others. This resolution also refers to product quality, metering, monitoring and controlling and commercial service quality. In this context, in September 2018, there was an extraordinary tariff update process. This updated tariff is non-retroactive and will be effective until the next tariff setting process.

 

Distribution companies may be required to compensate end customers in the case of electricity shortages that exceed the authorized standards. These compensatory payments are equal to double the amount of electricity the distribution company failed to provide, using a rate equal to the “failure cost.” In addition, distribution companies are subject to the provisions of the SEF, in particular to in its articles 15 and 16 of the Law No. 18,410, in which different infractions are listed and classified according to their severity and associated fines.

 

Distribution-Related Services

 

Distribution-related services are services identified by the TDLC as subject to regulation, such as meter rentals and meter verification, among others. The tariffs of these services are set every four years by the CNE along with the VAD calculation. On March 14, 2014, the Ministry of Energy published the prices for distribution-related services, which are currently still effective.

 

The tariff setting process for the distribution related services for the 2016-2020 period concluded in July 2018. The new tariff is non-retroactive and will be in effect until the next tariff setting process.

 

6. Environmental Regulation

 

Chile has numerous laws, regulations, decrees and municipal ordinances that address environmental considerations. Among them are regulations relating to waste disposal (including the discharge of liquid industrial wastes), the establishment of industries in areas that may affect public health, and the protection of water for human consumption.

 

Environmental Law No. 19,300 was enacted in 1994 and has been amended by several regulations, including the Environmental Impact Assessment System Rule issued in 1997 and modified in 2001. This law establishes a general framework of regulation of the right to live in a pollution-free environment, the protection of the environment, the preservation of nature and the conservation of environmental heritage. It also regulates environmental management instruments such as the Strategic Environmental Assessment, the Environmental Impact Assessment System and Access to Environmental Information, the Environmental Damage Liability, the Enforcement and the Environmental Protection Fund and the environmental institutional framework of Chile. This law requires companies to conduct an environmental impact study and a declaration of any future generation or transmission projects.

 

In January 2010, Law No. 19,300 was modified by Law No. 20,417, and introduced changes to the environmental assessment process and in the public institutions involved, principally creating the Chilean Ministry of Environment and the Superintendence of Environment. Environmental assessment processes are coordinated by this entity and by the Environmental Assessment Service (SEA).

 

The Ministry of the Environment is in charge of the management, protection and application of policies in environmental matters, whose mission is to lead sustainable development, through the generation of efficient public policies and regulations, by promoting good practices that improve citizen environmental education. This Ministry works in the recovery of air quality in urban centers, the management of natural resources and biodiversity, the proper final disposal of solid waste, climate change and protection of water resources, and environmental education and citizen participation.

 

The SEA is in charge of guarding the regulatory integrity within the framework of the environmental impact assessment of the projects, while the Superintendence of Environment monitors compliance with the environmental qualification, standards and plans.

 

In June 2011, the Ministry of Environment published Decree 13, which establishes emission standards for thermoelectric plants applicable to generation units of at least 50 MW. The objective of this regulation is to control atmospheric emissions of particulate matter (MP), nitrogen oxides (NOx), sulfur dioxide (SO2) and mercury (Hg), to prevent and protect the health of the population and

 

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protect the environment. Existing emission sources are required to meet emission limits as established in the regulation for MP emissions and for SO2 and NOx emissions by June 2015 in highly polluted areas and by June 2016 elsewhere.

 

In June 2012, Law No. 20,600 created the Environmental Courts, special jurisdictional courts subject to the control of the Chilean Supreme Court. Their primary function is to resolve environmental disputes within their jurisdiction and investigate other matters that are submitted for their attention under the law. The law created three such courts, all of which are in operation.

 

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

 

On September 10, 2014, Law No. 20,780 was enacted and included charges for the emission of MP, NOx, SO2 and CO2 into the atmosphere. For CO2 emissions, the charge is US$ 5 per emitted ton (not applicable to renewable biomass generation). MP, NOx and SO2 emissions will be charged the equivalent of US$ 0.10 per emitted ton, multiplied by the result of a formula based on the population of the municipality where the generation plant is located and an additional fee of US$ 0.90 per ton of MP emitted, US$ 0.01 per ton of SO2 emitted and US$ 0.025 per ton of NOx emitted. This tax became effective in 2018, with the amount due calculated based on the previous year’s emissions.

 

In 2017, authorities published Exempt Resolution No. 659 related to the implementation of Article No. 8 of Law No. 20,780 regarding taxes on thermal electric power plant emissions as a result of the country’s latest tax reform.

 

All our thermal plants and our subsidiary GasAtacama have established methodologies to measure emissions and pay related taxes, in line with the requirements of the Environmental Superintendence of Chile.

