UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
| REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2020
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
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| SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Date of event requiring this shell company report, . . . . . . . . . . . . . . . . . . .
Commission file number: 001-37723
ENEL CHILE S.A. (Exact name of Registrant as specified in its charter) ENEL 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: (56-9) 9343 5500, nicolas.billikopf@enel.com, Av. Santa Rosa 76, Piso 15, Comuna de Santiago, Santiago, Chile (Name, Telephone, E-mail, and Address of Company Contact Person)
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Securities registered or to be registered pursuant to Section 12(b) of the Act:
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Title of | | Trading Symbol(s) | Name of | ||
American Depositary Shares Representing Common Stock | | ENIC | New York Stock Exchange | ||
Common Stock, no par value * | | * | New York Stock Exchange | ||
US$ 1,000,000,000 4.875% Notes due June 12, 2028 | | ENIC28 | New York Stock Exchange |
*Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.
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* | Listed, not for trading, but only in connection with the registration of American Depositary Shares, under the Securities and Exchange Commission’s requirements. |
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report
Shares of Common Stock: 69,166,557,220
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 (§232.405 of this chapter) 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 | Accelerated filer | Non-accelerated filer ☐ | Emerging growth company |
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards † provided pursuant to Section 13(a) of the Exchange Act. 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 whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report ⌧
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
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U.S. GAAP | International Financial Reporting Standards as issued by the International Accounting Standards Board | Other |
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
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).☐ Yes ☒ No
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: 49,092,772,762
Enel Chile’s Simplified Organizational Chart(1)Structure(1)
As of December 31, 2018the date of this Report(2)
(1) | Only principal operating consolidated entities are presented here. |
(2) | As of January 1, 2021, Enel Transmission was spun off from Enel Distribution. |
(1) Only principal operating consolidated entities are presented here. The percentage listed in the box for each
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Material Modifications to the Rights of Security Holders and Use of Proceeds |
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Purchases of Equity Securities by the Issuer and Affiliated Purchasers |
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| | American Depositary Receipt | | A certificate issued by our depositary that represents ADS, or American Depositary Shares. | ||
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ADS | | American Depositary Share(s) | | An equity interest in our company that is issued by Citibank, N.A., as the depositary, in respect of shares of our company held by the depositary. Each ADS represents 50 shares and ADS are traded on the New York Stock Exchange. In this Report, ADS is used in the singular and plural forms. | ||
AES Gener | | AES Gener S.A. | | A Chilean generation company and one of our competitors in Chile. | ||
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AFP | | Administradora de Fondos de Pensiones | | A legal entity that manages | ||
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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 | ||
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Celta | | Compañía Eléctrica Tarapacá S.A. | | Celta was a former Chilean generation subsidiary of Enel | ||
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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. | ||
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Chilean Stock Exchanges | | Chilean Stock Exchanges |
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CMF | | |||||
| Comisión para el Mercado Financiero | | Chilean Financial Market Commission, the governmental authority that supervises the financial | |||
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CNE | | Comisión Nacional de Energía | | Chilean National Energy Commission, a governmental entity with responsibilities under the Chilean regulatory framework. | ||
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| Enel Green Power Chile | | A | |||
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EGPL | | Enel Green Power Latin | |
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Enel | | Enel S.p.A. | | An Italian company with multinational operations in the power and gas markets, with a 64.9% ownership of Enel Chile as of December 31, 2020, and our ultimate parent company. | |
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Enel Américas | | Enel Américas S.A. | | An affiliated Chilean publicly held limited liability stock corporation headquartered in Chile, with subsidiaries engaged primarily in the generation, transmission, and distribution of electricity in Argentina, Brazil, Colombia, and Peru, | |
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Enel Chile | | Enel Chile S.A. |
| Our company, a Chilean publicly held limited liability stock corporation, with subsidiaries engaged primarily in the generation and distribution of electricity in Chile. |
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| | Geotérmica del Norte S.A. |
| | A joint venture between our subsidiary EGP Chile and Empresa Nacional del Petróleo (ENAP), the state-owned Chilean |
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| International Financial Reporting Standards | | International Financial Reporting Standards as issued by the International Accounting Standards Board (IASB). | ||
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LNG | | Liquefied Natural Gas. |
| | Liquefied natural |
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NCRE | | Non-Conventional Renewable Energy |
| | Energy sources |
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OSM | | Ordinary Shareholders’ Meeting |
| | Ordinary Shareholders’ |
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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 a subsidiary of Enel Generation. | |
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| | System Average Interruption Duration Index | | Index of average duration of interruption in the power supply. | |
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SAIFI | | System Average Interruption Frequency Index | | Index of average frequency of interruptions in the power supply. | |
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SEF | | Superintendencia de Electricidad y Combustible | | Chilean Superintendence of Electricity and Fuels, the governmental authority that supervises the Chilean electricity industry. |
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SEN | | Sistema Eléctrico Nacional | | The National Electricity System is the Chilean national interconnected electricity system formed in November 2017 | |
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| | Unidad de Fomento |
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| | Chilean inflation-indexed, Chilean peso-denominated monetary unit, equivalent to Ch$ | ||
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| Valor Agregado de Distribución | |
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As used in this Report on Form 20-F (“Report”), first personfirst-person personal pronouns such as “we”“we, “us”” “us,” or “our”,“our,” as well as “Enel Chile” or the “Company”,“Company,” refer to Enel Chile S.A. and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries and jointly-controlledjointly controlled companies and associates is expressed in terms of our economic interest as of December 31, 2018.2020.
We are a Chilean company primarily engaged in the electricity generation, transmission and distribution businesses in Chile through our subsidiaries and affiliates. As of the date of this Report and after giving effect to the 2018 Reorganization (described in “Item 4. Information on the Company — A. History and Development of the Company — theThe 2018 Reorganization”), we own 93.6%93.5% of Enel Generación Chile S.A. (“Enel Generation”), a Chilean electricity generation company holding electricity generationwith operations in Chile, and 99.1% of Enel Distribución Chile S.A. (“Enel Distribution”), a Chilean electricity distribution company with operationwhich operates in the Santiago Metropolitan Region.Region, and 99.1% of Enel Transmisión Chile S.A., through which we carry out sub-transmission activities.
On April 2, 2018, as part of the 2018 Reorganization, Enel Green Power Latin America S.A. (“EGPL”), a Chilean non-conventional electricity generation company holding non-conventional electricity generationwith operations in Chile, merged with us. As a result, we now wholly own and consolidate Enel Green Power Chile Ltda.S.A. (“EGP Chile”). For additional information relating to the company and the corporate reorganization completed in 2018, please see “Item 4. Information on the Company — A. History and Development of the Company — The 2018 Reorganization”.
We are a publicly held limited liability stock corporation organized on March 1, 2016, under the laws of the Republic of Chile as a result of a corporate reorganization completed in 2016 by the former Enersis S.A., which separated its Chilean businesses from its non-Chilean businesses.
On October 18, 2016,December 3, 2020, Enel Distribution held an extraordinary shareholders’ meeting to approve the separation of its distribution and as part of this process, (i) Endesa Chile changed its name totransmission business lines into two separate companies. 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 theDistribution carried out a corporate reorganization completed in 2016, please see “Item 4. Information on the Company — A. History and DevelopmentJanuary 1, 2021, pursuant to which each shareholder of Enel Distribution received one share of the Company — The 2016 Reorganization”.new company, Enel Transmission, for each share of Enel Distribution held, maintaining the same ownership position in each company after the spin-off.
As of the date of this Report, Enel S.p.A. (“Enel”), an Italian energy company with multinational operations in the power and gas markets, owns 61.9% (excluding treasury stock)64.9% of us and is our ultimate controlling shareholder.
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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; references to “EUR” or “€” are to Euro, the currency of the European Union and references to “UF” are to Unidades de Fomento. The UF is a Chilean inflation-indexed, a 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, 2018,2020, one UF was equivalent to Ch$ 27,565.79.29,070.33. The U.S. dollar equivalent of one UF was US$ 39.6840.89 as of December 31, 2018,2020, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 20182020, of Ch$ 694.77710.95 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,web page, is the weighted averageweighted-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 outmade at the rates applicable as of December 31, 2018.2020.
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 withunder 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 participationinterest in associated companies over which we exercise significant influence areis included in our consolidated financial statements using the equity method. For detailed information regarding consolidated entities, jointly-controlledjointly controlled entities, and associated companies, see Appendices 1, 2Notes 2.4, 2.5, and 32.6 of the Notes to theour consolidated financial statements.
Solely for the convenience of the reader, thisThis 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, 2018,2020, 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 showndisclosed 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”.Rates.”
Technical Terms
References to “TW” are to terawatts (1012 watts or a trillion watts); references to “GW” and “GWh” are to gigawatts (109 watts or a billion watts) and gigawatt hours,gigawatt-hours, respectively; references to “MW” and “MWh” are to megawatts (106 watts or a million watts) and megawatt hours,megawatt-hours, respectively; references to “kW” and “kWh” are to kilowatts (103 watts or a thousand watts) and kilowatt hours,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;hertz, and references to “mtpa” are to metric tons per annum. Unless otherwise indicated, statistics provided in this Report with respect toconcerning the installed capacity of electricity generation facilities are expressed in MW. One TW equals 1,000 GW, one GW equals 1,000 MW, and one MW equals 1,000 kW. The installed capacity we are presentingpresent in this Report corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its own operation.
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Statistics relating to aggregate annual electricity production are expressed in GWh and based on a year of 8,760 hours, except for a leap years,year like 2020, which areis based instead on 8,784 hours. Statistics relating to installed capacity and production of the electricity industry do not include electricity of self-generators.
Energy losses experienced by generation companies during transmission are calculated by subtracting the number of GWh of energy sold from the number of GWh of energy generated (excluding their own energy consumption and losses on the part of the power plant), within a given period. Losses are expressed as a percentage of total energy generated.
Energy losses during distribution are calculated as the difference between total energy purchased (GWh of electricity demand, including own generation) and the energy sold excluding tolls and energy consumption not billed (also measured in GWh), within a given period. Distribution losses are expressed as a percentage of the total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical losses.
Calculation of Economic Interest
ReferencesIn this Report, references are made in this Report to the “economic interest” of Enel Chile in its related companies. We could have a direct and indirect interest isin such companies. In circumstances wherein which we do not directly own an interest in a relatedan affiliated company, our economic interest in such ultimate relatedaffiliated company is calculated by multiplying the percentage of economic interest in a directly held relatedaffiliated company by the percentage of economic interest of any entity in the ownership chain of such relatedaffiliated company. For example, if we directly own a 6% equity stake in an associateaffiliated company and 40% is directly held by our 60%-owned subsidiary, our economic interest in such an associate would be 60% times 40% plus 6%, equal to 30%.
Rounding
Certain figuresFigures included in this Report have been rounded for ease of presentation. Because of thisDue to rounding, it is possible that amountsthe sums in tables maydo not add up toalways exactly equal the same amounts as the sumsums of the entries.
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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.
● | our capital investment program; |
● | trends affecting our financial condition or results of operations; |
● | our dividend policy; |
● | the future impact of competition and regulation; |
● | political and economic conditions in the countries in which our related companies or we 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.”
● | demographic developments, political events, social unrest, economic fluctuations, public health crises and pandemics, 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 toconcerning 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.
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PART I
Item 1.Identity of Directors, Senior Management and Advisers
Not applicable.
Item 2.Offer Statistics and Expected Timetable
Not applicable.
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, 2018,2020, and 20172019, and for each of the three years in the three-year period ended December 31, 2016,2020, are derived from our audited consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2018, 2017, 2016, 2015 and 2014, and for the years ended December 31, 2015,2017, and 20142016 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 theThe tables are expressed in millions, except for ratios, operating data, and data for shares and American Depositary Shares (“ADS”). For the reader’s convenience, of the reader, all data presented in U.S. dollars in the following summary, as of and for the year ended December 31, 2018,2020, has been converted at the U.S. dollar Observed Exchange Rate (dólar observado) for that date of Ch$ 694.77710.95 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 averageweighted-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.
The following tables set forth our selected consolidated financial data and operating data for the years indicated:
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| As of and for the year ended December 31, |
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| 2014 |
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Consolidated Statement of Comprehensive Income Data |
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Revenues and other operating income |
| 3,537 |
| 2,457,161 |
| 2,522,978 |
| 2,541,567 |
| 2,399,029 |
| 2,049,065 |
| | 3,637 | | 2,585,402 | | 2,770,834 | | 2,457,161 | | 2,522,978 | | 2,541,567 |
Operating costs (2) |
| (2,571 | ) | (1,786,546 | ) | (1,944,348 | ) | (1,973,778 | ) | (1,873,540 | ) | (1,666,315 | ) | | (3,685) | | (2,619,658) | | (2,244,780) | | (1,786,557) | | (1,944,348) | | (1,973,778) |
Operating income |
| 965 |
| 670,605 |
| 578,631 |
| 567,789 |
| 525,489 |
| 382,750 |
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Operating income (loss) | | (48) | | (34,255) | | 526,055 | | 670,605 | | 578,631 | | 567,789 | |||||||||||||
Financial results (3) |
| (160 | ) | (110,875 | ) | (22,415 | ) | (20,483 | ) | (97,869 | ) | (67,045 | ) | | (158) | | (112,435) | | (150,893) | | (110,875) | | (22,415) | | (20,483) |
Other non-operating income |
| 5 |
| 3,410 |
| 113,241 |
| 121,490 |
| 20,056 |
| 70,893 |
| | 13 | | 9,489 | | 1,793 | | 3,410 | | 113,241 | | 121,490 |
Share of profit (loss) of associates and joint ventures accounted for using the equity method |
| 5 |
| 3,190 |
| (2,697 | ) | 7,878 |
| 8,905 |
| (54,353 | ) | | 5 | | 3,509 | | 366 | | 3,190 | | (2,697) | | 7,878 |
Income before income taxes |
| 815 |
| 566,330 |
| 666,760 |
| 676,674 |
| 456,581 |
| 332,245 |
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Income tax expenses |
| (221 | ) | (153,483 | ) | (143,342 | ) | (111,403 | ) | (109,613 | ) | (132,687 | ) | ||||||||||||
Income (loss) before income taxes | | (188) | | (133,692) | | 377,321 | | 566,330 | | 666,760 | | 676,674 | |||||||||||||
Income taxes | | 114 | | 81,305 | | (61,228) | | (153,483) | | (143,342) | | (111,403) | |||||||||||||
Net income |
| 594 |
| 412,848 |
| 523,418 |
| 565,271 |
| 346,968 |
| 199,558 |
| | (74) | | (52,387) | | 316,093 | | 412,848 | | 523,418 | | 565,271 |
Net income attributable to the parent Company |
| 521 |
| 361,710 |
| 349,383 |
| 384,160 |
| 251,838 |
| 162,459 |
| | (72) | | (50,860) | | 296,154 | | 361,710 | | 349,383 | | 384,160 |
Net income attributable to non-controlling interests |
| 74 |
| 51,138 |
| 174,035 |
| 181,111 |
| 95,130 |
| 37,099 |
| | (2) | | (1,527) | | 19,940 | | 51,138 | | 174,035 | | 181,111 |
Total basic and diluted earnings per average number of shares (Ch$/US$ per share) |
| 0.01 |
| 5.66 |
| 7.12 |
| 7.83 |
| 5.13 |
| 3.31 |
| | (0.001) | | (0.74) | | 4.28 | | 5.66 | | 7.12 | | 7.83 |
Total basic and diluted earnings per average number of ADSs (Ch$/US$ per ADS) |
| 0.41 |
| 282.97 |
| 355.84 |
| 391.26 |
| 256.49 |
| 165.46 |
| ||||||||||||
Cash dividends per share (Ch$/US$ per share)(4) |
| 0.004 |
| 3.00 |
| 3.23 |
| 2.09 |
| — |
| — |
| ||||||||||||
Cash dividends per ADS (Ch$/US$ per ADS)(4) |
| 0.22 |
| 149.89 |
| 161.72 |
| 104.65 |
| — |
| — |
| ||||||||||||
Total basic and diluted earnings per average number of ADS (Ch$/US$ per ADS) | | (0.052) | | (36.77) | | 214.09 | | 282.97 | | 355.84 | | 391.26 | |||||||||||||
Cash dividends per share (Ch$/US$ per share)(4) | | 0.006 | | 4.23 | | 3.14 | | 2.99 | | 3.23 | | 2.09 | |||||||||||||
Cash dividends per ADS (Ch$/US$ per ADS)(4) | | 0.297 | | 211.50 | | 157.00 | | 149.50 | | 161.50 | | 104.65 | |||||||||||||
Weighted average number of shares of common stock (millions) |
| 63,913 |
| 63,913 |
| 49,093 |
| 49,093 |
| 49,093 |
| 49,093 |
| | 69,167 | | 69,167 | | 69,167 | | 63,913 | | 49,093 | | 49,093 |
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Consolidated Statement of Financial Position Data |
|
|
|
|
|
|
|
|
|
|
|
|
| | | | | | | | | | | | |
Total assets |
| 10,778 |
| 7,488,020 |
| 5,694,773 |
| 5,398,711 |
| 5,325,469 |
| 5,126,735 |
| | 11,118 | | 7,904,472 | | 7,857,988 | | 7,488,020 | | 5,694,773 | | 5,398,711 |
Non-current liabilities |
| 3,737 |
| 2,596,392 |
| 1,090,995 |
| 1,178,471 |
| 1,270,006 |
| 1,122,585 |
| | 4,592 | | 3,264,717 | | 3,069,405 | | 2,596,392 | | 1,090,995 | | 1,178,471 |
Equity attributable to the parent company |
| 4,924 |
| 3,421,229 |
| 2,983,384 |
| 2,763,391 |
| 2,592,682 |
| 2,472,201 |
| | 4,715 | | 3,351,916 | | 3,484,698 | | 3,421,229 | | 2,983,384 | | 2,763,391 |
Equity attributable to non-controlling interests |
| 364 |
| 252,935 |
| 803,578 |
| 699,602 |
| 609,219 |
| 611,864 |
| | 341 | | 242,359 | | 262,586 | | 252,935 | | 803,578 | | 699,602 |
Total equity |
| 5,288 |
| 3,674,164 |
| 3,786,962 |
| 3,462,994 |
| 3,201,901 |
| 3,084,066 |
| | 5,056 | | 3,594,274 | | 3,747,284 | | 3,674,164 | | 3,786,962 | | 3,462,994 |
Capital stock |
| 5,692 |
| 3,954,491 |
| 2,229,109 |
| 2,229,109 |
| 2,229,109 |
| 2,229,109 |
| | 5,460 | | 3,882,103 | | 3,882,103 | | 3,954,491 | | 2,229,109 | | 2,229,109 |
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Other Consolidated Financial Data |
|
|
|
|
|
|
|
|
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|
|
|
| | | | | | | | | | | | |
Capital expenditures (CAPEX) (5) |
| 433 |
| 300,539 |
| 266,030 |
| 222,386 |
| 309,503 |
| 196,932 |
| | 780 | | 554,314 | | 321,079 | | 300,539 | | 266,030 | | 222,386 |
Depreciation, amortization and impairment losses (6) |
| 318 |
| 220,750 |
| 160,622 |
| 197,587 |
| 150,147 |
| 141,623 |
| | 1,326 | | 942,931 | | 527,437 | | 220,750 | | 160,622 | | 197,587 |
(1) | Solely for the reader’s convenience, Chilean peso amounts have been converted into U.S. dollars at the exchange rate of Ch$ 710.95 per U.S. dollar, as of December 31, 2020. |
(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) | For 2016, a payout ratio of 50% was used based on annual consolidated net income for our 2016 annual consolidated net income filed with the Financial Market Commission (“CMF” in its Spanish acronym), based on ten months of results starting as of our incorporation on March 1, 2016, and therefore differs from the twelve-month net income included in this Report. |
11
(5) | CAPEX figures represent cash flows used to purchase property, plant, and equipment, and intangible assets for each year. |
(6) | Please refer to Note 31 of the Notes to our consolidated financial statements for further detail. |
| | | | | | | | | | |
| | As of and for the year ended December 31, | ||||||||
|
| 2020 |
| 2019 |
| 2018 |
| 2017 |
| 2016 |
OPERATING DATA OF SUBSIDIARIES | | | | | | | | | | |
| | | | | | | | | | |
Enel Distribution | | | | | | | | | | |
Electricity sold (GWh) | | 16,481 | | 17,135 | | 16,782 | | 16,438 | | 15,924 |
Number of customers (thousands) | | 2,008 | | 1,972 | | 1,925 | | 1,882 | | 1,826 |
Total energy losses (%)(1) | | 5.2 | | 5.0 | | 5.0 | | 5.1 | | 5.3 |
| | | | | | | | | | |
Enel Generation | | | | | | | | | | |
Installed capacity (MW) | | 6,001 | | 6,114 | | 6,274 | | 6,351 | | 6,351 |
Generation (GWh) | | 15,913 | | 17,548 | | 17,373 | | 17,073 | | 17,564 |
| | | | | | | | | | |
EGP Chile(2) | | | | | | | | | | |
Installed capacity (MW) | | 1,200 | | 1,189 | | 1,189 | | — | | — |
Generation (GWh) | | 3,418 | | 3,493 | | 2,673 | | — | | — |
(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) For 2016, a payout ratio of 50% was used based on annual consolidated net income for our 2016 annual consolidated net income filed with the CMF, based on 10 months of results starting as of our incorporation on March 1, 2016, and therefore differs from the twelve-month net income included in this Report.