 

Regarding biodiversity, on January 5, 2018, the Chilean Sustainable Development Board approved the 2017-2030 National Biodiversity Strategy. This strategy replaces the existing national strategy adopted in 2003. The new strategy identifies five objectives related to the sustainable use of biodiversity, and the development of the institutions and regulation required for the sustainable management of ecosystems.

 

7. 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 Enel, an Italian company and our ultimate controlling shareholder. Enel Chile, our controlling shareholder, owned 93.6% of our shares, and Enel beneficially owned 61.9% of Enel Chile as of December 31, 2018. 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 35 countries across five continents, produces energy through a managed installed capacity over 89 GW, which includes 43 GW of renewable sources, and distributes electricity and gas through a network covering 2.2 million kilometers. With over 73 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enel shares trade on the Milan Stock Exchange.

 

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Enel Generation Chile’s Organizational Chart (1)

As of December 31, 2018

 

 


(1)         Only principal operating subsidiaries are presented here. The percentage listed in the box for each of Enel Generation’s consolidated subsidiaries represents its economic interest in such consolidated subsidiary.

(2)         Excluding treasury stock.

 

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We consolidated the companies listed in the following table as of December 31, 2018. In the case of subsidiaries, our economic interest is calculated by multiplying our percentage of 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 Companies

 

% Economic
Ownership of Each
Main

Subsidiary by
Enel Generation

 

Consolidated Assets
of Each Main
Subsidiary on a
Stand-alone Basis

 

Revenues and
Other Operating
Income of Each
Main
Subsidiary on a
Stand-alone Basis

 

 

 

(in%)

 

(in billions of Ch$)

 

 

 

Pehuenche

 

92.7

 

231

 

163

 

GasAtacama(1)

 

97.4

 

757

 

271

 

 


(1)                  Includes Central Eólica Canela S.A and Gasoducto Atacama Argentina S.A. On November 1, 2016, Celta was merged into GasAtacama, which was the surviving company. GasAtacama has been fully consolidated since May 2014.

 

Principal Subsidiaries

 

GasAtacama

 

GasAtacama is a generation company located northern Chile, which owns and operate a four-unit combined-cycle power plant with a total installed capacity of 732 MW and a gas pipeline, which connects to Argentina. In April 2014, we acquired a 50% ownership interest in Inversiones GasAtacama Holding Ltda. (“GasAtacama Holding”) and as a result, we owned a controlling equity interest in GasAtacama Holding.

 

Since the second half of 2016, we have been carrying out a corporate simplification process, which mainly involved mergers. During 2016, GasAtacama Holding merged into Celta, which later merged into GasAtacama, the surviving company, on November 1, 2016. On November 9, 2017, GasAtacama purchased the 25% minority interest of Central Éolica Canela S.A. On December 22, 2017, Central Éolica Canela S.A. was dissolved subsequent to the sale of its assets to GasAtacama on November 21, 2017.

 

As of December 31, 2018, GasAtacama owned the following power plants: Tarapacá, San Isidro, Pangue, Canela I and II and Ojos de Agua, which have an aggregate capacity of 1,110 MW.

 

We hold 97.4% of the economic interest in GasAtacama and since May 1, 2014, we have consolidated GasAtacama in our consolidated financial statements.

 

Pehuenche

 

Pehuenche, a generation company connected to the SEN, owns three hydroelectric facilities located in the hydrological basin of the Maule River, south of Santiago, with a total installed capacity of 697 MW. The 568 MW Pehuenche plant began operations in 1991, the 89 MW Curillinque plant began operations in 1993, and the 40 MW Loma Alta plant began operations in 1997. We hold 92.7% of the economic interest in Pehuenche and consolidate Pehuenche in our consolidated financial statements.

 

D.                     Property, Plant and Equipment.

 

Our property, plant and equipment are concentrated on electricity generation assets in Chile.

 

We conduct our generation business through Enel Generation and its subsidiaries, Pehuenche and GasAtacama, which together own 28 generation power plants, all located in Chile, of which 16 are hydroelectric (3,456 MW installed capacity), ten are thermal (2,738 MW installed capacity) and two are wind powered (78 MW installed capacity). The description for our generation subsidiaries, and their businesses is included in this “Item 4. Information on the Company.”