(5) CAPEX figures represent cash flows used for purchases of property, plant and equipment and intangible assets for each year.
(6) For further detail, please refer to Note 31 of the Notes to our consolidated financial statements.
|
| As of and for the year ended December 31, |
| ||||||||
|
| 2018 |
| 2017 |
| 2016 |
| 2015 |
| 2014 |
|
OPERATING DATA OF SUBSIDIARIES |
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|
Enel Distribution |
|
|
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|
|
|
|
|
|
|
|
Electricity sold (GWh) |
| 16,782 |
| 16,438 |
| 15,924 |
| 15,893 |
| 15,690 |
|
Number of customers (thousands) |
| 1,925 |
| 1,882 |
| 1,826 |
| 1,781 |
| 1,737 |
|
Total energy losses (%) (1) |
| 5.0 |
| 5.1 |
| 5.3 |
| 5.3 |
| 5.3 |
|
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|
|
Enel Generation |
|
|
|
|
|
|
|
|
|
|
|
Installed capacity (MW) (2) |
| 6,274 |
| 6,351 |
| 6,351 |
| 6,351 |
| 6,351 |
|
Generation (GWh) (2) |
| 17,373 |
| 17,073 |
| 17,564 |
| 18,294 |
| 18,063 |
|
(1) | Energy losses in distribution arise from illegally tapped energy as well as technical losses. They are calculated as the difference between total energy generated and purchased and the energy sold, excluding tolls and energy consumption not billed (GWh), within a given period. Losses are expressed as a percentage of the total energy purchased. |
(2) | EGP Chile has been consolidated since April 2018. |
(1) Energy losses in distribution arise from illegally tapped energy as well as technical losses. They are calculated as the difference between total energy generated and purchased and the energy sold, excluding tolls and energy consumption not billed (GWh), within a given period. Losses are expressed as a percentage of total energy purchased.
(2) The 2015 and 2014 data includes the capacity and generation of GasAtacama, as a result of its consolidation.
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 in Chilean pesos 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 fluctuations in the exchange rate fluctuations affect the price of our American Depositary Shares (“ADSs”)ADS and the conversion of cash dividends relating to the common shares represented by ADSsADS from Chilean pesos to U.S. dollars. In addition,Also, to the extent that our significant financial liabilities of the Company are denominated in foreign currencies, fluctuations in the exchange rate fluctuations may have a significantsignificantly impact onour earnings.
In Chile, thereThere are two currency markets in Chile, the Formal Exchange Market (Mercado Cambiario Formal) and the Informal Exchange Market (Mercado Cambiario Informal). The Formal Exchange Market is comprisedconsists of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market is comprised ofincludes entities that are not expressly authorizedpermitted 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 outmade on the Formal Exchange Market. BothFree market forces drive both the Formal and Informal Exchange Markets are driven by free market forces.Markets. Current regulations require that the Central Bank of Chile be informed of certain transactions that must be carried outeffected 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 averageweighted-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 athe desired range.
The Informal Exchange Market reflects transactions carried out at an informal exchange rate (the “Informal Exchange Rate”).rate. There are no limits imposed on the extent to which the exchange rate of exchange in the Informal Exchange Market can fluctuate above or below the U.S. dollar Observed Exchange Rate. Foreign currency for payments and distributions with respect toconcerning the ADSsADS may be
12
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, 2018,2020, the U.S. dollar Observed Exchange Rate was Ch$ 694.77710.95 per US$ 1.00.
As of April 22, 2019,28, 2021, the U.S. dollar Observed Exchange Rate was Ch$ 663.91700.15 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 devaluationappreciation of the year-end Chilean peso in 2018,2020, one determines the percentage of change between the reciprocal of Ch$ 694.77,748.74, the value of one U.S. dollar as of December 31, 2018,2019, or 0.001439,0.0013355, and the reciprocal of Ch$ 614.75,710.95, the value of one U.S. dollar as of December 31, 2017,2020, or 0.001627.0.0014066. In this example, the percentage change between the two periods is -11.5%5.3%, which representsrepresenting the 20182020 year-end devaluationappreciation of the Chilean peso against the 20172019 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.
13
The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2014,2016, through December 31, 2018,2020, 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 | ) |
| | | | |
| | Ch$ per US$(1) | ||
|
| Period End |
| Appreciation (Devaluation) |
| | (in Ch$) | | (in %) |
Year ended December 31, | | | | |
2020 | | 710.95 | | 5.3 |
2019 | | 748.74 | | (7.2) |
2018 | | 694.77 | | (11.5) |
2017 | | 614.75 | | 8.9 |
2016 | | 669.47 | | 6.1 |
Source: Central Bank of Chile.
(1) | Calculated based on the variation of the reciprocals of the period-end exchange rates. |
(1) Calculated based on the variation of period-end exchange rates.
B.Capitalization and Indebtedness.
Not applicable.
C.Reasons for the Offer and Use of Proceeds.
Not applicable.
D.Risk Factors.
Risk Related to Our Business
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 conditionOur businesses depend heavily on hydrology 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 instabilitydroughts, flooding, storms, ocean currents, 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 hydrologicalinclement weather conditions.
Approximately 48%49% of our installed generation capacity in 20182020 was hydroelectric. Accordingly, dryarid hydrological conditions could adverselynegatively 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.average, which has been the case for much of the period since 2007.
While ourOur subsidiary Enel Generation has entered into certain agreements with the Chilean government and local irrigators regarding thewater use of water for hydroelectric generation purposes during periods of low water levels,levels. However, if droughts persist, we may face increased pressure byfrom the Chilean government or other third parties to further restrict our water use.use further.
Our operating expenses increase during these drought periods when thermal power plants, which have higher operating costs relative to hydroelectric power plants, are dispatched more frequently. WeDepending on our commercial obligations, we may need to buy electricity at higher spot prices in order to comply with our contractual supply obligations andobligations. Beyond increasing operating costs, 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 toconcerning 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 power plants, including our facilities that use natural gas, fuel oil, or coal, in the following manner:
● | Our thermal power plants require water for cooling, and droughts in extreme situations may reduce water availability and increase transportation costs. As a result, we have had to purchase water for our San Isidro |
· Our thermal plants require water for cooling and droughts in extreme situations may reduce the availability14
· 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 use of thermal plants 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.”
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 generate emissions such as nitrogen oxide (NO), carbon dioxide (CO2), carbon monoxide (CO), sulfur dioxide (SO2), and particulate matter into the atmosphere. Therefore, greater use of thermal power plants during droughts generally increases the risk of producing greater greenhouse gas (GHG) emissions. |
A full recovery from the droughtextended droughts that, hassince 2007, have been affecting the regions where most of our hydroelectric power plants are located may last for an extended period buttake many years, and new drought periods may recur in the future. A prolonged droughtProlonged droughts may exacerbate the risks described above and have a further adversenegative effect uponon our business, results of operations, and financial condition.
TheOur distribution business is also affected by inclement weather. With extremeExtreme temperatures demand can increase demand significantly within a very short period, of time, which in turn affectsmay strain our service and could result in service disruptions that are potentially subject to fines. Depending on weather conditions, results obtained by our distribution business can vary significantly from year to year. For example, as a result of severe rainstorms in June 2017, with high wind gusts that brought down part of the electric network, 125,000 of our customers, or 7%, were affected adversely.left without electricity. In July 2017, a strongan intense snowstorm over the Santiago Metropolitan Region caused massive damage to the electrical infrastructure, and a blackout affected 342,000 of our customers or 18%, and 17% of our feeders. This snowstorm was the most damaging snowstorm in Santiago since 1970 and left parts of the capital without powerelectricity for overmore than a week. These events significantly increased our costs due to emergency responses, including payments related to damage compensation, fines, line maintenance, and tree trimming programs.
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 customersWe are subject to extensive regulationphysical, operational, and financial risks related to climate change effects.
The electricity generated by our solar and wind generation facilities is highly dependent on climate factors other than hydrology, including suitable solar and wind conditions, which, even under normal operating circumstances, can vary greatly. Climate change may also have long-term effects on wind patterns and the amount of solar energy received at a particular solar facility, reducing electricity generated by the facilities. Although we base our business decisions on solar and wind studies for each renewable energy facility, actual conditions may not conform to these regulationsstudies’ findings. They may adversely affectbe affected by changes in weather patterns, including the potential impact of climate change.
If our profitability. For example, governmental authorities might impose rationing policies during droughts or prolonged failures ofrenewable energy production falls below anticipated levels, we may have to dispatch our back-up thermal power facilities,plants to make up the electricity generation shortfall. Our thermal power plants have higher operating costs and generate GHG emissions. We may also need to buy electricity in the spot market to fulfill our solar and wind generation facilities’ contractual supply obligations, 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. Governmental authorities may withholdbe at prices higher than the approval of these environmental impact studies and therefore their processing time may be longer than expected.
Governmental authorities may also delay the distribution tariff review process, or tariff adjustments may be insufficient to pass through all ofcontracted electricity sales. These impacts could increase our costs to customers. Some aspects of the Chilean electricity law date back to 1982, and could very well experience significant regulatory changes. The government has mentioned the potential introduction of electricity distribution tariff reform, and it possible that such new regulation may adversely affect our future profitability. 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 mayor result in significant penaltieslosses 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 greenhouse gas emissions 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 impacteffect on our business, results of operations, and financial condition.
Regulatory authorities may impose fines on our subsidiaries due to operational failures or any 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.
In 2017, Enel Distribución was fined by the SEF for a total amount of 160,000 UTM (Ch$ 7.7 billion) due to various claims of infractions related to extreme inclement weather in June and July 2017. During 2017, Enel Distribución was also fined for a total amount of 35,611 UTM (Ch$ 1.7 billion) associated with breaches of quality standards of supply. For further information on fines, please refer to Note 36.3 of the Notes to our consolidated financial statements.
We depend on paymentsdistributions from our subsidiaries to meet our payment obligations.
In order to pay our obligations, weWe rely on cash from dividends, loans, interest payments, capital reductions, and other distributions from our subsidiaries.subsidiaries to pay our obligations. Such payments and distributions to us aremay be 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 aredo not in compliancecomply with certainspecified financial ratios. Our credit agreements typically prohibit any typedistribution in the event of distribution if there is an ongoing default.
Operating Results of Our Subsidiaries. The: Our subsidiaries’ 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 subsidiariessubsidiaries’ cash requirements exceed their available cash, the subsidiarythey will not be able to make cashfunds available to us.
Any of theThe situations described above could adversely affect our business, results of operations, and financial condition.
15
We are involved in litigation proceedings.
We are involved in various litigation proceedings whichthat 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 adverselyunfavorably affected if we are unsuccessful in defending lawsuits and proceedings against us. For further information on litigation proceedings, pleasePlease see “Item 8. Financial Information — A. Consolidated Statements and Other Financial Information — Legal Proceedings” and Note 36.3 of the Notes to our consolidated financial statements.statements for further information on litigation proceedings.
Construction and operation of power plants may encounter significant delays, or haltstoppages, cost overruns, and cost over-runs as well as stakeholder opposition that may damage our reputation and result in impairment ofimpair 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 theylabor. They may be subject to construction delays, strikes, adverse weather conditions, natural disasters, civil unrest, accidents, and human error. Any such event could adversely impactnegatively affect our business, results of operations, and financial condition.
Market conditions atmay change significantly between the time when the projects are initially approved may differ significantly from those that prevail when the projects are completed,approval and completion of a project, which, in some cases, make such projects commercially unfeasible.may decrease a project’s profitability or render it impracticable. This circumstance has been the case with many of our formerpast projects whichthat were initially planned under very different market conditions, with higher energy prices prevailing in the market and less competition. Deviations in these assumptions, including themarket conditions, such as estimates of the timing and expenditures, related to these projects, may lead to cost over-runsoverruns and adelays in project completion timethat widely exceedingexceed our initial estimates, which inforecasts. In turn, this may have a material adverse effect on our business, results of operationoperations, and financial condition.
TheWe may develop new projects in locations where we develop projects arethat sometimes highlyinvolve a challenging in terms of geographical topography, in some cases inon mountain slopes with very limited access. These factors may also lead to delays and cost overruns. For example, Cerro Pabellón, our 4841 MW geothermal power plant, was built at 4,500 meters above sea level and is currently we are constructing a third unit that will increase its capacity by 33MW.28 MW. We may face challenges associated with high altitudehigh-altitude construction, includingsuch as health concerns, and these may affectaffecting the construction schedule, and associated investment.investments. Additionally, given the geographic location of some projects,projects’ locations, there aremay be archaeological risks. In 2018, 11the Superintendence of the Environment filed charges against our subsidiary Geotérmica del Norte S.A. for infractions related to the archaeological issues were brought against us in connection withand operational components of the Cerro Pabellón of which three are considered material. Theyproject, could lead to fines of up to 5,000 UTM (approximately US$ 241,765), a revocation of the Environmental Qualifications Resolution (“RCA”result in its Spanish acronym) and even the shutdown of the plant. The claims result from not having implemented adequate and timely preventive measures associated with archaeological sites discovered in the grounds.high fines.
The operation of our coal-firedOur thermal power plantsplants’ operation, especially those that are coal-fired, may affect our goodwill with stakeholders due to greenhouse gasGHG emissions whichthat could adverselyunfavorably affect the environment and localnearby residents. In addition, communities might have their ownFurthermore, outside stakeholders may influence the interests and different perceptions of the company, influenced by other stakeholders or motivations unrelatedlocal communities about the Company. If we fail to the project. If the company fails to engage with itsaddress all relevant stakeholders, itstakeholders’ concerns, including environmental, social and governance criteria (“ESG”), we may face opposition, which could adverselynegatively affect our reputation, stall operations, or lead to litigation threats or action.actions. Our reputation is the foundation of our relationship with key stakeholders.stakeholders and other constituencies. If we are unable todo not effectively manage real or perceivedthese sensitive issues, thatthey could impact us negatively,adversely affect our business, results of operations, and financial condition could be adversely affected.condition.
Damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders, and ultimately leadpossibly leading to the abandonment of projects and operations that may be abandoned, causingoperations. This damage could cause our share prices to drop and hinderinghinder our ability to attract and retain valuable employees, anyemployees. Any of whichthese outcomes 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 affect 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 U.S. history. Even temporary or threatened U.S. government shutdowns 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 impact 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 U.S. dollar 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.
Our long-term electricity salesales contracts are subject to fluctuations in the market prices of certain commodities, energy, and other factors.
In our conventional generation business, we have economic exposure to fluctuations in thecertain commodity market prices of certain commodities as a result of the long termthat affect our long-term electricity sales contracts. These contracts into which we have entered. We havecommit us to material obligations as selling parties under long term fixed-price electricity sales contracts. Prices in these contracts areand contain prices indexed according to different commodities, exchange rates, inflation, and inflation. Adversethe market price of electricity. Unfavorable changes to these indices would reduce the rates we charge under our long-term fixed-price electricity salesthese contracts, which could adversely affect our business, results of operations, and financial condition.
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We are subject to incremental risks in distribution markets that are becoming more liberalized.
In our distribution business, we are also exposed to fluctuations in electricity prices. Since 2016, some customers who had freely chosen to be subject to regulated tariffs have been switchingswitched to the unregulated tariff regime instead due to the lower prices. These customers are tendering their electricity needs, either directly or in association with other customers, because regulated tariffs are currently higher than unregulated prices, given thattariffs due to the former arebeing based on contracts tendered in the past at higher prices. Lower market prices mightmay reduce the number of customers thatwho choose regulated tariffs and customers mayas they choose an alternative energy provider, reducingprovider. This situation would reduce our number of customers which couldand 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, our controlling shareholder, owns 61.9% (excluding treasury stock) of our voting shares. Enel has the power to determine the outcome of substantially all material matters that require a simple majority of 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.