 

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 resulting from 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, all located in Chile, at the end of each year, by company and their basic characteristics:

 

Property, Plant and Equipment of Generation Companies

 

 

 

 

 

 

 

Installed Capacity(1)
As of December 31,

 

Company

 

Power Plant Name

 

Power Plant Type(2)

 

2018 (3)

 

2017

 

2016

 

 

 

 

 

 

 

(in MW)

 

Enel Generation

 

Rapel

 

Reservoir

 

376

 

377

 

377

 

 

 

Cipreses

 

Reservoir

 

106

 

106

 

106

 

 

 

El Toro

 

Reservoir

 

449

 

450

 

450

 

 

 

Los Molles

 

Run-of-the-river

 

18

 

18

 

18

 

 

 

Sauzal

 

Run-of-the-river

 

77

 

77

 

77

 

 

 

Sauzalito

 

Run-of-the-river

 

12

 

12

 

12

 

 

 

Isla

 

Run-of-the-river

 

70

 

70

 

70

 

 

 

Antuco

 

Run-of-the-river

 

319

 

320

 

320

 

 

 

Abanico

 

Run-of-the-river

 

136

 

136

 

136

 

 

 

Ralco

 

Reservoir

 

689

 

690

 

690

 

 

 

Palmucho

 

Run-of-the-river

 

34

 

34

 

34

 

 

 

Total hydroelectric

 

 

 

2,284

 

2,290

 

2,290

 

 

 

Bocamina

 

Steam Turbine/Coal

 

478

 

478

 

478

 

 

 

Diego de Almagro

 

Gas Turbine/ Diesel Oil

 

24

 

24

 

24

 

 

 

Huasco

 

Gas Turbine

 

64

 

64

 

64

 

 

 

Taltal

 

Gas Turbine/Natural Gas+Diesel Oil

 

240

 

245

 

245

 

 

 

San Isidro 2

 

Combined Cycle /Natural Gas+Diesel Oil

 

388

 

399

 

399

 

 

 

Quintero

 

Gas Turbine/Natural Gas

 

257

 

257

 

257

 

 

 

Total thermal

 

 

 

1,451

 

1,467

 

1,467

 

 

 

Total

 

 

 

3,735

 

3,757

 

3,757

 

Pehuenche

 

Pehuenche

 

Reservoir

 

568

 

570

 

570

 

 

 

Curillinque

 

Run-of-the-river

 

89

 

89

 

89

 

 

 

Loma Alta

 

Run-of-the-river

 

40

 

40

 

40

 

 

 

Total

 

 

 

697

 

699

 

699

 

GasAtacama

 

Atacama

 

Combined Cycle /Natural Gas+Diesel Oil

 

732

 

781

 

781

 

 

 

Tarapacá

 

Steam Turbine/Coal

 

158

 

158

 

158

 

 

 

Tarapacá

 

Gas Turbine/Diesel Oil

 

20

 

24

 

24

 

 

 

San Isidro

 

Combined Cycle /Natural Gas+Diesel Oil

 

379

 

379

 

379

 

 

 

Pangue

 

Reservoir

 

466

 

467

 

467

 

 

 

Canela I

 

Wind Farm

 

18

 

18

 

18

 

 

 

Canela II

 

Wind Farm

 

60

 

60

 

60

 

 

 

Ojos de Agua

 

Run-of-the-river

 

9

 

9

 

9

 

 

 

Total

 

 

 

1,842

 

1,896

 

1,896

 

Total capacity

 

 

 

 

 

6,274

 

6,351

 

6,351

 

 


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

 

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(2)                  “Reservoir” and “run-of-the-river” refer to hydroelectric plants that use the force of a dam or a river, respectively, to move the turbines that generate electricity. “Steam” refers to thermal power plants fueled with natural gas, coal, diesel or fuel oil to produce steam that moves the turbines. “Gas Turbine” or “Open Cycle” refer to thermal power plants that use either diesel or natural gas to produce gas that moves the turbines. “Combined-Cycle” refers to thermal power plants 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 2018 installed capacity differs from previous years since the CEN has reviewed the capacity of each generation unit and adjusted their capacity.

 

Insurance

 

Our electricity generation facilities are insured against damage caused by 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. Insurance policies include liability clauses, which protect our companies from claims made by third parties. 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.

 

Project Investments

 

We are continuously analyzing potential opportunities for growth. The study and profitability assessment of our project portfolio is an ongoing effort. Industry technology is allowing for smaller, less environmentally damaging power plants. These plants can be built quicker, allow greater flexibility to activate or deactivate according to system needs, and are generally preferred by the community. We are favoring renewable energy technology for our new power plant investments. We seek opportunities, either by building new greenfield projects or by modernizing existing brownfield assets and improving (operationally and/or environmentally) performance. The expected start-up for each project is assessed and is defined based on the commercial opportunities and our financing capacity to fund these projects. All of our projects are financed with internally generated funds. Below we list our most important projects under development; however, any decision related to construction will depend on commercial opportunities foreseen in the upcoming years, including future tenders for supplying the regulated market, and the evolution of the regulatory framework (mainly associated with ancillary services).

 

Budgeted amounts include connecting lines that could be owned by third parties and paid as tolls, unless otherwise indicated.

 

1.              Generation Business Projects

 

A.            Projects completed during 2018

 

Bocamina Optimization Project

 

Bocamina is a 478 MW coal-fired power plant located in Coronel in the Bíobío Region in southern Chile, which consists of two units, Bocamina I (128 MW) and Bocamina II (350 MW). Bocamina II started commercial operations in July 2013 but suspended its operations in December 2013 due to environmental injunctions. A new Environmental Impact Statement was approved in March 2015 and included a new technical optimization plan. On April 2, 2015, the Chilean Court approved the new RCA, and the plant resumed operations in July 2015, after complying with all requested conditions established in the new RCA.

 

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The technical optimization plan involves the following: (i) installation of Johnson filters for seawater intake in both units; (ii) installation of domes over the north and south coalfields; (iii) improvement of the ash dump in operation; and (iv) construction of a water treatment plant. After we finished the dome over the north coalfield, we proceeded to the construction and completion of the south dome in June 2018, achieving a storage capacity of 270,000 tons of coal.

 

The latest progress includes:

 

·         On June 15, 2018, we delivered to Major Contractor the Provisional Acceptance Certificate of South Dome.

 

·         On October 17, 2018, we received from Municipality the certificate of definitive reception of the building works for the south dome.

 

The estimated total investment is Ch$ 62,103 million, of which Ch$ 61,357 million was incurred as of December 31, 2018.

 

B.            Projects under Construction

 

B.1 Enel Generation

 

Los Cóndores Hydroelectric Project

 

The Los Cóndores project is located in the Maule Region, in the San Clemente area.  It consists of a 150 MW run-of-the-river hydroelectric power plant, with two Pelton vertical water turbine units, which will use water from the Maule Lagoon reservoir through a pressure tunnel.  The power plant will be connected to the SEN at the Ancoa substation (220 kV) through an 87 km transmission line.

 

On September 14, 2018, our Board of Directors approved an updated construction plan, with a total project investment of US$ 957.3 million, excluding contingencies. The construction activities will continue until 2020. After that, the power plant commissioning phase will follow as well as commercial operations.

 

As of December 31, 2018, 65.6% of the project was completed and 86.8% of the transmission lines were completed and assembled, according to the last approved construction plan. We expect that the estimated total investment will be Ch$ 665,986 million, of which Ch$ 419,022 million was incurred as of December 31, 2018. This project is being financed primarily with internally generated funds.

 

Sauzal Repowering

 

The Sauzal Repowering project is to be implemented within the Sauzal power plant, located in the Libertador General Bernando O’Higgins Region of central Chile. The power plant uses the water of the Cachapoal and Claro Rivers and is a run-of-the-river hydroelectric power plant with three Francis vertical units.

 

The project involves replacing two turbines with a target efficiency rate of 95%, obtaining up to 3MW of new capacity and 13.7 GWh per year. The contract was signed in July 2018 with Voith. During 2018, detailed engineering was carried out and the manufacturing of the runner parts, shaft and seals of the first unit commenced, with an overall progress of 37% as of December 2018.

 

The estimated total investment is US$ 10.5 million, of which US$ 2 million has been incurred as of December 31, 2018. This project is being financed primarily with internally generated funds.

 

Bocamina closure plan of the landfill

 

The project considers the application of the best practices for closure of similar ash dumpsite facilities. In a first stage, there will be infrastructure and operation improvements in two sectors. We expect to satisfy the environmental standard established in the Environmental Impact Assessment approved in March 2015.

 

The project is composed of two stages:

 

·                  Stage 1: Closure works of sectors one and two and a lateral one (the total area is around 48,000 m2), which we expect to complete during the second quarter of 2020.

 

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·                  Stage 2: Closure works for the remaining sector 3 at the end of the life of the power plant. This second stage does not have a commissioning date defined since it depends on several factors such as the operation of the plant and the sale of ashes.

 

Currently, the basic design is completed and the bidding process of major works is ongoing.

 

We estimate a total investment of Ch$ 6,555 million, of which Ch$ 1,668 million was incurred as of December 31, 2018.

 

C.            Projects Under Development

 

We are currently evaluating the development of the following projects, which we classify as “under development”. We will finally decide whether to proceed or not with each project depending on the commercial and other opportunities foreseen in upcoming years, and in particular, future tender prices for supplying the energy requirements of the regulated market and/or negotiations with existing or new unregulated customers.

 

C.1 Enel Generation

 

Vallecito Hydroelectric Project

 

The Vallecito hydroelectric project is located in the Maule Region, in the upper part of the Maule River basin. It consists of a run-of-the-river hydroelectric plant with an installed capacity of 55 MW. We expect to deliver energy to the SEN through the transmission line of the Los Cóndores hydroelectric plant, which we are also currently building (see above).