Our electricity business is subject to risks arising from natural disasters, catastrophic accidents, and acts of vandalism or terrorism, thatwhich could adverselyunfavorably affect our operations, earnings, and cash flow.
Our primary facilities include power plants and distribution assets. Our facilities may be damaged byassets that are exposed to damage from catastrophic natural disasters, such as earthquakes fires and other catastrophic disasters arising from natural or accidentalfires, human causes, as well as acts of protest, vandalism, riot,protests, riots, 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 majorsignificant 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.
In mid-October 2019, widespread street demonstrations and protests erupted in Santiago and quickly spread throughout Chile. These actions became commonplace and, at times, were accompanied by looting, arson, and vandalism. Violent confrontations between protesters and the police and armed forces resulted in a significant loss of human lives and serious injuries. Accumulated damage to public and private property amounted to billions of dollars. Damage to Chile’s economy, prospects for growth, perception of risk, and immediate repercussions in unemployment and productivity loss were also significant. Our corporate headquarters in Santiago suffered a severe arson attack on October 18, 2019, resulting in the dislocation of our management and headquarters employees for an extended period. An electricity substation belonging to an unrelated company in the northern city of Copiapó was set on fire on November 28, 2019. Chilean public authorities have voiced their concern for the country’s strategic electricity infrastructure, including power stations, transmission lines, and distribution substations.
Any natural or human catastrophic disruption to our electricity assets in Chile could significantly affect our business, results of operations, and financial condition.
We are subject to financing risks, such as those associated with funding our new projects and capital expenditures and risks related toor refinancing our maturing debt; we are also subject to debt covenant compliance, all of which could adversely affect our liquidity.
existing obligations.
As of December 31, 2018,2020, our consolidated debt totaled Ch$ 2,479,624,0322.9 trillion (including Ch$ 447,317,781 in debt1.2 trillion with EFI,Enel Finance International N.V., a related company).
Some, and our most material debt obligation was the US$ 1.7 billion of ourSEC-registered bonds issued in the U.S. under the law of the State of New York.
Our debt agreements are subject to several of the following provisions, including (1) financial covenants, (2) affirmative and negative covenants, (3) events of default, and (4) mandatory prepayments for contractual breaches, (5) change of control clauses for material mergers and divestments, and (6) bankruptcy and insolvency proceeding covenants, among other provisions. others.
A significant portion of our financial indebtedness is subject to cross defaultcross-default provisions, which have varying definitions, criteria, materiality thresholds, and applicability with respect toconcerning subsidiaries that could give rise to suchresult in cross-default. Our debt may also become immediately due and payable in cases involving bankruptcy or insolvency proceedings of a cross default. We incurred debt in connection with the 2018 Reorganization. As a result, we entered into a debt agreement and we issued US$ 1 billion in bonds in the U.S that are subject to cross default provisions. In addition, since April 2018, we consolidate EGP Chile’s debt and we may incur in additional debt in the future, which may increase our debt leverage and associated financial risk.
In the event that wesignificant or our subsidiaries breach anymaterial subsidiary. Likewise, some of these contractual provisions, our debtholders may demand immediate repayment, and adecide to accelerate our debt in cross-default events dealing with significant portion of our indebtedness could become due and payable. or material subsidiaries, among other potential covenant defaults.
We may be unable to refinance our indebtednessdebt or obtain such refinancing on terms acceptable to us. In the absence of such refinancing, we could be forced to dispose ofliquidate assets in orderat unfavorable prices to make the payments due on our indebtedness under circumstances that might not be favorable to obtaining the best price for such assets. debt.
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Furthermore, we may be unable to sell our assets quickly enough,at opportune moments or at sufficiently high prices to obtain proceeds that would 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 canprevailing when we need funds could compromise our ability to finance these projects and expenditures.
Our inability to finance new projects or capital expenditures, or to refinance our existing debt, or comply with our covenants could adverselynegatively affect our business, results of operationoperations, and financial condition.
We rely onIf third-party electricity transmission facilities, that we do not owngas pipeline infrastructure, or control. If these facilities do notfuel supply contracts fail to provide us with an adequate transmission service, we may not be ableunable to deliver the powerelectricity 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 the transmission is disrupted, or transmissionits capacity is inadequate, we may be unable to sell and deliver our electricity, as has been the case of some of our solar and wind power plants located in northern Chile.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 isregulations are imposed, transmission companies upon whom we rely on may not have sufficient incentives to invest in expansion ofexpanding their transmission infrastructure, which could adverselyunfavorably affect our results of operations and financial results.condition or affect our ability to deploy our portfolio of projects under development. The construction of new transmission lines may take longer than in the past, mainly because of sustainability, social, and environmental requirements that create uncertainties regarding project completion timing. Also, our thermal power plants connected to natural gas pipelines are creating uncertainty assubject to the time of project completion.
There have been blackout eventsstoppages should material disruptions in the past duepipeline occur. Stoppages could force us to purchase electricity at spot market prices, which could be higher than the failure of transmission lines, which exposed weaknesses in the transmission grid and its need for expansion and technological improvementscontracted fixed sale price 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, whichcustomers. This scenario could adversely affect our business, results of operations, and financial condition.
Our businessWe may experience adverse consequences if we are unable tonot reach satisfactory collective bargaining agreements with our unionized employees or if we are unable to retain key employees.
employees in labor conflict cases.
A large percentage of our employees are members of unions andwith whom we have collective bargaining agreements that must be renewed regularly. For example, a labor union representing 148 workers went on a regular basis.strike as of January 12, 2021, which forced us to halt operations at the Bocamina II power plant and limit the generator park’s operational activities. A resolution to the strike was reached on January 14, 2021, and operations at the Bocamina II plant returned to normal the following day. Our business, financial condition and results of operations, and financial condition could be adverselyunfavorably affected by a failure to reach a collective bargaining agreement with any labor union representing such employees or by an agreementa deal 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, whichcannot agree. This situation is particularly true for some of our subsidiaries, including Enel Distribution, Enel Colina, and EGP Chile, and these agreements may materially increase our costs beyond what we have budgeted.costs.
In addition, weWe employ many highly-specialized employees, and certainhighly specialized employees. Specific actions such as strikes, walk-outswalkouts, or work stoppages by these employees could adversely impactnegatively affect our business, results of operations, and financial condition, as well asand reputation.
We may be unable to enter into suitable acquisitions or successfully integrate businesses that we acquire.
We review acquisition prospects that may increase our reputation.
The relative illiquiditymarket coverage or provide synergies with our existing businesses on an ongoing basis. However, there can be no assurance that we will be able to identify and volatility of the Chilean securities markets could adversely affect the price of our common stock and ADS.
Chilean securities markets are substantially smaller and less liquid than the major securities marketsacquire suitable companies in the United States orfuture. The acquisition and integration of independent companies that we do not control is generally a complicated, costly, and time-consuming process that requires significant efforts and expenditures. If we do make further acquisitions, we could incur substantial debt, assume unknown liabilities, potentially lose critical employees, be forced to amortize expenses related to tangible assets, and divert management’s attention from other developed countries. The low liquidity of the Chilean market may impair the ability of shareholders to sell shares, or holders of ADSs to sell shares of our common stock withdrawn from the ADS program, into the Chilean market in the amount and at the price and time they wish to do so. Also, the liquidity and the market for our shares or ADSs may be affected by a number of factors including variations in exchange and interest rates, the deterioration and volatility of the markets for similar securities and any changes in our liquidity, financial condition, creditworthiness, results and profitability.business concerns.
The price or the liquidity of our shares or 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, itIntegrating acquired businesses may be difficult, for them toexpensive, time-consuming, and a strain on our resources and relationships with our employees and customers. Ultimately, these acquisitions may not be successful or achieve the
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expected benefits. Any delays or difficulties encountered in connection with acquisitions and the integration of their operations could have a material adverse effect serviceon our business, results of legal process within the United States upon these persons,operations, or to enforce judgments obtainedfinancial condition.
Interruption 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, control, and communications systems or cyberattacks to or cybersecurity breaches of these systems could have a material adverse effect on our business, results of operations, and financial condition.
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, weWe use our IT Systems and infrastructure to create, collect, use, disclose, store, dispose of, and otherwise process sensitive information, including company data,and customer data and personal information regarding customers, employees and their dependents, contractors, shareholders, and other individuals. In our generation business,others. IT Systems are critical into 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.standards in our generation business. Our distribution business increasingly relies on IT Systems to monitor smart grids, billing processes for millions of customers, and customer service platforms. The operation of our generation, transmission, and distribution systems 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 deploymentimplementation of smart meters and intelligent grids.grids in Chile.
Our generation, and distribution facilities, IT Systems, and other infrastructure as well asand 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 theincreased volume and sophistication of cyber securitycybersecurity incidents from international activist organizations, nation statesnation-states, and individuals beingand are among the emerging risks identified in our planning process. Cybersecurity incidents could harm our businesses by limiting our generatinggeneration and distributingdistribution 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 and distribution business systems are 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 partythird-party service providers’ operations could also negatively impactunfavorably affect our business.
In addition, ourOur 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 significantSignificant theft, loss, or fraudulent use of personally identifiable information may lead to potentially largehigh costs associated with notifyingto notify and protectingprotect the impacted persons, and/orpersons. It could cause us to become subject to significant litigation, costs,losses, liability, fines, or penalties, any of which could materially and adversely affect our results of operations as well as ourand reputation with customers, shareholders, and regulators, among others. In addition, weWe may also 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, evolving, and evolves continually and, in the electricity industry, is increasing in sophistication, magnitude, and frequency. There canWe may be no assurance that we canunable to implement adequate preventativepreventive measures or accurately assess the likelihood of a cyber-incident.cybersecurity 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 significanthigh additional costs, including penalties, third partythird-party claims, repair costs, additionalincreased insurance expense, litigation costs, notification and remediation costs, security costs, and compliance costs. While
Risk Related to Regulatory Matters
Governmental regulations may unfavorably 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 we charge to our customers are subject to extensive regulation that may negatively affect our profitability. For example, governmental authorities might impose rationing policies during droughts or
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prolonged failures of power facilities, which may adversely affect our business, results of operations, and financial condition.
Some aspects of the Chilean electricity law have been subject to significant regulatory changes, and any such changes may unfavorably affect our future operations and profitability. For example, in the context of the social crisis that began in October 2019, the government established a transitional mechanism for stabilizing customers’ electricity prices under the regulated price system. The mechanism eliminates the price increase of 9.2% that would have been applied to regulated customers as of July 2019 and defers the price increase for the sale of electricity under contracts between generation and distribution companies that start before 2021. A price stabilization funding program was implemented by the National Energy Commission (“CNE” in its Spanish acronym) and is effectively financed by companies in the generation industry, including our subsidiary Enel Generation, through accounts receivable that are generated by the differences between the contractual rates and the stabilized rates, which are expected to enable the generation companies to recover the lost revenues by December 31, 2027. We have suffered and expect to continue to suffer a financial loss due to this revenue deferral because generation companies are being asked to finance such deferral until billing differences begin to accrue financial remuneration in 2026. Please see Note 9 of the Notes to our consolidated financial statements for further information. Other Chilean electricity sector regulations may also affect our generation companies’ ability to collect revenues sufficient to cover their operating costs and adversely affect our future profitability.
In December 2019, the Ministry of Energy’s Law No. 21,194 lowered the profitability of distribution companies and modified the electricity distribution tariff process. Among other things, the new law reduced the rate for calculating annual investment costs from 10% to a percentage calculated by the CNE every four years (which will be a yearly after-tax rate of between 6% and 8%) and established that the after-tax rate of return for each distribution company must be between three percentage points below and two percentage points above the rate calculated by the CNE. The Chilean Congress is currently discussing an electricity distribution tariff reform (“ley larga”), which, if approved, may reduce our future profitability. Tariffs remained fixed in 2020 under law 21,185, which creates a temporary electricity price stabilization mechanism for customers subject to tariff regulation. However, we expect a new tariff decree by December 2021 for the 2020-2024 period, retroactive to November 2020. We expect tariffs to be lower due to the new 6% after-tax discount rate.
Our operating subsidiaries are also subject to environmental regulations that, among other things, require us to perform environmental impact studies on future projects and obtain construction and operating permits from local and national regulators. Governmental authorities may withhold or delay the approval of these permits until the completion of environmental impact studies. Therefore, their processing time may be longer than expected. Environmental regulations for existing and future generation capacity have become stricter and require increased capital investments. Any delay in meeting the required emission standards may constitute a violation of the environmental regulations. Failure to certify monitoring systems’ original implementation and ongoing emission standard requirements may result in significant penalties and sanctions or legal claims for damages. We expect that more restrictive emission limits will be established in the future. We are also subject to an annual “green tax” based on our GHG emissions in the previous year. Such taxes may increase in the future and discourage thermal electricity generation.
Changes in the regulatory framework are often submitted to legislators and administrative authorities. Some of these changes could have a material adverse effect on our business, results of operations, and financial condition.
We are subject to potential business and financial risks resulting from climate change legislation and regulation to limit GHG emissions.
Future climate change legislation and regulation restricting or regulating GHG emissions could increase our operating costs and have a material adverse effect on our business, results of operations, and financial condition. The adoption and implementation of any international treaty, legislation, or regulation imposing new or additional reporting obligations or limiting emissions of GHGs from our operations could require us to incur additional costs to comply with such requirements and possibly require the reduction or limitation of GHG emissions associated with our operations. These higher compliance standards may involve additional costs to operate and maintain our equipment and facilities,
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install emission controls, or pay taxes and fees relating to GHG emissions, which could have a material adverse effect on our business, results of operations, and financial condition.
Our business faces risks from promoting decarbonization efforts both on a global and national scale.
In June 2019, the Chilean government announced its plan to phase out coal entirely from its energy mix by 2040 and achieve carbon neutrality by 2050. Our subsidiaries, Enel Generation and GasAtacama signed an agreement with the Chilean Ministry of Energy defining the process for the closures of our coal-fired power plants: Tarapacá (158 MW), Bocamina I (128 MW), and Bocamina II (350 MW). We closed the Tarapacá plant in December 2019 and the Bocamina I plant in December 2020, both ahead of schedule. We expect to close the Bocamina II plant by May 2022, well ahead of the scheduled deadline of December 31, 2040.
Even though the Chilean government’s plan to achieve decarbonization may overlap with our sustainability strategy, the governmental targets’ actual implementation may exert considerable pressure on us and our ability to satisfy our contractual obligations with other cleaner sources. In turn, this may increase our expenses, decrease our profitability, and limit our ability to satisfy electricity demand fully.
Our business and profitability could be unfavorably affected if water rights are denied or if water concessions are granted with limited duration.
The Chilean Water Authority (Dirección General de Aguas) grants us water rights for water supply from rivers and lakes near our production facilities. Currently, these water rights are (i) for unlimited duration, (ii) absolute and unconditional property rights, and casualty(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, and the conditions of such water rights may affect the design, timing, or profitability of a project.
Also, the new Chilean constitution being drafted may change existing rights, including rights to exploit natural resources and water and property rights, any of which could adversely affect our business, results of operations, and financial condition.
Any limitations on our water rights, the granting of additional water rights, or on the duration of our water concessions could have a material adverse effect on our hydroelectric development projects and profitability.
Regulatory authorities may impose fines on our subsidiaries due to operational failures or any breaches of regulations.
Our electricity businesses are subject to regulatory fines for any breach of current regulations, including failures to supply energy. Local regulatory entities supervise our generation subsidiaries. They may be subject to fines or penalties when the regulator determines that the company is responsible for the operational failures that affect the system’s regular energy supply, including coordination issues. 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.
In 2020, the Superintendence of Electricity and Fuels (“SEF”) fined Enel Distribution 22,000 UTM (Ch$ 1.1 billion) for breaches in quality standards of supply. On December 3, 2020, Enel Distribution filed an appeal of the SEF fine, which is still pending as of the date of this Report. Please refer to Note 38 of the Notes to our consolidated financial statements for further information on fines. Additionally, in 2020, SEF fined Enel Distribution 40,000 UTM (Ch$ 2 billion) for failure to comply with technical quality standards. Enel Distribution filed an appeal on November 13, 2020, and a final decision is still pending.
Risk Related to Chile and Other Global Risks
Fluctuations in the Chilean economy, economic interventionist measures by governmental authorities, political and financial events, or other crises in Chile and other countries may affect our results of operations, financial condition, liquidity, and the value of our securities.
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All our operations are in Chile. Accordingly, our revenues are affected by the performance of the Chilean economy. Chile is also vulnerable to external shocks, such as financial and political events, that could cause significant economic difficulties and affect economic growth. If Chile experiences lower than expected economic growth or a recession, our customers will likely demand less electricity. Some of our customers may experience difficulties paying their electric bills, possibly increasing our uncollectible accounts.
We are exposed to economic and political volatility, including civil unrest in Chile due to the challenges arising from changes in economic conditions, regulatory policies, laws governing foreign trade, manufacturing, development, and investments, and various crises and uncertainties. These factors, either individually or in the aggregate, could severely impact Chilean economic growth and our business, results of operations, and financial condition. Starting in October 2019, Chile began to experience social turmoil throughout the country. Increasingly violent student and civil protests brought about widespread and severe tensions, indiscriminate violence and vandalism, significant public and private sector property damage, and disruption to institutions, commerce, general safety, civilian welfare, and peace. In response, the government launched various political, social, and economic reforms, including a guaranteed minimum wage, an increase in government-subsidized pensions, stabilization of electricity costs, a higher tax bracket for high-income earners, new health insurance programs, a pay cut for the members of the Chilean Congress and certain civil servants, and authorizing current withdrawals from individually funded private-sector pension accounts that usually only permit withdrawals in retirement.
In this context, the Chilean government held a national referendum in October 2020 to decide whether to create a new Chilean constitution and whether a popularly elected assembly or a combination of current legislators and a popularly elected assembly would draft the new constitution. Nearly 80% of voters approved the referendum for a new constitution and opted to have a popularly elected assembly draft the new constitution. Any new constitution could alter the Chilean political situation, affect the Chilean economy and its business outlook. A new constitution may also change existing rights, including rights to exploit natural resources, and water and property rights, any of which could adversely affect our business, results of operations, and financial condition.
Future adverse developments in Chile, including political events, financial or other crises, changes to policies regarding foreign exchange controls, regulations, and taxation, may impair our ability to execute our business plan and 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. Economic and market conditions influence Chilean financial and securities markets in other countries. They may be affected by international events, which could unfavorably affect the value of our securities.
We are subject to the adverse effects of worldwide pandemics.
An international public health crisis, such as the one attributable to the Covid-19 pandemic that began in December 2019, has led to high unemployment levels in Chile and has impacted electricity demand, financial markets, and the ability of our business to generate income. For the year ended December 31, 2020, sales from energy distribution decreased 3.8%, sales from energy generation decreased 2.4%, and our collection rates fell 2.1%. We believe that the Covid-19 pandemic lowered our net income due to lower energy demand and increased uncollectible debts.
In March 2020, due to the Covid-19 pandemic, Chilean President Sebastián Piñera decreed a state of emergency (estado de excepción constitucional de catástrofe) for an initial 90 days, which was subsequently extended several times and is currently in effect until June 30, 2021. Under this executive authority, President Piñera has instituted nighttime military curfews, selective mandatory quarantines in affected areas, control of entrance, exit and traffic within specified zones, the prohibition of mass gatherings, and the closing of public schools, among other measures. The private sector has voluntarily taken further actions, such as adopting telecommuting wherever possible and closing commercial offices. Many businesses, such as restaurants and retail stores, have temporarily closed or have opened under constrained capacity, either voluntarily or by executive decree. Companies associated with travel, transportation, and tourism have been severely affected, and many have gone bankrupt.
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The government also announced the tightening of Chile’s borders through the month of April 2021. Chilean citizens and residents may enter Chile but are not allowed to depart from the country unless they qualify for exceptional consideration. Non-resident foreigners will not be allowed to enter Chile but will be permitted to depart.
The cumulative effect of measures of this kind has led to high unemployment levels, reduced business operations, closures of businesses, reduced travel, and decreased demand for electricity. Recent increases in infection rates indicate a second wave of Covid-19 infections in 2021. In February 2021, Chile began to implement a widespread vaccination program. However, if there is a resurgence of the Covid-19 pandemic for any reason, including new strains for which vaccines are unavailable, or the vaccination program is ineffectual, our business, results of operations, and financial condition may be materially adversely affected.
Political events or financial or other crises in any region worldwide can significantly impact Chile and may unfavorably affect our operations and liquidity.
Chile is vulnerable to external shocks that could cause significant economic difficulties and affect growth. If Chile experiences lower than expected economic growth or a recession, it is likely that consumer demand for electricity will decrease and that some of our customers may have 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 negatively affect our business. For example, since 2018, the U.S. and China have been involved in a trade war involving protectionist measures that increase volatility in financial markets worldwide due to the uncertainty of political decisions. Also, instability in the Middle East or any other major oil-producing region could result in higher fuel prices worldwide, which would increase the operating costs for our thermal generation power plants and unfavorably affect our results of operations and financial condition. An international financial crisis and its disruptive effects on the financial industry could adversely affect our ability to obtain new bank financings under 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 capital markets in Chile and international capital markets as sources of liquidity or increase interest rates available to us. Reduced liquidity could negatively affect our capital expenditures, long-term investments and acquisitions, growth prospects, and dividend payout policy.
Foreign exchange risks may unfavorably 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 no assurancesubject to significant fluctuations in the future. We pay our dividends in Chilean pesos, and a substantial portion of our consolidated indebtedness has historically been in U.S. dollars. Although a substantial amount of our operating cash flows is linked to the U.S. dollar, we are exposed to fluctuations in the Chilean peso against the U.S. dollar because of time lags and other limitations to pegging our tariff rates to the U.S. dollar. This exposure can substantially decrease the value of the cash we generate in U.S. dollars due to the peso’s devaluation. Future volatility in the currency exchange rate in which we receive revenues or incur expenditures may adversely affect our business, results of operations, and financial condition.
Risk Related to Ownership of Our Shares and ADS
Our controlling shareholder may influence us and may have a strategic view for our development that liabilitiesdiffers from that of our minority shareholders.
Enel, our controlling shareholder, owns 64.9% of our voting shares as of the date of this Report. Under Chilean corporate law, Enel has the power to determine the outcome of substantially all material matters that require a simple majority of shareholders’ votes, such as the election of the majority of the seats on our board, and, subject to contractual and legal restrictions, the adoption of our dividend policy. Enel also exercises significant influence over our business strategy and operations. However, in some cases, its interests may differ from those of our minority shareholders.
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Certain conflicts of interest affecting Enel in these matters may be resolved in a manner that is different from the interests of our company or lossesour minority shareholders.
The relative illiquidity and volatility of the Chilean securities markets could unfavorably affect the price of our common stock and ADS.
Chilean securities markets are substantially smaller and have less liquidity than major securities markets in the United States and other developed countries. The low liquidity of the Chilean markets may impair shareholders’ ability to sell shares, or holders of ADS to sell shares of our common stock withdrawn from the ADS program, on Chilean Stock Exchanges in the amount and at the desired price and time.
Lawsuits against us brought outside of Chile or complaints against us based on foreign legal concepts may be unsuccessful.
All our operations are located outside of the United States. All our directors and officers reside outside of the United States, and substantially all their assets are located outside the United States. If investors were to bring a lawsuit against our directors and officers in the United States, it may be difficult for them to effect service of legal process within the United States upon these persons. It may also be difficult to enforce judgments obtained in the U.S. courts based on civil liability provisions of U.S. federal securities laws against them in U.S. or Chilean courts. There is also doubt about whether an action could be brought successfully in Chile for liability based solely on the civil liability provisions of U.S. federal securities laws.
We identified a material weakness in our internal controls over financial reporting, which, if not remediated, could result in material misstatements of our consolidated financial statements or cause us to fail to meet our periodic reporting obligations.
Our management assessed the effectiveness of its internal control over financial reporting as of December 31, 2020, based on criteria established in the framework “Internal Controls — Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the assessment, we may incur,have identified a material weakness in our internal control over financial reporting related to our general information technology controls, including asthe design and implementation of access and change management controls. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. As a result, our management has concluded that as of cybersecurity litigation,December 31, 2020, our internal control over financial reporting was not effective, although our consolidated financial statements included in this Annual Report on Form 20-F present fairly, in all material respects, our consolidated financial position, results of operations, and cash flows as of the dates and for the periods presented. See “Item 15. Controls and Procedures.”
The material weakness will not be coveredconsidered remediated until any applicable new or enhanced controls operate for a sufficient period, and management has concluded through testing that these controls are operating effectively. As of the date of this Report, the material weakness with respect to our internal control over financial reporting has not been remediated.
Any failure, difficulties, or delay in implementing and maintaining such remedial measures could (i) result in a material misstatement in our financial reporting or financial statements that would not be prevented or detected, (ii) cause us to fail to meet our reporting obligations under such policiesapplicable securities laws, or that(iii) cause investors to lose confidence in our financial reporting or financial statements, the amountoccurrence of insurance will be adequate.any of which could materially and adversely affect our business, financial condition, cash flows, results of operations, and the prices of our securities.
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Item 4.Information on the Company
A.History and Development of the Company.
A. | History and Development of the Company. |
We are a publicly held limited liability stock corporation organized on March 1, 2016, under the laws of the Republic of Chile. Since April 2016, we have been registered in Santiago with the CMF under Registration No. 1139. We are also registered with the SEC under the commission file number 001-37723. Our full name is Enel Chile S.A., and we are also known commercially as “Enel Chile”.
Chile.” As of December 31, 2020, Enel beneficially owned 61.9% (excluding treasury stock)64.9% of our Company as of December 31, 2018.shares. Our shares are listed and traded on the Chilean Stock Exchanges under the trading symbol “ENELCHILE,” and our ADSsADS are listed and traded on the NYSE.NYSE under the trading symbol “ENIC.”
Our contact information in Chile is:
Contact Person: | Nicolás Billikopf |
Street Address: | Av. Santa Rosa 76, Piso 15 Comuna de Santiago Santiago, Chile |
| nicolas.billikopf@enel.com |
Telephone: |
|
| www.enelchile.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 interneta 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 through our subsidiaries and affiliates, in the generation, transmission, and distribution of electricity businesses in Chile.Chile through our subsidiaries and affiliates. As of December 31, 2018,2020, we had 7,4637,200 MW of gross installed capacity and 1.92.0 million distribution customers. OurOf our total gross installed capacity, is comprised66% corresponds to renewable energies, including 3,561 MW of 48 generation facilities, of which 48% are hydroelectric power plants.plants, 642 MW of wind farms, 496 MW of solar plants, and 48 MW of geothermal capacity. Approximately 86% of our gross thermoelectric installed capacity corresponds to gas/fuel oil power plants (2,104 MW) and the remaining to coal-fired steam power plants (350 MW). As of December 31, 2018,2020, we had consolidated assets amounting to Ch$ 7,488 billion7.9 trillion and operating revenues of Ch$ 2,457 billion.2.6 trillion.
We have been known as Enel Chile since the completion of the 2016 Reorganization described further below.that separated Enersis’s Chilean businesses from its non-Chilean companies. However, we trace our origins to Compañía Chilena de Electricidad Ltda. (“CCE”), which was formed in 1921 as a result ofin the merger of Chilean Electric Tramway and Light Co., founded (founded in 1889,1889) and Compañía Nacional de Fuerza Eléctrica with operations dating(dating back to 1919.1919). Following the nationalization of CCE in the 1970s, during the 1980s, the Chilean electric utility sector was reorganized through the Chilean Electricity Law, known as Decree with Force of Law No. 1 of 1982 (“DFL1”). CCE’s operations were divided into one generation company, a currently unrelated company, and two distribution companies, one with a concession in the Valparaíso Region, and the other, our predecessor company, with a concession in the Santiago Metropolitan Region. From 1982 to 1987, the Chilean electric utility sector went through a process of re-privatization. In August 1988, our predecessor company changed its name to Enersis S.A. (“Enersis” and currently known as Enel Américas S.A.) and. It became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A (“Chilectra” and currentlypresently known as Enel Distribución Chile S.A.). In the 1990s, Enersis diversified into electricity generation through increasing equity stakes in Endesa Chile S.A. (currently known as Enel Generación Chile S.A.).
The 2016 Reorganization
During 2016, we completed a corporate reorganization to separate Enersis’s Chilean businesses from its non-Chilean businesses (the “2016 Reorganization”).
The 2016 Reorganization involved the separation As of the respective Chilean and non-Chilean electricity generation, transmission and distribution businesses of Endesa Chile, Chilectra and Enersis by means of a “demerger” under Chilean law and the subsequent
distribution of the shares of the newly created entities to each company’s respective shareholders (collectively, the “Spin-Offs”). 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 from Enersis Chile S.A. to31, 2020, Enel Chile S.A. on October 18, 2016. That same date, (i) Endesa Chile changed its name toowns 99.1% of Enel Generación Chile S.A.;Distribution and (ii) Chilectra changed its name to93.5% of Enel Distribución Chile S.A.Generation.
The 2018 Reorganization
On August 25, 2017, we proposed a corporate reorganization (the “2018 Reorganization”) to consolidate Enel’s conventional and non-conventional renewable energy (“NCRE”) businesses in Chile under our company, Enel Chile, 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 for all outstanding shares of common stock (including ADS) of Enel Generation. |
· 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 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 ADS to satisfy all conditions precedent; and |
● | a merger in 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 controlled by Enel. EGPL was a renewable energy generation holding company engaged in the electricity generation business in Chile through its wholly-owned subsidiary Enel Green Power Chile S.A. (“EGP Chile”). |
· 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 approved the different steps of the 2018 Reorganization 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, we increased our economic interest in Enel Generation from 60% to 93.6% economic interest, we93.5%, and EGP Chile is wholly owned. We continue to own 99.1% of Enel Distribución and EGP Chile is wholly-owned. Currently, weDistribution.
We currently consolidate theour Chilean conventional and renewable electricity generation business throughunder Enel Generation, theour Chilean electricity distribution business throughunder Enel DistribuciónDistribution, our Chilean electricity transmission business under Enel Transmission, and theour Chilean non-conventional renewable electricityNCRE generation business throughunder EGP Chile. Enel remains as our parent company and our majority shareholder, owning 61.9% (excluding treasury stock)64.9% of our Company.Company as of December 31, 2020, and the date of this Report.
During the last few years, our business strategy has focused on our core business. We have increased our shareholdings in subsidiaries related to electricity generation, divested certain non-strategic assets, and reduced the number of our companies, simplifying our corporate structure, mainly through mergers.
WeEnel Generation
In June 2019, Enel Generation and its subsidiary GasAtacama signed an agreement with the Ministry of Energy that complemented our sustainability strategy and strategic plan and defined the process for the progressive closure of our coal-fired power plants Tarapacá, Bocamina I, and Bocamina II, which have conducteda gross installed capacity of 158 MW, 128MW, and 350 MW, respectively.
The agreement is subject to the following sales of non-core assets over the past three 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 this 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 operationsfull implementation of the facility beganPower Transfer Regulation, which defines the Strategic Reserve State and establishes, among others, the essential conditions that ensure non-discriminatory treatment between generation companies. Under the agreement, we were formally and irrevocably obligated to close Bocamina I and Tarapacá. The deadline for closing Tarapacá was May 31, 2020; however, upon receiving authorization from the National Energy Commission (“CNE” in September 2009its Spanish acronym) to move up the date of the closure of Tarapacá, we closed the plant ahead of schedule on December 31, 2019. The deadlines for closing Bocamina I and full commercial operations beganBocamina II are December 31, 2023, and December 31, 2040, respectively. Nevertheless, we shut down Bocamina I on January 1, 2011.
· On December 16, 2016, we sold our 42.5% equity interest31, 2020, and expect to voluntarily shut down Bocamina II by May 2022, well ahead of the deadline of 2040. By the end of 2022, Enel Chile, acting through Enel Generation, will become the first electricity company in Electrogas S.A. (“Electrogas”). Electrogas is a company dedicatedChile 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.complete its decarbonization process.
In order toTo simplify our corporate structure, we have continued to reduce the number of our companies over the last threeseveral years:
· During 2016, Inversiones GasAtacama Holding Ltda. merged into Celta, which later 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 Eólica Canela S.A., which owns the Canela wind farms.26
· On November 9, 2017, GasAtacama purchased the 25% minority interestTable of Central Eólica Canela S.A, which was dissolved on December 22, 2017. Our economic interest in GasAtacama was 93.7% as of December 31, 2018.Contents
● | During 2016, Inversiones GasAtacama Holding Ltda. merged into Celta, which later 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 Eólica Canela S.A., which owns the Canela wind farms. |
● | On November 9, 2017, GasAtacama purchased the remaining 25% minority interest in Central Eólica Canela S.A, which was dissolved on December 22, 2017. Our economic interest in GasAtacama was 93.7% as of December 31, 2018. |
● | In September 2019, we completed the intercompany sale of our 2.6% stake in GasAtacama to Enel Generation. On October 1, 2019, GasAtacama merged into Enel Generation. This transaction reorganized and simplified the corporate structures of the subsidiaries that comprised the GasAtacama group to generate corporate and operational efficiencies for us. |
EGP ChileEnel Distribution
Pursuant to Law No. 21,194 (known as “Ley Corta”) adopted in 2020, the Ministry of Energy requires Chilean distribution companies to operate as a separate public distribution business line with its own accounting and management without including other businesses, such as an electricity transmission business.
On December 3, 2020, Enel Distribution held an extraordinary shareholders’ meeting to approve the separation of its distribution and transmission business lines into two separate companies. Enel Distribution carried out a corporate reorganization on January 1, 2021, pursuant to which each shareholder of Enel Distribution received one share of the new company, Enel Transmission, for each share of Enel Distribution held, maintaining the same ownership position in each company after the spin-off. The energy commercialization segment, formerly executed by Enel Distribution, was transferred to Enel Generation Chile to improve synergies and cost-efficiency among affiliates.
Enel Green Power Chile (EGP Chile)
To simplify the organizational structure, we reorganized EGP Chile currently has 20 operational power plants with a total installed capacityto reduce the number of 1,189 MW consisting of 92 MW of hydroelectric power, 564 MW of wind power, 492 MW of solar power, and 41 MW of geothermal power.
In 2015,companies within the EGP Chile focused on continued growth as well as maintenance of existing facilities impacted by natural disasters. In particular, it rebuiltgroup, including the Diego de Almagro solar power plant after it was damaged by floods, as well as the Talinay Oriente and Talinay Poniente wind plants which were damaged by an 8.4-magnitude earthquake in Northeast Chile. A volcanic eruption in Southern Chile also affected plant operations. That year, EGP Chile also began construction on the Cerro Pabellón geothermal plant (the first in South America at 4,500 meters above sea level), the Los Buenos Aires and Renaico wind farms, and the Pampa Norte solar plant. By the end of 2015, EGP Chile totaled 606 MW of installed capacity and completed construction of the Carrera Pinto solar plant. In 2016, EGP Chile began operating the La Silla solar plant and began construction on the Sierra Gorda Este wind plant and by the end of that year, it reached its goal of 1 GW of installed capacity in Chile, well before the 2017 target.following steps:
● | on June 1, 2020, six subsidiaries of EGP Chile were merged and subsequently dissolved: Parronal SpA, Parque Solar Maipu SpA, Crucero de Atacama SpA, Crucero Este Uno SpA, Crucero Este Dos SpA, and Crucero Este Tres SpA; and |
During 2017, Cerro Pabellón geothermal plant start operation adding 48 MW to the total installed capacity, consolidating us as the Chilean multi-technology leader with a very well diversified portfolio of renewable energy. EGP Chile has become a leader in Chile’s renewable energy market (in terms of installed capacity) with a mixed portfolio of wind, solar, hydroelectric and geothermal power.
● | on July 1, 2020, Panguipulli merged into Taltal Wind Farm (the legal surviving entity) and on August 1, 2020, Taltal Wind Farm merged into Almeyda Solar. On January 1, 2021, Almeyda Solar merged into EGP Chile (the legal surviving entity). |
Enel X Chile
On September 7, 2018, we formed a new wholly-owned subsidiary, Enel X Chile SpA (“Enel X Chile”), to develop, implement and sell products and services that incorporate innovation and cutting-edge technology and are different from the sale of energy or concessioned energy distribution. Enel X Chile expects to offer turnkey projects for municipalities and other public and governmental entities, industrial or residential customer appliances such as photovoltaic systems, heating ventilation air conditioning, led lighting, projects related to energy efficiency, and the development of public and private electric mobility and charging infrastructure, in all cases including customers outside of our concession area. As of December 31, 2018, we supported installation of over 40 public charge stations, some of which located outside the Metropolitan Region concession area. In addition, we are offering smart charging solutions, including household devices or office devices having a load capacity of 2 to 4 times faster than a conventional plug.