 

We have developed the Vallecito project based on a sustainable development plan that requires the development of technical-economic, environmental and hydroelectric social activities. We have established community-specific actions to be carried out with nine communities of the Pehuenche Route in order to incorporate social stakeholder considerations, capacity and local projects in the hydro project development plan.

 

During 2017, we developed complete basic design and environmental base line campaigns and implemented a sustainable development plan after several meetings with local communities aimed to jointly design the best-shared use for the hydro project and to obtain agreements with local communities that will be integrated in the Environmental Impact Study (“EIA” in its Spanish acronym).

 

The next steps are to finalize and prepare the EIA that will include collaborative agreements with communities directly related to the project. Based on current market conditions and future commercial options, we will eventually decide whether to continue to undertake the development of this project. The current plan contemplates commencing construction during 2020 and commissioning to take place in 2023. We estimate a total investment of Ch$ 127,357 million, of which Ch$ 9,159.6 million was incurred as of December 31, 2018.

 

Smart Repowering Projects

 

Within the context of projects under development, we are analyzing the following three Smart Repowering projects to increase the installed capacity or electricity generation, or both, of power plants already in operations by upgrading some components or improving the hydraulic potential of the plant, or both.

 

Antuco Repowering

 

The Antuco Repowering project is to be implemented within the Antuco operating power plant, located in Biobío Region in southern Chile. The project involves replacing one turbine installed in 1981 with an 88% load factor, with a new turbine with a target efficiency rate of 94%, obtaining 21 GWh of new energy. We estimate total investments of US$ 14.5 million, none of which has been incurred as of December 31, 2018, and we expect to begin operations in the second half of 2020.

 

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Quintero Combined-Cycle Project

 

The Quintero project is located in the Valparaíso Region and consists of an energy efficiency project that takes advantage of the heat of the gases emitted by the existing turbines to produce steam through the installation of a steam turbine and a generator, which allows converting the existing open cycle plant into a combined-cycle gas plant. Currently, the Quintero plant has two gas turbines with a total capacity of 257 MW. With the addition of a steam turbine unit of 130 MW capacity, the Quintero plant would reach a total capacity of 387 MW. We would deliver the produced energy to the SEN through the existing Quintero-San Luis line, a simple 220 kV circuit built to evacuate the energy of the combined-cycle power plant.

 

In 2017, we started the preparation of the environmental impact study and the implementation of the sustainability plan. However, during August 2018, the Quintero and Puchuncaví areas suffered an environmental crisis leaving more than 300 people suffering the toxic effects allegedly associated with gas emissions of other industries. As a result, the project was indefinitely postponed and the environmental impact study has been suspended.

 

The estimated total investment for the project is Ch$ 150,651 million, of which Ch$ 2,858 million was incurred as of December 31, 2018.

 

Ttanti Combined-Cycle Project

 

The Ttanti project is located in the Antofagasta Region, on land adjacent to the existing Atacama power plant that is located in the industrial zone of the city of Mejillones. The project consists of the construction of a natural gas combined-cycle power plant with an aggregate installed capacity of 1,290 MW (430 MW for each of the three units), and one unit would be able to use diesel oil as a backup in case of a shortage of natural gas. The power plant would connect to the SEN through a 0.5 km 220 kV double circuit transmission line to the Atacama substation, which would be expanded for this purpose.

 

The environmental permit, requested through an Environmental Impact Assessment, was approved in December 2017 by the Environmental Evaluation Service (“SEA” in its Spanish acronym) of the Antofagasta Region. Any decision related to the construction of the project will depend primarily on the commercial opportunities foreseen in the upcoming years (prices in future tenders and/or negotiations with unregulated customers, among other factors).

 

The estimated total investment for the first unit is Ch$ 251,078 million, of which Ch$ 1,319 million was incurred as of December 31, 2018.

 

Taltal Combined-Cycle Project

 

The Taltal project consists of the construction of a steam turbine for converting the existing Taltal gas-fired open cycle plant to a combined-cycle plant by adding a turbine in the vapor phase, which would use the steam generated by the gas turbines’ heat emissions to produce energy, which will considerably improve its efficiency. The Taltal power plant is located in the Antofagasta Region. Currently, the existing Taltal power plant has two gas turbines with 120 MW installed capacity each. The steam turbine would add 130 MW and therefore, the Taltal power plant would reach a total capacity of 370 MW. We will supply the produced energy to the SEN through the existing 220 kV double circuit Diego de Almagro — Paposo transmission line.

 

The environmental permit, requested through an Environmental Impact Statement submitted in December 2013, was approved in January 2017. Any decision related to the construction of the project will depend primarily on the commercial opportunities foreseen in the upcoming years (prices in future tenders and/or negotiations with unregulated customers, among others).

 

The estimated total investment is Ch$ 136,998 million, of which Ch$ 2,873 million was incurred as of December 31, 2018.