Capital Investments, Capital Expenditures, and Divestitures
We coordinate our overall financing strategy, including the terms and conditions of loans and intercompany advances entered into by our subsidiaries, in order to optimize debt and liquidity management. Generally, our operating subsidiaries independently plan capital expenditures financed by internally generated funds or direct financings. One of our goals is to focus on investments that will provide long-term benefits and sustainability initiatives. On the other hand, inbenefits. In the distribution business, we will continue investing with the aim to allow the connection of new customers, increase the quality of our service quality, and inintroduce new technologies (such as smart meters) to automate our networks. 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 timewhen the cash flows are needed.
Our investment plan is flexible enough to adaptand adapts to changing circumstances by givingassigning different priorities to each project in accordance withaccording to profitability, strategic fit, and strategic fit. Investment prioritiessustainability. We are currently focused on making investments on
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behalf of the distribution business related to network reliability, capacity improvement, and new technologytechnological developments, such as smart meters.meters, while keeping the environment in mind.
For the 2019-20212021-2023 period, we expect to make capital expenditures of Ch$ 1,355 billion1.67 trillion in our subsidiaries, related to investments currently in progress, maintenance of our distribution network and generation plants, and in studies required to develop other potential generation and distribution projects. For further detail regarding these projects, pleasePlease see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Development”. for further detail regarding these projects.
The table below sets forth the expected capital expenditures for the 2019-20212021-2023 period and the capital expenditures incurred in 2018, 20172020, 2019, and 2016:2018:
|
| Estimated |
| 2018 |
| 2017 |
| 2016 |
|
|
| (in millions of Ch$) |
| ||||||
Capital Expenditure(1) |
| 1,355,018 |
| 300,539 |
| 266,030 |
| 222,386 |
|
| | | | | | | | |
|
| Estimated |
| 2020 |
| 2019 |
| 2018 |
| | (in millions of Ch$) | ||||||
Capital Expenditure(1) | | 1,674,000 | | 554,314 | | 321,079 | | 300,539 |
(1) Capex amounts represent effective payments for each year, except for future projections.
(1) | Capital Expenditure figures listed in this table represent cash flows used to purchase property, plant and equipment, and intangible assets for each year, except for future projections. |
While our planned investments go beyond the three years highlighted in this table, we are reportingreport three years to be alignedalign with Enel’s three-year industrial plan that was disclosed in November 2018. For further information, pleaseDecember 2020. 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”. for further information.
Capital Expenditures in 2020, 2019, and2018 2017 and 2016
Our capital expenditures inIn the last three years, our capital expenditures were principally related to the optimization of the 350 MW Bocamina II power plant, improvements to the Tarapacá coal-fired power plant, the construction ofCampos del Sol I, Domeyko, and Sol de Lila solar projects, the 150 MW Los Cóndores hydroelectric power plant, Renaico II wind farms, and maintenance of our currentexisting power plants. Investments relatedThese projects aim to the Bocamina II and Tarapacá power plants focused on making improvementsadd 1,043 MW of installed capacity 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. During 2018, we also concluded investments associated with the 48 MW Cerro Pabellón power plant, the first geothermal plant in South America.our generation mix.
In 2018,2020, our investments in the distribution business were focused on connections offacilitating new customers,customer connections, reinforcing feeders mainly to increase our service quality, increasing the capacity of our substations, automatization ofand automating our systems through the installation of control remote devices and smart meters for residential customers.
In 2020, our generation business material plans in progress include Los Cóndoresinvestments focused primarily on the Campos del Sol I and II solar projects, the Domeyko solar project, which began construction in 2014 with completion expected during 2020. For further detail of the Los Cóndores hydroelectric project, pleaseand the Renaico II wind farms. Please see “Item 4. Information on the Company — D. Property, Plant and Equipment.Equipment — Projects Under Construction.”Construction” for further detail on our projects.
In our distribution business, we plan to continue to expand our services, control energy losses, and increase our quality of service in order to improve the efficiency of our facilities, profitability of our business, and increase our capacity to satisfy our growing number of customers and their increasing demands.
AWe reserve a portion of our capital expenditures is reserved for maintenance and for the assurance of our facilities’ quality and operational standards of our facilities.standards. Projects in progress will be financed with resources provided by external financing as well as internally generated funds.
B.Business Overview.
B. | Business Overview. |
We are a publicly held limited liability stock corporation that operates in Chile. Our core business is electricity, both generation, transmission, and distribution. We conduct our business through Enel Generation, andEnel Transmission, Enel Distribution, and their respective subsidiaries. The transmission business was spun off from Enel Distribution as of January 1, 2021, and is therefore not reported as a separate business segment as of December 31, 2020.
We also participate in other activities but that are not core businesses and represent less than 1% of our 20182020 revenues. We do not report them as a separate business segment in this Report noror in our consolidated financial statements.
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The table below presents our revenues:
| | | | | | | | |
| | Year ended December 31, | ||||||
Revenues |
| 2020 |
| 2019 |
| 2018 |
| Change 2020 vs. 2019 |
| | (in millions of Ch$) | | (in %) | ||||
Generation | | 1,577,422 | | 1,726,612 | | 1,580,653 | | (8.6) |
Distribution | | 1,382,068 | | 1,412,872 | | 1,263,224 | | (2.2) |
Other businesses and intercompany transaction adjustments | | (374,088) | | (368,649) | | (386,716) | | (1.5) |
Total revenues | | 2,585,402 | | 2,770,834 | | 2,457,161 | | (6.7) |
|
| Year ended December 31, |
| ||||||
Revenues |
| 2018 |
| 2017 |
| 2016 |
| Change |
|
|
| (in millions of Ch$) |
| (in %) |
| ||||
Generation |
| 1,580,653 |
| 1,634,937 |
| 1,659,727 |
| (3.3 | ) |
Distribution |
| 1,263,224 |
| 1,326,659 |
| 1,315,761 |
| (4.8 | ) |
Other businesses and intercompany transaction adjustments |
| (386,716 | ) | (438,618 | ) | (433,921 | ) | (11.8 | ) |
Total revenues |
| 2,457,161 |
| 2,522,978 |
| 2,541,567 |
| (2.6 | ) |
For further financial information related to our revenues, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 3528 of the Notes to our consolidated financial statements.
Electricity Generation Business Segment
We through our subsidiaryhold a 93.5% economic interest in Enel Generation, in which we hold a 94% economic interest asaccounted for 32% of the date hereof, are a generation operatorNational Electricity System’s (“SEN” in the SEN, representing 34.2% of theits Spanish acronym) total electricity market sharesales in 2018.
2020. As of December 31, 2018,2020, we accounted for 31.5%28% of the SEN’s total generation capacity, measured by the installed capacity, according to figures published by the National Electricity Coordinator (“CEN” in its Spanish acronym).capacity. Hydroelectric, thermal, solar, wind, and geothermal power represent 47.5%49.5%, 36.7%34.1%, 6.6%6.9%, 8.6%8.9%, and 0.5%0.7% of our total installed capacity in Chile, respectively.Chile.
For the year ended December 31, 2020, our consolidated electricity generation was 19,331 GWh in 2020. Our sales were 22,960 GWh, representing an 8.1% decrease in electricity generation and a 2.4% decrease in sales compared to 2019.
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) (2) |
| 1,030 |
| 111 |
| 111 |
|
Installed capacity (MW)(3) |
| 7,463 |
| 6,351 |
| 6,351 |
|
Electricity generation (GWh) |
| 20,046 |
| 17,073 |
| 17,564 |
|
Energy sales (GWh) |
| 24,369 |
| 23,356 |
| 23,689 |
|
| | | | | | |
| | Year ended December 31, | ||||
|
| 2020 |
| 2019 |
| 2018 |
Number of generating units(1) | | 1,028 | | 1,029 | | 1,030 |
Installed capacity (MW)(2)(3) | | 7,200 | | 7,303 | | 7,463 |
Electricity generation (GWh) | | 19,331 | | 21,041 | | 20,046 |
Energy sales (GWh) | | 22,960 | | 23,513 | | 24,369 |
(1)
(1) | For details on generation facilities, see “Item 4. Information on the Company — D. Property, Plant and Equipment — Property, Plant and, Equipment of Generation Companies.” |
(2) | Total installed capacity is 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) | Bocamina I and Tarapacá steam turbine and coal plants were decommissioned on December 31, 2020, and December 31, 2019, respectively. |
(2) The increaseIt is common in the number of generating units from 2017electricity industry to 2018 isdivide the result of including the EGP Chile solar plants, since each inverter element is considered a generating unit.
(3) 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.
Our consolidated electricity generation was 20,046 GWh in 2018 and our sales were 24,369 GWh, which represents a 17% and 4% increase, when compared to 2017, respectively.
Dividing the electricity generation business into hydroelectric, thermoelectric, and other generation is customary in the electricity industry,types because each generation type has significantly different variable costs. Thermoelectric generation for instance, requires thefuel purchase, of fuel, which generally leads to higher variable costs than hydroelectric generation from reservoirs or rivers, that normallywhich typically has minimalimmaterial variable costs. Of our total consolidated generation in 2018, 56.8%2020, 50.2% was from hydroelectric sources, 31.3%33.4% was from thermal sources, and 11.9%16.4% was from solar and wind energy.
The following table summarizes our consolidated generation by type of energy:
29
GENERATION BY TYPE OF ENERGY (GWh)
|
| Year ended December 31, |
| ||||||||||
|
| 2018 |
| 2017 |
| 2016 |
| ||||||
|
| Generation |
| % |
| Generation |
| % |
| Generation |
| % |
|
Hydroelectric |
| 11,395 |
| 56.8 |
| 9,652 |
| 56.5 |
| 9,078 |
| 51.7 |
|
Thermal |
| 6,268 |
| 31.3 |
| 7,292 |
| 42.7 |
| 8,379 |
| 47.7 |
|
Other generation(1) |
| 2,384 |
| 11.9 |
| 129 |
| 0.8 |
| 107 |
| 0.6 |
|
Total generation |
| 20,046 |
| 100 |
| 17,073 |
| 100 |
| 17,564 |
| 100 |
|
| | | | | | | | | | | | |
| | Year ended December 31, | ||||||||||
| | 2020 | | 2019 | | 2018 | ||||||
|
| Generation |
| % |
| Generation |
| % |
| Generation |
| % |
Hydroelectric | | 9,712 | | 50.2 | | 10,578 | | 50.3 | | 11,395 | | 56.8 |
Thermal | | 6,452 | | 33.4 | | 7,233 | | 34.4 | | 6,268 | | 31.3 |
Other generation(1) | | 3,166 | | 16.4 | | 3,230 | | 15.4 | | 2,384 | | 11.9 |
Total generation | | 19,331 | | 100.0 | | 21,041 | | 100.0 | | 20,046 | | 100.0 |
(1) Other generation refers to the generation from wind and solar energy.
(1) | Other generation includes wind, solar, and geothermal energy. |
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 |
| Sales |
| % of Sales |
| Sales |
| % of Sales |
|
Regulated customers |
| 15,645 |
| 64.2 |
| 17,029 |
| 72.9 |
| 18,516 |
| 78.2 |
|
Unregulated customers |
| 7,549 |
| 31.0 |
| 5,586 |
| 23.9 |
| 4,321 |
| 18.2 |
|
Total contracted sales(1) |
| 23,194 |
| 95.2 |
| 22,615 |
| 96.8 |
| 22,838 |
| 96.4 |
|
Electricity pool market sales |
| 1,174 |
| 4.8 |
| 742 |
| 3.2 |
| 852 |
| 3.6 |
|
Total electricity sales |
| 24,369 |
| 100 |
| 23,356 |
| 100 |
| 23,689 |
| 100 |
|
| | | | | | | | | | | | |
| | Year ended December 31, | ||||||||||
| | 2020 | | 2019 | | 2018 | ||||||
|
| Sales |
| % of Sales |
| Sales |
| % of Sales |
| Sales |
| % of Sales |
Regulated customers | | 10,838 | | 47.2 | | 12,712 | | 54.1 | | 15,645 | | 64.2 |
Unregulated customers | | 11,043 | | 48.1 | | 9,902 | | 42.1 | | 7,549 | | 31.0 |
Total contracted sales(1) | | 21,881 | | 95.3 | | 22,614 | | 96.2 | | 23,194 | | 95.2 |
Electricity pool market sales | | 1,079 | | 4.7 | | 899 | | 3.8 | | 1,174 | | 4.8 |
Total electricity sales | | 22,960 | | 100.0 | | 23,513 | | 100.0 | | 24,369 | | 100.0 |
(1) Includes sales to distribution companies not backed by contracts.
(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 managingcustomers helps manage and understandingunderstand 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’their regulated customers, that is, either residential, commercial, or others, are classified as regulated sales and are subject to government regulatedgovernment-regulated electricity tariffs. TheGeneration companies’ sales of generation companies to distribution companies to supply the distributors’their unregulated customers are also classified as unregulated sales and are also governed by contracts at a freely negotiated prices and terms. We sell directly sell to large commercial and industrial customers and other generators. The sales to 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 placeoccur either when SEN dispatches 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 generatorsgenerators’ electricity dispatched is less than their contractual commitments with their customers and thereforecustomers. Therefore, they must purchase the deficit in the pool market. These purchase and sale transactions among electricity generation companies are normally carried outtypically made 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 consider the available statistical information concerning rainfall, mountain snow and ice, and when they are expected to melt, hydrological levels, and the capacity of keycritical 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
30
water users, and including pass-through cost clauses in contracts with customers to cover the cost of the spot market purchases.
In 2022, distribution company contracts awarded in the August 2016 auction will come into effect and thereforeeffect. Therefore, the tariffs of our regulated contracts will decrease by 6% as a consequence ofdue to 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% 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, through Enel Generation, 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, thesegeneration. These prices are 6.8% higher than the average price.
In terms of expenses,Energy purchases and transportation costs are the primaryprincipal 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 ofOur thermal generation increases during relatively low hydrology, the amount of our thermal generation increases. This involves an increaserainfall periods, typically resulting in the amount ofhigher fuel required and the costs of its transportation to the thermal generation power plants.costs. Under dry conditions, the 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 requiredgenerate, requiring us to purchase electricity in the pool market at spot market prices.prices to satisfy our contractual obligations. The cost of these purchases at spot prices may, 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. WeTo determine the estimated 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 tocritical reservoirs. Besides limiting contracted sales, we may adopt other strategies, including installing temporary thermal capacity,power, 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, whichrather than seasonal weather variations, may adversely affect our generation capacity rather than seasonal weather variations,and materially affect our operating results and financial condition.
The generation business is affected by seasonal changes throughout the year. During normalaverage 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.August typically have the most precipitation.
When there is more precipitation, hydroelectric generating facilities can accumulate additional water to be used for generation. TheOur reservoirs’ increased level of our reservoirs allows us to generate more electricity with hydrohydroelectric power plants during months in whichwhen 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 the El Niño phenomenon reduces the amount ofreduce water that can be accumulated in reservoirs, thereby curtailing our hydroelectric generation capacity. In order toTo mitigate hydrological risk associated with our contractual obligations with our customers, hydroelectric generation may be substituted with thermal generationsources (natural gas, LNG,liquefied natural gas (“LNG”) coal, or diesel) and energy purchases on the spot market, both of whichmarket. These actions could result in higher costs, in order to meet our obligations under contracts with both regulated and unregulated customers.costs.
Operations
31
We own and operate a total of 48 generation power plants in Chile both directly and through our subsidiaries, Enel Generation, EGP Chile, GasAtacama and Pehuenche. Of these generation power plants, 18 are hydroelectric, with a total installed capacity of 3,5483,561 MW, representing 48 %49.5% of our total installed capacity in Chile. There are 11ten thermal generation power plants, (including aincluding one geothermal power plant)plant, that operate with gas, coal, or oil, with a total installed capacity of 2,7812,502 MW, representing 37 %34.7% of our total installed capacity in
Chile. There are 9 wind powerednine wind-powered generation power plants with an aggregate installed capacity of 642 MW, representing 9%8.9% of our total installed capacity in Chile. There are 10 solar poweredten solar-powered generation power plants with an aggregate installed capacity of 492496 MW, representing 7%6.9% 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 27.8 %28.5% of total gross electricity generation in Chile during 2018.in 2020.
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 |
|
EGP Chile(1) |
| 2,673 |
| — |
| — |
|
Pehuenche |
| 2,794 |
| 2,443 |
| 2,369 |
|
GasAtacama |
| 3,265 |
| 3,654 |
| 3,657 |
|
Total |
| 20,046 |
| 17,073 |
| 17,564 |
|
| | | | | | |
| | Year ended December 31, | ||||
|
| 2020 |
| 2019 |
| 2018 |
Enel Generation | | 13,613 | | 15,428 | | 11,314 |
EGP Chile(1) | | 3,418 | | 3,493 | | 2,673 |
Pehuenche | | 2,300 | | 2,120 | | 2,794 |
GasAtacama(2) | | — | | — | | 3,265 |
Total | | 19,331 | | 21,041 | | 20,046 |
(1) | Includes all of EGP Chile’s subsidiaries. |
(2) | GasAtacama was merged into Enel Generation in October 2019. |
(1) Includes all of EGP Chile’s subsidiaries
The following table sets forth the electricity generation by type:
ELECTRICITY GENERATION BY TYPE (GWh)
| | | | | | | | | | | | |
| | Year ended December 31, | ||||||||||
| | 2020 | | 2019 | | 2018 | ||||||
|
| Generation |
| % |
| Generation |
| % |
| Generation |
| % |
Hydroelectric generation | | 9,680 | | 50.1 | | 10,523 | | 50.0 | | 11,101 | | 55.4 |
Thermal generation | | 6,452 | | 33.4 | | 7,233 | | 34.4 | | 6,268 | | 31.3 |
Wind generation – NCRE(1) | | 1,768 | | 9.1 | | 1,845 | | 8.8 | | 1,352 | | 6.7 |
Mini-hydro generation – NCRE(2) | | 32 | | 0.2 | | 55 | | 0.3 | | 293 | | 1.5 |
Solar generation – NCRE | | 1,177 | | 6.1 | | 1,190 | | 5.7 | | 872 | | 4.4 |
Geothermal generation – NCRE | | 221 | | 1.1 | | 194 | | 0.9 | | 159 | | 0.8 |
Total generation | | 19,331 | | 100.0 | | 21,041 | | 100.0 | | 20,046 | | 100.0 |
(1) | Electricity generated by the Canela I and Canela II wind farms, and since 2018, all EGP Chile wind farms. |
(2) | Electricity generated in 2019 refers to the Ojos de Agua mini-hydroelectric plant. Before 2019, the information also includes generation by the Palmucho plant. |
Water Resource Use Agreements
|
| Year ended December 31, |
| ||||||||||
|
| 2018 |
| 2017 |
| 2016 |
| ||||||
|
| Generation |
| % |
| Generation |
| % |
| Generation |
| % |
|
Hydroelectric generation |
| 11,101 |
| 55.4 |
| 9,392 |
| 55.0 |
| 8,815 |
| 50.2 |
|
Thermal generation |
| 6,268 |
| 31.3 |
| 7,292 |
| 42.7 |
| 8,379 |
| 47.7 |
|
Wind generation — NCRE(1)(3) |
| 1,352 |
| 6.7 |
| 129 |
| 0.8 |
| 107 |
| 0.6 |
|
Mini-hydro generation — NCRE(2) |
| 293 |
| 1.5 |
| 260 |
| 1.5 |
| 263 |
| 1.5 |
|
Solar generation — NCRE(2) |
| 872 |
| 4.4 |
| — |
| — |
| — |
| — |
|
Geothermal generation — NCRE(2) |
| 159 |
| 0.8 |
| — |
| — |
| — |
| — |
|
Total generation |
| 20,046 |
| 100 |
| 17,073 |
| 100 |
| 17,564 |
| 100 |
|
(1) For 2017, electricity generated by the Canela I and Canela II wind farms.