 

Taltal Battery Energy Storage System

 

The project consists of the installation of a battery energy storage system (BESS) in the Taltal power plant to provide ancillary services in upcoming years.

 

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The project would reach an installed capacity of 12 MW and 12 MWh of energy storage, connected to the 15 kV bar of one of the existing 120 MW turbines installed in the Taltal power plant.

 

In May 2018, the Antofagasta Region SEA issued the resolution waiving the obligation to submit the project to environmental assessment before its construction. Any decision related to the construction of the project will depend primarily on the commercial opportunities foreseen in the upcoming years and, particularly, on the evolution of the regulatory framework for the provision and remuneration of the ancillary services, currently under elaboration by the authority.

 

The estimated total investment is Ch$ 8,119 million, of which Ch$ 15.1 million was incurred as of December 31, 2018.

 

Tarapacá Battery Energy Storage System

 

The project consists of the installation of a BESS in the Tarapacá power plant to provide ancillary services in upcoming years. The BESS has about 14 MW of installed capacity and 14 MWh of energy storage, and will be connected to the 11.5 kV bar of the existing 23 MW turbine installed in the Tarapacá power plant.

 

In December 2017, the SEA of the Tarapacá Region issued the resolution waiving the obligation to submit the project to environmental assessment before its construction. Any decision related to the construction of the project will depend on the commercial opportunities foreseen in the upcoming years and particularly on the evolution of the regulatory framework for the provision and remuneration of the ancillary services, currently under elaboration by the authority.

 

The estimated total investment is Ch$ 9,427 million, of which Ch$ 80.5 million was incurred as of December 31, 2018.

 

Major Encumbrances

 

As of December 31, 2018, we have full ownership of our assets and they are not subject to material encumbrances.

 

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 audited consolidated financial statements and the notes thereto, included in Item 18 in this Report, and “Selected Financial Data,” included in Item 3 herein. Our consolidated financial statements as of December 31, 2018, and 2017 and for each of the years in the three-year period ended December 31, 2018, have been prepared in accordance with IFRS, as issued by the IASB.

 

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

 

We own and operate electricity generation plants in Chile. Our consolidated revenues, income and cash flows come from our core business, electricity generation.

 

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 may materially affect our financial results. In addition, our results from operations and financial condition are affected by variations in the exchange rate between the Chilean peso and the U.S. dollar. We have certain critical accounting policies that affect our consolidated operating results. The impact of these factors on us, for the years covered by this Report, is discussed below.

 

a.     Hydrological Conditions

 

A substantial part of our generation capacity is hydroelectric and depends on the prevailing hydrological conditions. Our installed capacity as of December 31, 2018, 2017 and 2016 was 6,274 MW, 6,351 MW and 6,351 MW, of which 55% was hydroelectric for the three years. See “Item 4. Information on the Company — D. Property, Plant and Equipment.”

 

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Hydroelectric generation was 10,974 GWh, 9,652 GWh and 9,078 GWh in 2018, 2017 and 2016, respectively. Our 2018 hydroelectric generation was greater than 2017, showing similar path of what occurred in 2017 and 2016. The increase was mainly due to the slight increase in total fluvial energy and rainfalls. Although there was little rain, hydrological conditions were more humid and intense, especially during the last quarter of 2017. Additionally, some important reservoirs have been at low levels since 2010 due to several years of drought, characterized by low rainfalls and a poor snowmelt.

 

Hydrological conditions in Chile can range from very wet, as a result of several years of abundant rainfall and lakes at their peak capacity, to extremely dry, as a consequence of prolonged droughts lasting for several years, the partial or material depletion of water reservoirs and the significant reduction of snow and ice in the mountains, which in turn leads to materially lower levels of available water as a consequence of lower melts. In between these two extremes, there is a wide range of possible hydrological conditions and their final effect on us may depend on the accumulated hydrology. For instance, a new year with drought conditions has less of an impact on us if it follows several periods of abundant rainfall instead of exacerbating a prolonged drought. Likewise, a good hydrological year has less marginal impact if it comes after several wet years than after a prolonged drought. In Chile, the period of the year that typically has the most precipitation is from May through August, and the period in which snow and ice in the mountains melt more is during the warmer months, from October through March, providing water flow to lakes, reservoirs and rivers, which supply our hydroelectric plants, most of them located in southern Chile. For purposes of discussing the impact of hydrological conditions on our business, we generally categorize our hydrological conditions as either dry or wet, although there are several other intermediate scenarios. Extreme hydrological conditions materially affect our operating results and financial condition. However, it is difficult to indicate the effects of hydrology on our operating income, without concurrently considering other factors, because our operating income can only be explained by looking at a combination of factors and not each one on a stand-alone basis.

 

Hydrological conditions affect electricity market prices, generation costs, spot prices, tariffs and the mix of hydroelectric, thermal and NCRE generation, which is constantly being determined by the CEN to minimize the operating costs of the entire system. According to the current regulatory framework, the price at which energy is traded on the spot market (known as spot price) is determined by the marginal cost of the system. The marginal cost is the cost of the most expensive power plant in operation given an efficiency-based dispatch. Regulation also considers capacity payments to generators, which remunerates each power plant’s installed capacity according to its availability and contribution to the system’ safety. This capacity payment is determined by the regulator every six months. Run of the river hydroelectric and NCRE generation are almost always the least expensive generation technology and normally have a marginal cost close to zero. Water from reservoirs used to generate electricity, on the other hand, is assigned an opportunity cost for the use of water, which may lead to hydroelectric generation using water from reservoirs having a significant cost in extended drought conditions. The cost of thermal generation does not depend on hydrological conditions but instead on international commodity prices for LNG, coal, diesel and fuel oil. Solar and wind sources are currently the NCRE technologies most widely used. NCRE facilities are able to dispatch energy to the system at very low marginal costs, but they depend on the blowing of the wind or the shining of the sun.

 

Spot prices primarily depend on hydrological conditions and commodity prices and, to a lesser extent, on NCRE availability. Under most circumstances, abundant hydrological conditions lower spot prices while dry conditions normally increase spot prices. Spot market prices affect our results because we must purchase electricity in the spot market when our contracted energy sales are greater than our generation, and we sell electricity in the spot market when we have electricity surpluses.

 

There are many other factors that may affect our operating income, including the level of contracted sales, purchases and sales in the spot market, commodity prices, energy demand and supply, 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.

 

To illustrate the effects of hydrology on our operating results, the following table describes certain hydrological conditions, their expected effects on spot prices and generation, and the expected impact on our operating income, assuming that other factors remain

 

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unchanged. In all cases, hydrological conditions do not have an isolated effect but need to be evaluated along with other factors to better understand the impact on our operating results.

 

Hydrological
Conditions

 

Expected effects on spot prices
and generation

 

Expected impact on our operating results 

 

 

 

 

 

Dry

 

Higher spot prices

 

Positive: if our generation is higher than our contracted energy sales, energy surpluses are sold in the spot market at higher prices.


Negative: if our generation is lower than our contracted sales, we have an energy deficit and must purchase energy in the spot market at higher prices.

 

 

 

 

 

Reduced hydro generation

 

Negative: less energy available to sell in the spot market.

 

 

 

 

 

Increased thermal generation

 

Positive: increases our energy available for sale and either reduces purchases in the spot market or increases sales in the spot market at higer prices.

 

 

 

 

 

Wet

 

Lower spot prices

 

Positive: if our generation is lower than contracted energy sales, the energy deficit is covered by purchases in the spot market at lower prices.

Negative: if we have energy surpluses, they are sold in the spot market at lower prices.

 

 

 

 

 

Increased hydroelectric generation

 

Positive: more energy available to sell in the spot market at lower prices.

 

 

 

 

 

Reduced thermal generation

 

Negative: less energy available to sell in the spot market.

 

If factors other than those described above apply, the expected impact of hydrological conditions on operating results will be different from those shown above. For instance, in a dry year with lower commodity prices, spot prices may decrease, or in a wet year if demand increases, or generation plants are not available for technical or other reasons, the spot price may increase, altering the impact of hydrological conditions discussed in the table above.

 

b.     Economic Conditions

 

Macroeconomic conditions, such as changes in employment levels and inflation or deflation may have a significant effect on our operating results. Macroeconomic factors, such as the variation of the Chilean peso against the U.S. dollar may impact our operating results, as well as our assets and liabilities, depending on the amounts denominated in U.S. dollars. For example, a devaluation of the Chilean peso against the U.S. dollar increases the cost of capital expenditure plans depending on the level at which our revenues are denominated in Chilean pesos. For additional information, see “Item 3. Key Information — D. Risk Factors — Foreign exchange risks may adversely affect our results and the U.S. dollar value of dividends payable to ADS holders” and “Item 3. Key Information  — D. Risk Factors — Chilean economic fluctuations as well as, certain economic interventionist measures by governmental authorities as well as political events or financial or other crises in any region worldwide may affect our results of operations and, financial condition and liquidity as well as the value of our securities.”

 

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

 

 

 

Local Currency U.S. Dollar Exchange Rates

 

 

 

2018

 

2017

 

2016

 

 

 

Average

 

Year End

 

Average

 

Year End

 

Average

 

Year End

 

Chilean pesos per U.S. dollar

 

640.95

 

694.77

 

649.11

 

614.75

 

676.67

 

669.47

 

 

Source: Central Bank of Chile

 

c.     Critical Accounting Policies

 

Critical accounting policies are defined as those that reflect significant judgments and uncertainties that 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 consolidated financial statements under IFRS are those described below.