(2) For 2017, electricity generated by the Palmucho and the Ojos de Agua mini-hydroelectric plants.
(3) Includes all EGP Chile wind farms.
Water Agreements
Water resource use agreements refer to thea user's right of a user to utilize water from a particular source, such as a river, stream, pond, or groundwater. In times of goodfavorable hydrological conditions, water agreements are generally not complicated or contentious. However, in times ofwith poor hydrological conditions, water agreements protect our right to use water
32
resources for hydroelectric generation. The following agreements allow us to use water more efficiently and avoid additional litigation with the local community and farmers.
Through our subsidiaries, weWe have three current agreements in forcesigned with the purpose of utilizing water for both irrigation and hydroelectric generation more efficiently. Two of them areChilean Hydraulic Works Directorate (“DOH”). The 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 intensefrom Maule Lagoon and Laja Lake, both located in southcentral Chile in areas where irrigation period (normallyis more demanding, generally from September to April) from Laja Lake and Maule Lagoon, both located in southern Chile.April. Enel Generation signed the first agreement withagreements regarding 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 theMaule Lagoon and Laja Lake on September 9, 1947, and October 24, 1958, respectively. On November 16, 2017, the OperationEnel Generation signed an agreement to operate and Recovery ofrecover water resources from Laja Lake, Agreement was signed, which complementscomplementing the previous agreement signed with DOH in 1958. This
In May 2020, Enel Generation and our subsidiary Pehuenche signed an agreement provides reasonablewith Colbún S.A., the electric utility company that owns Colbún Reservoir, and some irrigation security to irrigatorsassociations in the area, giving priorityMaule basin. The agreement aims to extractions for irrigation whenconsolidate the reservoir is at low levels, which are also used by generation. It also contemplatesgeneration rights extracted from Maule Lagoon under 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 irrigation and generation according to their needs. Another agreement was signed in 1947 with the Colbún Reservoir to allow these irrigation associations to use them during the 2020/2021 irrigation season.
In October 2018 between2020, our subsidiary Pehuenche, Colbún S.A., and the irrigators of the Maule Lagoon MonitoringVigilance Board signed an agreement to optimize the use of water during drought periods. These agreements allow us toperiods of drought. The agreement, which expires on August 31, 2025, facilitates water accumulation in the Colbún Reservoir in the spring for use in the water more efficiently and to avoid further litigation withsummer, the local community, especially with farmers.peak irrigation period.
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 gasLNG supply contract with suppliers that establishes maximum supply amountsquantities and prices, as well asprices. We also have 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 unitsOur gas-fired efficient power plants can operate using either natural gas or diesel and since December 2009,diesel. In particular, San Isidro San Isidro 2 and Quintero power plants operate using LNG.LNG from the Quintero LNG Terminal.
The LNG contract is the largest supply contract and is based on long-term agreements between us andwith Quintero LNG Terminal for regasification services and British GasShell for supply. Our LNG Salesale and Purchase Agreementpurchase agreement with Shell 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 3,523Electrogas S.A. is our current gas transportation provider. In 2020, Enel Generation used 742 million cubic meters of natural gas, of which 1,096 million cubic meters corresponded to Enel GenerationLNG from Quintero LNG Terminal for its generation and commercialization requirements.
Regarding the supply of natural gas, a milestone was achieved during the last quarter of 2018. In a newan environment of cooperation and promotion of energy integration by governments and private actors in Argentina and Chile, and after eleven years of interrupted supply gas supply, it was possible to reactivate the import of natural gas from Argentina. In this context,2020, Enel Generation 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 were 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 in 2010. With this availability, the electrical energy produced by Nueva Renca, which was approximately 0.5 TWh, accounted for the electrical energy balance of Enel Generation and helped to reduce our spot energy purchases.
From the point of view of gas commercialization, during 2018, Enel Generation had five LNG shipment sales transactions, including the sale to Enel Trade of two LNG shipments with delivery to the United Kingdom, continuing international trading transactions for shipments under the contract with BG Global Energy Ltda. in relevant international markets, outside of Latin America.
In addition, Enel Generation, 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 90.6imported 377 million cubic meters of which Enel Generation contributed 55% ofnatural gas with a very competitive price under supply agreements with YPF, Total Austral, and Pan American Energy, among other producers, driving a reduction in the total exported volume.system energy prices during the year.
In 2018,2020, the Terminal Use Agreement signed with GNL Mejillones allowed the unloading of an LNG shipmentshipments at thisthat terminal. This agreement allowedpermitted the renewal of gas purchasesales agreements with important mining and industrial customers, in the north of Chile, making of Enel Generation the mainprincipal industrial gas trader in the north of Chile, in addition to having volumes of this gas available to Enel Generation thermal units connected to the northern gas pipeline networkpipelines (Taltal and GasAtacama).
In relation toConcerning the commercialization of LNG by trucks, 2018 was marked bytruck, 70 million cubic meters were delivered in 2020, a 30%17% increase compared to 2017. During 2018,2019. In 2020, new agreements were reached that willto allow distributethe increased supply of natural gas to two new cities.for distribution for the coming years.
With respect to coal-based
The Bocamina power plant operations, during 2018, 1,037 kilotonsconsumed 840 thousand tons of coal were consumed by Tarapacá and Bocamina power plants. This consumption wasin 2020, equivalent of 2.3to 1.9 TWh of energy generated by Bocamina 2, 0.6II and 0.4 TWh generated by Bocamina I. We closed Bocamina I in December 2020 and 0.01 TWh generatedexpect to shut down Bocamina II by Tarapacá.May 2022 as part of our decarbonization strategy.
Generation from NCRE sources
33
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 tobefore 2007, to 20% for those signed starting in July 2013. Currently, ourOur Canela wind farms and Ojos de Agua mini-hydroelectric plant, 40% of the installed capacity of our Palmucho mini-hydroelectric plant, as well asand most of EGP Chile’s power plants (except the Pullinque yand Pilamiquén power plants), qualify as NCRE facilities.
Electricity sales and generation
The SEN’s electricity sales increased 4.3%0.2% during 20182020 compared to 2017, as set2019.
The following table sets forth in the following table:SEN’s electricity sales:
ELECTRICITY SALES PER SYSTEMIN SEN (GWh)
|
| Year ended December 31, |
| ||||
|
| 2018(1) |
| 2017 |
| 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 |
|
| | | | | | |
| | Year ended December 31, | ||||
|
| 2020 |
| 2019 |
| 2018 |
Total electricity sales (SEN) | | 71,808 | | 71,670 | | 71,179 |
(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 22,960 GWh in 2020, 23,513 GWh in 2019, and 24,369 GWh in 2018, 23,356 GWh in 2017 and 23,689 GWh in 2016, which represented a 34.2%32.0%, 34.2%32.8%, and 35.1%34.2% market share, respectively. The energy purchases to comply with our contractual obligations to third parties decreasedincreased by 31%46.8% in 2018 when2020, compared to 20172019, primarily due to lower hydro and coal electricity generation from closing the fact that (i) EGP Chile’s purchases are not included in the total since they are considered as intercompany sales, and (ii) to lower energy available in the contract with Nueva Renca, which is also included in this total.Tarapacá plant.
The following table sets forth our electricity generation and purchases:
ELECTRICITY GENERATION AND PURCHASES (GWh)
|
| Year ended December 31, |
| ||||||||||||||||||||||
|
| 2018 |
| 2017 |
| 2016 |
| ||||||||||||||||||
|
| (GWh) |
| % |
| (GWh) |
| % |
| (GWh) |
| % |
| ||||||||||||
| | | | | | | | | | | | | |||||||||||||
| | Year ended December 31, | |||||||||||||||||||||||
| | 2020 | | 2019 | | 2018 | |||||||||||||||||||
|
| (GWh) |
| % |
| (GWh) |
| % |
| (GWh) |
| % | |||||||||||||
Electricity generation |
| 20,046 |
| 82.3 |
| 17,073 |
| 73.1 |
| 17,564 |
| 74.1 |
| | 19,331 | | 84.2 | | 21,041 | | 89.5 | | 20,046 | | 82.3 |
Electricity purchases |
| 4,323 |
| 17.7 |
| 6,283 |
| 26.9 |
| 6,125 |
| 25.9 |
| | 3,629 | | 15.8 | | 2,472 | | 10.5 | | 4,323 | | 17.7 |
Total |
| 24,369 |
| 100 |
| 23,356 |
| 100 |
| 23,689 |
| 100 |
| | 22,960 | | 100.0 | | 23,513 | | 100.0 | | 24,369 | | 100.0 |
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. CommercialContracts usually govern commercial relationships with our customers are usually governed by contracts.customers. 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 betweenupon by both parties, reflecting competitive market conditions.
In 2018, 20172020, 2019, and 2016,2018, we had 294, 152384, 315, and 46294 customers, respectively. This significant increase in 20182020 is mainly due to the increase in the number of unregulated customers. Regulated customers of a certain size may use their optionelect 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 2018,2020 our customers included 2024 regulated customers and 274360 unregulated customers.
The most significant supply contracts with regulated customers are with our subsidiary Enel Distribution and with Compañía General de Electricidad S.A. (“CGE”), an unaffiliated entity. These are the two largest electricity distribution companies in Chile in terms of sales.
Our generation contracts with unregulated customers are generally on a long-term basis and typically range from five to fifteen years. Such contractsThese agreements 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
34
regarding power sources and equipment, which may be provided at special rates as well asand 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,agreement, we are allowed tocan 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.
For the year ended December 31, 2018,2020, 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): CMPC, Compañia Minera Doña Inés de Collahuasi SCM, Enel Distribution,, Empresa CMPC S.A., Minera Valle Central S.A.S.A, and SCM Minera Lumina Copper Chile.
Electricity generation companies compete largely based mainly on price, technical experience, and reliability. In addition, because 48% of our installed capacity connected to the SEN is hydroelectric, weWe have lower marginal production costs than companies whose installed capacity is primarily thermal.thermal because 49.9% of our installed capacity connected to SEN is hydroelectric. 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 Distribution Business Segment
Through our subsidiary Enel Distribución,Distribution, in which we have a 99.1% economic interest, we are one of the largest electricity distribution companies in Chile in terms ofbased on the number of regulated customers, distribution assets, and energy sales.
We operate in a concession area of 2,105 square kilometers, under an indefinite concession granted by the Chilean government. We transmit and distribute electricity in 33 municipalities in the Santiago metropolitan region. Our service area is primarily defined as a densely populated area under the Chilean tariff regulations, which govern electricity distribution companies and includes all residential, commercial, industrial, governmental electricity customers, and toll customers. The Santiago metropolitan region, which includes theChile’s capital, of Chile, is the country’s most densely populated area and has the highesta high concentration of industries, industrial parks, and office facilities in the country.facilities. As of December 31, 2018,2020, we distributed electricity to approximately 1.9over 2 million customers. Energy losses were 5.2% in 2020, 5.0% in 2018, 5.1%2019, and 5.0% in 2017 and 5.3% in 2016.2018.
For the year ended December 31, 2018,2020, residential, commercial, industrial, and other customers, who are primarily municipalities, represented 28%30.4%, 30%27.9%, 13%10.2%, and 28%31.4%, respectively, of our total energy sales of 16.78216,481 GWh, which is an increasea decrease of 2.1%3.8% in comparison withcompared to the same period in 2017.2019.
The following table sets forth our principal operating data for each of the periods indicated:
|
| Year ended December 31, |
| ||||
|
| 2018 |
| 2017 |
| 2016 |
|
Electricity sales (GWh) |
| 16,782 |
| 16,438 |
| 15,924 |
|
Residential |
| 4,702 |
| 4,676 |
| 4,442 |
|
Commercial |
| 5,107 |
| 5,271 |
| 5,075 |
|
Industrial |
| 2,202 |
| 2,451 |
| 2,536 |
|
Other customers(1) |
| 4,771 |
| 4,039 |
| 3,871 |
|
Number of customers (thousands) |
| 1,925 |
| 1,882 |
| 1,826 |
|
Residential |
| 1,725 |
| 1,686 |
| 1,634 |
|
Commercial |
| 149 |
| 146 |
| 142 | �� |
Industrial |
| 13 |
| 13 |
| 13 |
|
Other customers |
| 39 |
| 38 |
| 37 |
|
Energy purchased (GWh)(2) |
| 17,718 |
| 17,373 |
| 16,803 |
|
Total energy losses (%)(3) |
| 5.0 |
| 5.1 |
| 5.3 |
|
| | | | | | |
| | Year ended December 31, | ||||
|
| 2020 |
| 2019 |
| 2018 |
Electricity sales (GWh) | | 16,481 | | 17,135 | | 16,782 |
Residential | | 5,006 | | 4,897 | | 4,702 |
Commercial | | 4,606 | | 4,924 | | 5,107 |
Industrial | | 1,687 | | 1,954 | | 2,202 |
Other customers(1) | | 5,183 | | 5,360 | | 4,771 |
Number of customers (thousands) | | 2,008 | | 1,972 | | 1,925 |
Residential | | 1,801 | | 1,768 | | 1,725 |
Commercial | | 154 | | 152 | | 149 |
Industrial | | 12 | | 13 | | 13 |
Other customers(1) | | 41 | | 40 | | 39 |
Energy purchased (GWh)(2) | | 17,356 | | 18,115 | | 17,718 |
Total energy losses (%)(3) | | 5.2 | | 5.0 | | 5.0 |
SAIDI (minutes) | | 171 | | 184 | | 195 |
SAIFI (times) | | 1.5 | | 1.6 | | 1.5 |
(1) The data for other customers includes tolls.35
(2) During 2018, 2017, and 2016, Enel Distribution acquired from Enel Generation 37%, 39% and 38%, respectively,Table of its electricity purchases.Contents
(1) | The data for other customers includes tolls. |
(2) | In 2020, 2019, and 2018, Enel Distribution acquired 31%, 33%, and 37%, respectively, of its electricity purchases from Enel Generation. |
(3) | Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise from illegally tapped lines and technical losses. |
(3) Energy losses are calculated as the percent difference between energy purchased and energy sold excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical losses.
Enel Distribution’s tariff review process, which set the tariffs for the 2016-2020 period, was finalized in August 2017. The new tariffs were applied retroactively as of November 2016, and the review did not have a significant effect on Enel Distribution’s tariffs.
ForThe technical bases for the year ended December 31, 2018,tariff-setting process for 2020-2024 were published at the end of the first half of 2020. This is the first tariff-setting process where the CNE has carried out a single study. In the tariff-setting process for 2016-2020, the tariff was calculated using a weighted average between the Reference Company study (one-third) and the CNE study (two-thirds). During the second half of 2020, the consulting company that carried out the study was assigned, and, as of the date of this Report, the study has not yet produced conclusive results.
The seasonally adjusted collection rate corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. In 2020 this ratio was 98.6%97.3%, compared to 99.6%99.4% during the same period in 2017.2019.
For the supply to regulated distribution customers, Enel DistribuciónDistribution has entered into contracts with the following generation companies: Enel Generation.,Generation, AES Gener S.A., Colbún S.A., and othersother companies.
In 2017, the distribution companies of the former SIC jointly submitted a 2,200 GWh/year bid for the period of 2024 through 2043. In November 2017, the following generation companies were awarded the most relevant amounts of the bid companies: Enel Generation, Energía Renovable Verano Tres SpA, Cox Energía SpA, Atacama Energy Holdings S.A. and Atacama Solar S.A.
For the supply to unregulated distribution customers, Enel Distribution has contracts with the following generation companies: Parque Eólico Los Cururos Ltda., Latin América Power, Orazul Energy Duqueco SpA., Enel Generation.Empresa Eléctrica Guacolda S.A., Empresa Electrica PuntillaHidroeléctrica La Higuera S.A., Hidroeléctrica La Confluencia S.A., Pacific Hydro Chile S.A., and KDM.Enel Generation.
Seasonality
The distribution business is directly influenced by seasonalSeasonal changes in energy demand.demand directly influence the distribution business. Although the price at which a distribution company purchases electricity can change seasonally and has an impact on the price at which it is sold to end users,end-users, it does not have an impacteffect on our profitability since the cost of electricity purchased is passed on to end usersend-users through tariffs that are set for multi-year periods. In general, moderate temperatures reduceHowever, in the need for electric heating and air conditioning. During 2018,case of regulated customers, an increase in tariffs due to rate adjustments may not happen immediately, which could affect our profitability in the effects of low temperatures (especially during winter) positively impacted our residential customers’ per capita consumption, which represented 28% of our electricity distribution during 2018.short term.
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 variousdifferent participants in the Chilean electricity market:
36
The Chilean electricity sector is physically divided into three main networks, thenetworks: 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 northnorthern Chile to Chiloé in the south. Thesouthern Chile. 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.
operations.
The industry’s three business segments: segments—generation, transmission, and distribution, 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.
i) | Generators: |
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.authorities. Generators may sell their energy to unregulated customers and to other generation companies through contracts at freely negotiated prices, or theyprices. They may also sell to distribution companies to supply regulated customers through contracts governed by bids.bids defined by the authorities.
The operation ofCEN coordinates electricity generation companies is coordinated by the CEN,companies’ operations, 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 system’s hourly marginal cost of the system.cost.
ii) | Transmitters: |
ii)Transmitters:
Transmission companies own lines and substations with a voltage abovehigher than 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 nondiscriminatorynon-discriminatory conditions.
iii)Distributors:
iii) | Distributors: |
Distribution companies supply electricity to end customers using electricity infrastructure with lesslower than 23 kV. The distribution segment is a natural monopoly subject to special industry regulations as well, including antitrust
37
legislation. The electricity network is open access, and distribution tariffs of distribution are regulated. Distribution companies have the obligation tomust 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, customersCustomers are classified as “regulated” or “unregulated” according to their demand as “regulated” or “unregulated.” Certaindemand. Some customers have the choicemay choose to be either regulated or unregulated, and therefore subject to the respective price regime. Demand requirements to qualify as a regulated or unregulated customer are described below under “—3. Generation Segment — Dispatch, Customers and Pricing”.Pricing.”
2. Electricity Law and Authorities
The goal of the Chilean Electricity Law isaims to provide incentives to maximize efficiency and to provide a simplified regulatory scheme and tariff-setting process that limitslimiting the government’s discretionary role of the government.role. This goal is achieved by establishing objective criteria for setting prices that provideoffer a competitive rate of return on investment to stimulate private investment while ensuring theelectricity availability of electricity in the system to all who request it.
Since its inception, private sector companies have developed the Chilean electricity industry has been developed primarily by private sector companies. However,industry; however, nationalization by the government was carried outconducted 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 private sector’s renewed participation of the private sector.participation.
The industry is currently governed by the electricity law Ley General de Servicios Eléctricos No. 20,018 and its modifications currently govern the industry, 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 Regulationsregulations included in Decreto Supremo D.S. No. 327/1998.
The Ministry of Energy is the mainleading authority in the energy industry since February 1, 2010. The Ministry of Energyindustry. It elaborates and coordinates plans, policies, and standards for the sector’s 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,”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 electricitythe generation, transmission, and distribution of electricity, as well as liquid fuels and gas.
The Energy Sustainability Agency was created in 2018 to promote energy efficiency and replaced the Energy Efficiency Agency that is in charge of promoting energy efficiency.Agency.
Additionally, the law provides for a “Panel of Experts,” whose mainprimary responsibility is to actsact as a court, issuing enforceable resolutions in disputes related to subjects referred to by DFL 4 and other electricity relatedelectricity-related laws. This panel is comprised ofcomprises 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:
● | maintain service security; |
i) maintain service security;
ii)
● | guarantee the efficient operation of facilities connected to the system; and |
● | guarantee open access to all transmission networks. |
38
iii) guarantee open access to all transmission networks.
The CEN’SCEN’s main activities include:
● | coordinating of electricity market operations; |
● | authorization of connections; |
● | managing ancillary services, implementing information systems for the public; and |
● | monitoring competition and payments, among others. |
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 outmade in the spot market. However, the CEN does not, however, calculate the pricesrates of generation capacity. Such prices are calculated by the National Energy Commission or CNE.The CNE calculates such prices.
LimitsLimits on Integration and Concentration
The antitrust legislation established in DFL 211 (modified in 2016 by Law No. 20,945 in 2016)20,945) 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 complyingand Law No. 21,194. Companies must also comply with the conditions establishedset in Resolution NoNo. 667/2002, listeddiscussed below.
The transmission sector is subject to the greatestmost significant restrictions, mainly because of its open access requirements. DFL 4 sets limits to the shareholdings of generation and distribution companies inestablishes that companies that participate in the national transmission segment of the transmission system.
The owners ofown the National Transmission System (“STN” in its Spanish acronym) may not engage in activities within the generation or distribution segment.
Owners of the STN 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 certainspecific measures to increase transparency associated with us and our subsidiaries and us through Resolution 667No. 667/2002 issued by the TDLC.
Resolution 667No. 667/2002 states that:
● | electricity generation and distribution activities cannot be merged (Enel Chile must continue to keep both business segments separate and manage them as independent business units); |
· electricity generation and distribution activities cannot be merged. For instance,
● | Enel Chile,
|
● | members of the board of directors must be elected from different and independent groups; and |
● | the external auditors of the companies must be different for local statutory purposes. |
Pursuant to Law No. 21,194 (known as “Ley Corta”) adopted in 2020, the Ministry of Energy requires Chilean distribution companies to operate as a separate public distribution business line with its own accounting and management without including other businesses, such as an electricity transmission business. As of January 2021, and as
39
required by this law, our transmission and our distribution business lines are now owned and operated by separate companies, Enel Transmission 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;respectively.
· 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, theThe Water Utility Services Law also sets restrictions on the overlapping of different utility concessions in the same area, setting restrictionsarea. It establishes limits 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 ofFor 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-drivenmarket 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 CEN decides the operation of their power plants is determined by the CEN.plants’ operation. The surplus or deficit between thea 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
Non-Conventional Renewable Energy (“NCRE”) has been promoted in 2008 to promote the development of NCRE generation. In Chile since 2008. NCRE refers to powerelectricity from wind, solar, geothermal, biomass, ocean (movement of tides, waves, and currents, as well asand the ocean’s thermal gradient), and mini-hydromini-hydropower plants with a capacity 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(2013) established a mandatory 20% share of NCRE source as a percentage of total contracted energy sales by 2025 but allowinggrandfathered contracts signed between 2007 and 2013, to maintain thewhich have a 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 production cost of production of the last kWh dispatched.
The CEN operates the electricity system with an approach that minimizes costs while monitoring the quality of the service provided by the generation and transmission companies.companies’ service. To minimizereduce operating costs, itCEN 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 beis 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, using both their injections (sales) and their withdrawals (purchases) to balance their contracted customer sales towith their production determined by the CEN.
The customers of generation companies are classified by the electricity capacity demand required, explained as follows:
i)
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. This customer category also includes those unregulated customers who demand between 500 and 5,000 kW of capacity and have the option to choose between the unregulated and regulated regimes. |
ii) | Distribution companies: Distributors purchase energy from generation companies through an open bid process regulated by the CNE to satisfy regulated customers’ energy dispatch. Distributors may freely negotiate bilateral contracts with unregulated customers. |
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 |
40
energy traded on the spot market is the system’s hourly marginal cost and the price of capacity sold on the spot market at a specific node. |
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.
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 dependdepends primarily on the facility’s availability, of such facility, the type of power plant technology, and the resources used to generate.generate electricity. It isconsiders the maximum capacity a generator may supply to the system at certain peak hours, considering statistical information, accounting for maintenance time and extremely dryarid conditions for hydroelectric power plants, but differs from firm capacity becauseplants. However, 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 consideringthat considers the weighted average pricesweighted-average rates of their current supply contracts for regulated customerscustomers. 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;indices; (2) upon the entry of a new supply contract with any distribution company; and (3) upon indexation of a supply contract inby more than 10%.
Rationing
For ancillary services, the regulator has defined four primary services that the system may require: (i) frequency control services; (ii) voltage control services; (iii) services to face contingency situations; and (iv) recovery services.
The system operator can obtain these services through (i) direct instruction to the power units that are the most efficient at delivering the service; (ii) auctions awarded to offers that most effectively reduce system costs; and (iii) bidding processes to develop new infrastructure aimed at providing the service. In 2021, auctions will only apply to secondary and tertiary frequency control services because the system operator has determined competitive conditions in that market.
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 asand compensate electricity customers affected by shortages of electricity. The finesPenalties 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 companythey 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 project’s start-up date of the project associated with the water right.rights. 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 forthoutlined in article 19, paragraph 24: “The rights of individuals over water, recognized or constituted in accordance withunder the law, grant their holders ownership over such rights.” Notwithstanding the foregoing,this definition, 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 makingto make water use for human consumption, household subsistence, and sanitation a high priority.
41
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 new water rights would be limited to a maximum period of 30 years, extendable over future terms unless the Water Authority proves the resources’ non-use. The extension would be effective only for water rights used. |
· 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 granted by law if the holder does not exercise the right of use within eight years. |
· 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 previously granted: If the holder does not effectively use the rights within 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. |
· 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.
In January 2019, the PresidentChile’s president modified this amendment to state that the water rights have an unlimited duration. As of the date of this Report, the Chilean Congress is still discussing the amendment.
4. Transmission Segment
The transmission segment suppliesTransmission systems are comprised of the electricity over lines orand substations with a voltage or tension higher than 23 kV that are connected 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 and guaranteed under nondiscriminatorynon-discriminatory 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,national, development poles, zonal, dedicated, and International.international.
National and Zonal Transmission Systemszonal transmission systems planning is a centralized and regulated process carried outconducted by the CEN that annually issues an expansion plan to be approved by the CNE.
The
Both systems’ expansion of both systems is granted through an open tender process that distinguishes new installations from the enlargement of existing installations.facilities. The tenders carried outconducted for new installations grantgive the winner ownership of the installation to be built. The expansionextension of existing installations,facilities, on the other hand, belongs to the owner of the original installation,facility, who is obliged to tender the construction of the required expansion.extension.
The remuneration of existing national and zonal transmission installations is determined by a tariff settingtariff-setting process performedconducted every four years. This process determines the Annual Transmission Valueannual transmission value that considers efficient operation and maintenance costs and an annuala yearly valuation of investments that is based on a discount rate determined by the authorityauthorities every four years (minimum 7% after tax)after-tax) and the installations’ useful life of the installations.life.
The remuneration of expansionsextensions of existing facilities is the value resulting from the respective bid of such expansionextensions for the first 20 years of operations. FromBeginning with year 21, on, such expansionextension is considered an existing installation and remuneratedcompensated accordingly.
RegulationThe regulation currently in force states that transmission remuneration is the sum of tariff revenue and the usage charge revenue received for use of the transmission system, defined as $/kWh by the CNE. Revenues are calculated on a semi-annual basis.
Finally, inIn the case of a failure in electricity transmission, Law No. 20,396 defines the penalty conditions for the responsible company (transmission, generation, or other).
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Transmission Tariffs
Law No. 20,936 introduced changes to the transmission tariff settingtariff-setting process. In transitioningthe transition to the implementation of the new law, the currentexisting zonal transmission tariff settingtariff-setting process has been continued, as stated by transitory Article No. 20 of Law No. 20,936. The tariff settingtariff-setting process for the 2018-2019 period concluded in October 2018 and has been effective retrospectivelyapplied retroactively since January 1, 2018. The
In 2020, national and zonal transmission pricing studies were carried out for the 2020-2023 tariff settingperiod. As of the date of this Report, observations on both studies were submitted, and the next step in the process is now in progress.the publication of the technical report by the CNE.
5. Distribution Segment
The distribution segment is comprised ofcomprises electricity infrastructure with a voltage lower than 23 kV to supply electricity to end customers. Electricity distribution is considered a natural monopoly andmonopoly. Therefore, 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 whosewith a connected capacity is below or equalof up to 5,000 kW and unregulatedkW. Unregulated customers are those whosewith a connected capacity is at leastof over 5,000 kW. Customers with a 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 oneCustomers must remain in the selected category must remainfor at least four years in the option chosen.years.
Customers subject to the unregulated price regime may negotiate their electricity supply with any generator or distributor, althoughsupplier; however, 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 permitshas permitted customers with a connected capacity of up to 300 kW to sell their surpluses.
Distribution concessions are given by theThe Chilean Ministry of Energy grants distribution concessions for an undefined period of timeperiods and give the right to use public areas for building distribution lines. Distribution companies have thean obligation to supply electricity to regulatedall customers thatwho request service within their concession area, except for customers that have chosen the unregulated regime.area. A concession may be declared expired if the quality of service does not meet certainspecific minimum standards.
Regarding the supply of electricity to regulated customers, DFL 4 establishes that distribution companies must permanently have an amount of electricity supplypermanently 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 outconducted 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 termshort-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 outconducted in 2017. A total of 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 completelywholly sourced from NCRE. For further detail onIn November 2020, the outcomeCNE announced a new bidding process for 2,310 GWh/year to be tendered from 2026 to 2040. The deadline for the submission of tenders, pleasebids is May 19, 2021. Please see “Item 4. Information on the Company — B. Business overview”.Overview” for further detail on the outcome of tenders.
Distribution Tariffs
The Chilean distribution tariff model has gone through nine tariff setting processtariff-setting processes since its privatization in the 1980s.
43
Law No. 21,194 established new limits on returns on investments for distribution companies. Tariffs charged by distribution companies to regulated 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 Addedvalue-added from Distributiondistribution of electricity (“VAD”), which allowsallowing distribution companies to recover their investment and operating costs, including a legally mandated return on investment, which is set by law.investment. The transmission charge reflects the costprice paid for electricity transmission and transformation. The law also requires that distribution companies may not operate in other sectors or industries as of 2021.
The VAD is based on a so-called “efficient model company” within a Typical Distribution Areatypical distribution area (“TDA”). It considers the cost of building and operating the company at the minimum cost,price, fulfilling the company’s quality and safety standards of a company within that TDA. Therefore, the CNE classifies all distribution companies according to their TDA thenand subsequently selects one distribution company from each TDA and estimatesto estimate 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,expenses, 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)replacement cost of the installations, useful life, and a 10%rate of return on assets associated with electricity investments.that the CNE calculates every four years.
The CNE determines 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, withTDA. With the resulting VAD, preliminary tariffs are tested to ensure that they provide an industry aggregate rate of return between 6% and 14%8%. However, Law No. 21,194 establishes that the after-tax rate of return for each distributor must be between three percentage points below and two percentage points above the rate of return calculated by the CNE.
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 greaterhigher 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 ofapplying this mechanism will beare 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 lowerless 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. Thissix months. The state confers this subsidy, is conferred by the state,and its application is a facultypower of the government, and the last one was granted in 2009.
The tariff settingtariff-setting process for 2016-2020 concluded in August 2017 and had been effective, retroactively, since November 4, 2016. On December 18, 2017, the CNE published a resolution which setsthat set the Technical Standard of Quality of Service for Distribution Systems. The Distribution System Technical Service Quality Standards establishedSystems, establishing higher technical and commercial standards. Included in these new standards includingare 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;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 tariffprocess, which is non-retroactive and will be effectivein effect until the nexttariff-setting process for the 2020-2024 period has been completed. This process began in January 2020 and is ongoing. However, due to the social unrest that began in October 2019, distribution tariffs for 2020 remained fixed under Law No. 21,185, which creates a temporary electricity price stabilization mechanism for customers subject to tariff setting process.regulation.
In August 2019, the CNE published technical annex Measurement, Monitoring, and Control Systems to the Technical Standard for Service Quality for Distribution Systems. The annex establishes minimum technical requirements to ensure a level of quality, security, scalability, and interoperability that distribution companies must implement in accordance with the Technical Standard of Service Quality for Distribution Systems, which was last updated in December 2019.
44
The technical bases for the tariff-setting process for 2020-2024 were published at the end of the first half of 2020. This is the first tariff-setting process where the CNE has carried out a single study. In the tariff-setting process for 2016-2020, the tariff was calculated using a weighted average between the Reference Company study (one-third) and the CNE study (two-thirds). During the second half of 2020, the consulting company that carried out the study was assigned, and, as of the date of this Report, the study has not yet produced conclusive results.
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,Also, distribution companies are subject to theSEF provisions, of the SEF, in particular to in itsincluding 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 CNE sets the tariffs of these services are set every four years, by the CNE along with the VAD calculation.
The tariff settingtariff-setting process for the distribution relateddistribution-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.tariff-setting process for the 2020-2024 period has been completed. This process began in January 2020 and is ongoing. However, due to the social unrest that began in October 2019, distribution-related tariffs for 2020 will remain unchanged for the time being.
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.heritage conservation. 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 theChile’s environmental and institutional framework of Chile.framework. 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)(“SEA” in its Spanish acronym).
The Ministry of the Environment is in charge of the management, protectionmanaging, protecting, and application of policies inapplying environmental matters, whosepolicies. Its mission is to lead sustainable development through the generation ofby implementing efficient public policiesprocedures and regulations byand promoting good practices that improve citizen environmental education. ThisThe Ministry works in the recovery ofto restore 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 theprojects’ environmental impact assessment offramework. At the projects, whilesame time, the Superintendence of Environment monitors compliance with the environmental qualification, standards, and plans.
In June 2011, the Ministry45
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 chargesfees for the emission of MP, NOx, SO2PM, NOx, SO2, and CO2CO2 into the atmosphere. For CO2CO2 emissions, the chargefee is US$5 per emitted ton (not applicable to renewable biomass generation). MP, NOxPM, NOx, and SO2SO2 emissions will beare charged the equivalent of US$ 0.10 per emitted ton, multiplied by the result of a formula based on the population of the municipality where the generation power plant is located, andwhich is an additional fee of US$ 0.90 per ton of MP emitted,PM emissions, US$ 0.01 per ton of SO2 emittedemissions, and US$ 0.025 per ton of NOx emitted.emissions. 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 thermal power plants of Enel Generation and its subsidiary GasAtacama have established methodologies to measure emissions and pay related taxes in line with the requirements of the EnvironmentalChilean Superintendence of Chile.Environment requirements.
Regarding biodiversity, on January 5, 2018, the Chilean Sustainable Development Board approved the 2017-2030 National Biodiversity Strategy. This strategy replacesreplaced the existing national strategypolicy adopted in 2003. The new strategyplan identifies five objectives related to the sustainable use of biodiversity and the development of the institutions and regulationregulations 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.”
C. | Organizational Structure. |
C.Organizational Structure.
Principal Subsidiaries and Affiliates
We are part of an electricity group controlled by Enel S.p.A, an Italian company and our ultimate controlling shareholder whichthat beneficially owned 61.9%64.9% of our shares(excluding treasury stock) as of December 31, 2018.2020. Enel is an energyItalian utility company with multinational operations inwhose principal business is the powerproduction, distribution, and gas markets, with a focussale of electricity, focusing primarily on Europe and Latin America. Enel operates in 3532 countries across five continents and produces energy through a managed installed capacity over 89of 87 GW, which includes 43including more than 47 GW of renewable sources, and distributesmaking Enel one of the world’s largest private renewables operators. Enel is among the largest network operators, distributing electricity and gas through a network covering 2.2to more than 74 million kilometers.end users. With over 73almost 70 million userscustomers worldwide, Enel has one of the largestmost extensive customer basebases among European competitors and figures among Europe’s leading power companies in terms of installed capacity and reported EBITDA. Enelcompetitors. Enel’s shares tradeare listed on the Milan Stock Exchange.Mercato Telematico Azionario organized and managed by Borsa Italiana S.p.A.