 

For further detail of the accounting policies and the methods used in the preparation of the consolidated financial statements, see Notes 2 and 3 of the Notes to our consolidated financial statements.

 

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Impairment of Long-Lived Assets

 

From time to time, and principally at the end of any year, we evaluate whether there is any indication that an asset has been impaired. Should any such indication exist, we estimate the recoverable amount of that asset to determine, where appropriate, the amount of impairment. In the case of identifiable assets that do not generate cash flows independently, we estimate the recoverability of the cash generating unit to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

 

Notwithstanding the preceding paragraph, in the case of cash generating units to which goodwill or intangible assets with an indefinite useful life have been allocated, a recoverability analysis is performed routinely at each period end.

 

The recoverable amount is the greater of (i) the fair value less the cost needed to sell and (ii) the value in use, which 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 future years and applying reasonable growth rates, which in no case are increasing nor exceed the average long-term growth rates for the Chilean electricity sector. At the end of December 2018, projected cash flows were extrapolated using an annual growth rate of 3.1%.

 

These future cash flows are discounted at a given pre-tax rate to calculate their present value. This rate reflects the cost of capital of the business in Chile. 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.

 

The pre-tax nominal discount rates applied in 2018, 2017 and 2016 are as follows:

 

 

 

 

 

Year ended December 31, 

 

 

 

 

 

2018

 

2017

 

2016

 

Chile

 

 

 

10.6

%

10.7

%

12.2

%

 

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 other than goodwill in prior periods are reversed when its estimated recoverable amount changes, increasing the asset’s value with a credit to earnings, limited to the asset’s carrying amount if no adjustment had occurred. Impairment adjustments to goodwill are not reversible.

 

Litigation and Contingencies

 

We are currently involved in legal and tax proceedings. As discussed in Note 23 of the Notes to our consolidated financial statements as of December 31, 2018, we recognized provisions for legal and tax proceedings in an aggregate amount of Ch$ 3.9 billion as of December 31, 2018. This amount was based on consultations with our legal and tax advisors, who are carrying out our defense in these matters and an analysis of potential results, assuming a combination of litigation and settlement strategies.

 

Hedge Cash 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 revenues directly linked to the U.S. dollar, with the purpose of confirming that hedge accounting is applicable. Such analysis may change in the future due to new electricity regulations limiting the amount of cash flows tied to the U.S. dollar.

 

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Recent Accounting Pronouncements

 

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

 

2.     Analysis of Results of Operations for the Years Ended December 31, 2018, and 2017

 

Consolidated Revenues

 

The following tables set forth our total revenues and the corresponding change for the years ended December 31, 2018, and 2017:

 

 

 

Year ended December 31, 

 

 

 

2018

 

2017

 

Change

 

Change

 

 

 

(in millions of Ch$)

 

(in %)

 

Revenues

 

1,521,054

 

1,634,937

 

(113,883

)

(7.0

)

 

Revenues decreased in 2018 compared to 2017 despite the level of generation and the stable level of physical sales. The decrease was mainly due to (i) Ch$ 88.3 billion lower revenues from energy sales, which was primarily attributable due to (a) Ch$ 46.1 billion associated with lower energy average sales price due to the lower average exchange rate for the period; (b) Ch$ 22.3 billion of lower physical sales as a result of the shift in our customer mix between regulated and unregulated customers; and (c) Ch$ 21.9 billion of lower revenues as a result of settlements performed by the CEN associated with price and quantity adjustments registered in 2017. The decrease was also the result of Ch$ 35.4 billion of less toll revenues partially offset by Ch$ 9.3 billion of higher other sales, mainly due to Ch$ 12.1 billion of higher gas sales offset by Ch$ 2.8 billion lower coal sales.

 

Total Operating Costs

 

Our total operating costs are primarily energy purchases from third parties, fuel purchases, 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 principal items for consolidated operating costs for the years ended December 31, 2018, and 2017:

 

 

 

Year ended December 31, 

 

 

 

2018

 

2017

 

 

 

(in millions
of Ch$)

 

(in %)

 

(in millions
of Ch$)

 

(in %)

 

Energy purchases

 

326,366

 

40.3

 

346,955

 

38.4

 

Fuel consumption

 

230,994

 

28.5

 

280,739

 

31.1

 

Transportation costs

 

141,551

 

17.5

 

152,870

 

16.9

 

Other variable procurement and services

 

111,063

 

13.7

 

123,414

 

13.7

 

Depreciation, amortization and impairment losses(1)

 

117,867

 

14.6

 

117,282

 

13.0

 

Other expenses(1)

 

82,479

 

10.2

 

102,821

 

11.4