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Enel Chile’s Simplified Organizational Chart(1)Structure(1)
As of December 31, 2018the date of this Report(2)
(1)
(1) | Only principal operating consolidated entities are presented here. |
(2) | As of January 1, 2021, Enel Transmission was spun off from Enel Distribution. |
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We consolidated entities are presented here. The percentage listed in the box for each of Enel Chile’s consolidated subsidiaries represents its economic interest in such consolidated subsidiary.
(2) Excluding treasury stock.
The companies listed in the following table were consolidated by us as of December 31, 2018.2020. In the case of subsidiaries, 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 Subsidiaries |
| % Ownership of Each |
| Consolidated |
| Revenues and Other |
|
|
| (in %) |
| (in billions of Ch$) |
|
|
|
Electricity Generation |
|
|
|
|
|
|
|
Enel Generation |
| 93.6 | % | 3,669 |
| 1,521 |
|
EGP Chile(1) |
| 100.0 | % | 1,973 |
| 183 |
|
Electricity Distribution |
|
|
|
|
|
|
|
Enel Distribution |
| 99.1 | % | 1,279 |
| 1,263 |
|
| | | | | | |
Principal Subsidiaries |
| % Ownership of Each |
| Consolidated |
| Revenues and Other Operating Income of Each |
| | (in %) | | (in billions of Ch$) | | |
Electricity Generation | | | | | | |
Enel Generation | | 93.5% | | 3,091 | | 1,490 |
EGP Chile(1) | | 99.9% | | 2,237 | | 297 |
Electricity Distribution | | | | | | |
Enel Distribution | | 99.1% | | 1,651 | | 1,382 |
(1) | EGP Chile is the result of EGPL merging into Enel Chile during the 2018 Reorganization |
(1) EGP Chile is the result of EGPL merging into Enel Chile during the 2018 Reorganization
Generation Business
Enel Generation
Enel Generation is a Chilean electricityan electric utility company engaged, directly and through our subsidiaries and affiliates, in the generation company, which has a total installed capacity of 6,351 MW asbusinesses in Chile. As of December 31, 2018,2020, it had 6,001 MW of gross installed capacity, with 28 generation facilities.facilities and a total of 109 generation units. Of theits total gross installed capacity, 55% is from57.8% consists of hydroelectric power plants and includes, among others, Ralco with 689690 MW, Pehuenche with 568570 MW, El Toro with 449450 MW, Rapel with 376377 MW, and Antuco with 319321 MW. Nearly 77%Approximately 86% of itsour gross thermoelectric facilities areinstalled capacity is gas/fuel oil power plants (2,104 MW), and the remaining areis coal-fired steam power plants.plants (350 MW). Our economic interest in Enel GeneraciónGeneration was 93.6%93.5% as of December 31, 2018.
EGP Chile
On April 2, 2018,2020, and as a result of the 2018 Reorganization, EGPLdate of this Report.
In June 2019, Enel Generation and its subsidiary GasAtacama Chile (now merged with and into Enel Generation) signed an agreement with the Ministry of Energy that complements our sustainability strategy and strategic plan and defines how to proceed with the progressive closures of our coal-fired power plants Tarapacá, Bocamina I and Bocamina II, which have a gross installed capacity of 158 MW, 128MW, and 350 MW, respectively.
The agreement is subject to the full implementation of the Power Transfer Regulation, which defines the Strategic Reserve State and establishes, among others, the essential conditions that ensure non-discriminatory treatment between generation companies. Under the agreement, we were formally and irrevocably obligated to close Bocamina I and Tarapacá. The deadline for closing Tarapacá was May 31, 2020. However, upon receiving authorization from the CNE to accelerate Tarapacá’s closure, we closed the plant ahead of schedule on December 31, 2019. The deadlines for closing Bocamina I and Bocamina II were December 31, 2023, and December 31, 2040, respectively. Nevertheless, we also shut down Bocamina I on December 31, 2020, and expect to voluntarily shut down Bocamina II by May 2022, well ahead of the deadline of 2040. By the end of 2022, Enel Chile, and acting through Enel Generation, will become the first electricity company in Chile to complete its decarbonization process.
EGP Chile became a direct and wholly-owned subsidiary of Enel Chile.
EGP Chile is an electricityelectric utility company engaged in therenewable generation business in Chile and a leader in Chile’s renewable energy market with a mixed portfolio of wind (564 MW), solar (492(496 MW), small hydroelectric (92 MW), and geothermal (41(48 MW) power. We hold a 99.99%99.9% economic interest in EGP Chile. For additional information on the corporate reorganization,Please see “Item 4. Information of the Company — A. History and Development of the Company — The 2018 Reorganization”. for additional information on the corporate reorganization.
GasAtacamaGeotérmica del Norte
GasAtacama48
Geotérmica del Norte (GDN) is a generation company located northernjoint venture between our subsidiary EGP Chile which owns and operate a four-unit combined-cycle powerEmpresa Nacional del Petróleo (ENAP), the state-owned Chilean oil company. GDN was established in 2005 to develop, explore, and exploit geothermal resources in Chile. GDN developed the 48 MW Cerro Pabellón geothermal plant, with a totalthe first of its kind in Chile, and is currently developing the geothermal extension project that will add 28 MW of 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 of it, 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 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 assetsCerro Pabellón power plant. It also has production rights 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.
As of December 31, 2018, we beneficially owned 93.7% of GasAtacama, with 91.1% from our indirect equity interest through Enel Generation, which owns 97.4% of GasAtacama, and the remaining 2.6% from our direct ownership.
Pehuenche
Pehuenche, a generation company connected to the SEN, owns three hydroelectric facilities locatedgeothermal concessions 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. Enel Generación holds 92.7% of theChile. Our economic interest in Pehuenche. As of December 31, 2018, we beneficially owned an 86.7% economic interest in Pehuenche, through Enel Generación, and consolidate Pehuenche in our consolidated financial statements.GDN is 84.6%.
Distribution Business
Enel Distribution
Enel Distribution is one of the largest electricity distribution businesses in Chile, as measured by the number of regulated customers, distribution assets, and energy sales. Enel Distribution operates in a concession area of 2,105 square kilometers in the Santiago Metropolitan Region, serving approximately 1.9over two million customers. As of December 31, 2018, ourOur economic interest in Enel Distribution wasis 99.1%.
D.Property, PlantTransmission Business
Enel Transmission
Pursuant to Law No. 21,194 (known as “Ley Corta”) adopted in 2020, the Ministry of Energy requires Chilean distribution companies to operate as a separate public distribution business line with its own accounting and Equipment.management without including other businesses, such as an electricity transmission business.
On December 3, 2020, Enel Distribution held an extraordinary shareholders’ meeting to approve the separation of its distribution and transmission business lines into two separate companies. Enel Distribution carried out a corporate reorganization on January 1, 2021, pursuant to which each shareholder of Enel Distribution received one share of the new company, Enel Transmission, for each share of Enel Distribution held, maintaining the same ownership position in each company after the spin-off. Our economic interest in Enel Transmission is 99.1%.
Assets and liabilities relating to the energy transmission segment were allocated to Enel Transmission. Transmission assets are related to the lines and substations that are part of the electric system but are not intended for distribution service under the terms of the electricity law and regulations.
D. | Property, Plant, and Equipment. |
Our property, plant, and equipment areis concentrated onin electricity generation and distribution assets in Chile.
We conduct our generation business through Enel Generation, EGP Chile, Enel Generation and their subsidiaries, which together own 48 generation power plants, all located in Chile, of which 18 are hydroelectric (3,5483,561MW installed capacity), ten are thermal, including geothermal (2,502 MW installed capacity), 11ten are thermal (2,781solar (496 MW installed capacity), 10and nine are solar (492 MW installed capacity) and 9 are wind poweredwind-powered (642 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.
The following table identifies the power plants that we own, all located in Chile, at the end of each year, organized by company and their basic characteristics:technology:
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Property, Plant, and Equipment of Generation Companies
| | | | | | | | | | |
| | | | | | Installed Capacity(1) | ||||
Company |
| Power Plant Name |
| Power Plant Type(2) |
| 2020 |
| 2019 |
| 2018 |
| | | | | | (in MW) | ||||
Enel Generation | | Ralco | | Reservoir | | 690 | | 689 | | 689 |
| | Pangue(3) | | Reservoir | | 467 | | 466 | | 466 |
| | El Toro | | Reservoir | | 450 | | 449 | | 449 |
| | Rapel | | Reservoir | | 377 | | 376 | | 376 |
| | Antuco | | Run-of-the-river | | 321 | | 319 | | 319 |
| | Abanico | | Run-of-the-river | | 136 | | 136 | | 136 |
| | Cipreses | | Reservoir | | 106 | | 106 | | 106 |
| | Sauzal | | Run-of-the-river | | 80 | | 77 | | 77 |
| | Isla | | Run-of-the-river | | 70 | | 70 | | 70 |
| | Palmucho | | Run-of-the-river | | 34 | | 34 | | 34 |
| | Los Molles | | Run-of-the-river | | 18 | | 18 | | 18 |
| | Sauzalito | | Run-of-the-river | | 12 | | 12 | | 12 |
| | Ojos de Agua(3) | | Run-of-the-river | | 9 | | 9 | | 9 |
| | Total hydroelectric | | | | 2,770 | | 2,759 | | 2,759 |
| | | | | | | | | | |
| | Atacama(3) | | Combined Cycle /Natural | | 732 | | 732 | | 732 |
| | San Isidro 2 | | Combined Cycle /Natural | | 388 | | 388 | | 388 |
| | San Isidro 1(3) | | Combined Cycle /Natural | | 379 | | 379 | | 379 |
| | Bocamina(4) | | Steam Turbine/Coal | | 350 | | 476 | | 478 |
| | Quintero | | Gas Turbine/Natural | | 257 | | 257 | | 257 |
| | Taltal | | Gas Turbine/Natural | | 240 | | 240 | | 240 |
| | Huasco | | Gas Turbine | | 64 | | 64 | | 64 |
| | Diego de Almagro | | Gas Turbine/Diesel Oil | | 24 | | 24 | | 24 |
| | Tarapacá | | Gas Turbine/Diesel Oil | | 20 | | 20 | | 20 |
| | Tarapacá(5) | | Steam Turbine/Coal | | — | | — | | 158 |
| | Total thermal | | | | 2,454 | | 2,580 | | 2,740 |
| | | | | | | | | | |
| | Canela II(3) | | Wind Farm | | 60 | | 60 | | 60 |
| | Canela I(3) | | Wind Farm | | 18 | | 18 | | 18 |
| | Total wind farm | | | | 78 | | 78 | | 78 |
| | | | | | | | | | |
| | Total | | | | 5,302 | | 5,417 | | 5,577 |
| | | | | | | | | | |
Pehuenche | | Pehuenche | | Reservoir | | 570 | | 568 | | 568 |
| | Curillinque | | Run-of-the-river | | 89 | | 89 | | 89 |
| | Loma Alta | | Run-of-the-river | | 40 | | 40 | | 40 |
| | Total Pehuenche | | | | 699 | | 697 | | 697 |
| | | | | | | | | | |
EGP Chile(6) | | Parque Solar Finis Terrae | | Solar | | 160 | | 160 | | 160 |
| | Parque Eólico Sierra Gorda Este | | Wind | | 112 | | 112 | | 112 |
| | Eólica Taltal | | Wind | | 99 | | 99 | | 99 |
| | Eólica Talinay Oriente | | Wind | | 90 | | 90 | | 90 |
| | Valle De Los Vientos | | Wind | | 90 | | 90 | | 90 |
| | Parque Eólico Renaico | | Wind | | 88 | | 88 | | 88 |
| | Pampa Solar Norte | | Solar | | 79 | | 79 | | 79 |
| | Carrera Pinto II Etapa | | Solar | | 77 | | 77 | | 77 |
| | Eólica Talinay Poniente | | Wind | | 61 | | 61 | | 61 |
| | Lalackama | | Solar | | 60 | | 60 | | 60 |
| | Pullinque | | Run-of-the-river | | 51 | | 51 | | 51 |
| | Cerro Pabellón | | Geothermal | | 48 | | 41 | | 41 |
| | Pilmaiquén | | Reservoir | | 41 | | 41 | | 41 |
| | Chañares | | Solar | | 40 | | 40 | | 40 |
| | Solar Diego de Almagro | | Solar | | 36 | | 36 | | 36 |
| | Eólica Los Buenos Aires | | Wind | | 24 | | 24 | | 24 |
| | Carrera Pinto I Etapa | | Solar | | 20 | | 20 | | 20 |
| | Lalackama 2 | | Solar | | 18 | | 18 | | 18 |
| | Azabache | | Solar | | 4 | | 0 | | 0 |
| | Solar La Silla | | Solar | | 2 | | 2 | | 2 |
| | Total EGP Chile (NCRE) | | | | 1,200 | | 1,189 | | 1,189 |
| | Total Aggregate Capacity for Enel Chile | | 7,200 | | 7,303 | | 7,463 |
50
|
|
|
|
|
| Installed Capacity(1)(2) |
| ||||
Company |
| Power Plant Name |
| Power Plant Type(3) |
| 2018 |
| 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 |
|
Table of Contents Installed Capacity(1)(2) Company Power Plant Name Power Plant Type(3) 2018 2017 2016 (in MW) EGP Chile (4) Eólica Los Buenos Aires Wind 24 — — Eólica Talinay Oriente Wind 90 — — Eólica Talinay Poniente Wind 61 — — Eólica Taltal Wind 99 — — Parque Eólico Renaico Wind 88 — — Parque Eólico Sierra Gorda Este Wind 112 — — Valle De Los Vientos Wind 90 — — Cerro Pabellón Geothermal 41 — — Pilmaiquén Reservoir 41 — — Pullinque Run-of-the-river 51 — — Carrera Pinto I Etapa Solar 20 — — Carrera Pinto II Etapa Solar 77 — — Chañares Solar 40 — — Lalackama Solar 60 — — Lalackama 2 Solar 18 — — Pampa Solar Norte Solar 79 — — Parque Solar Finis Terrae Solar 160 — — Solar Diego de Almagro Solar 36 — — Solar Diego de Almagro (Ampliación) Solar — — — Solar La Silla Solar 2 — — Total 1,189 — — Total Capacity 7,463 6,351 6,351
As of December 31,
(1) | The installed capacity corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its operation. |
(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” refers to thermal power that uses either diesel or natural gas to produce steam that turns the turbines. “Combined-Cycle” refers to a thermal power plant that burns natural gas, diesel oil, or fuel oil to turn the first turbine and then recovers the heat to generate steam to turn a second turbine. |
(3) | GasAtacama was merged into Enel Generation in October 2019. |
(4) | The Bocamina I steam turbine and coal plant were decommissioned on December 31, 2020. |
(5) | The Tarapacá steam turbine and coal plant were decommissioned on December 31, 2019. |
(6) | The acquisition of EGP Chile by Enel Chile was completed on April 2, 2018. It includes power plants of its subsidiaries Almeyda Solar SpA, Empresa Eléctrica Panguipulli S.A, Enel Green Power del Sur SpA, Geotérmica del Norte S.A., Parque Eólico Taltal S.A., Parque Eólico Talinay Oriente S.A., and Parque Eólico Valle de Los Vientos S.A. |
(1) The installed capacity corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its own operation.
(2) The 2018installed capacity may differ from previous years since the CEN has reviewed the capacity of each generation unit and adjusted their capacity.
(3) “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 that uses either diesel or natural gas to produce gas that moves the turbines. “Combined-Cycle” refers to a thermal power plant fueled with natural gas, diesel oil, or fuel oil to generate gas that first moves a turbine and then recovers the gas from that process to generate steam to move a second turbine.
(4) The acquisition of EGP Chile by Enel Chile was completed April 2, 2018. It includes power plants of its subsidiaries Almeyda Solar SpA, Empresa Eléctrica Paguipulli S.A, Enel Green Power del Sur SpA, Geotérmica del Norte S.A., Parque Eólico Tal Tal S.A., Parque Eólico Talinay Oriente S.A. and Parque Eólico Valle de Los Vientos S.A.
Property, Plant, and Equipment of Distribution Companies
We conduct our distribution business through Enel Distribution and its subsidiaries, Empresa Eléctrica de Colina Ltda. and Luz Andes Ltda. The description of our distribution subsidiary and its business is included in this “Item 4. Information on the Company.”
Enel Colina. A substantial portion of our distribution subsidiaries’subsidiary’s cash flow and net income isare derived from the sale of electricity distributed through our distribution installations. Significant damage to one or more of our main electricity distribution installations or interruption in the distribution of electricity, whether as a result of an earthquake, flood, volcanic activity, severe snowstorms and wind storms or any other such natural disasters, could have a material adverse effect on our operations.
The table below describes our mainleading electricity distribution equipment, such as distribution networks, substations, and transformers, and transmission lines. They include the consolidateconsolidated property, plant, and equipment figures of our subsidiary Enel Distribution.
TABLE OF DISTRIBUTION FACILITIES
General Characteristics
| | | | | | | | |
| | | | Transmission Lines(1)(2)(3) | ||||
|
| Concession Area |
| 2020 |
| 2019 |
| 2018 |
| | (in km2) | | (in kilometers) | ||||
Enel Distribution | | 2,105 | | 683 | | 683 | | 367 |
(1) | The transmission lines consist of circuits with voltages in the 35-220 kV range. |
(2) | Since 2019, the reported figures correspond to kilometers at the line circuit-level instead of at the line track-level. |
(3) | On January 1, 2021, the transmission business assets were spun-off to Enel Distribution shareholders as Enel Transmission. |
General Characteristics
|
|
|
| Transmission Lines(1) |
| ||||
|
| Concession Area |
| 2018 |
| 2017 |
| 2016 |
|
|
| (in km2) |
| (in kilometers) |
| ||||
Enel Distribution |
| 2,105 |
| 367 |
| 367 |
| 361 |
|
(1) The transmission lines consist of circuits with voltages in the 35-220 kV range.
Power and Interconnection Substations and Transformers(1)(2)
|
| As of December 31, 2018 |
| As of December 31, 2017 |
| As of December 31, 2016 |
| ||||||||||||
|
| Number of |
| Number of |
| Capacity |
| Number of |
| Number of |
| Capacity |
| Number of |
| Number of |
| Capacity |
|
Enel Distribution (2) |
| 56 |
| 206 |
| 8,398 |
| 56 |
| 203 |
| 8,386 |
| 56 |
| 204 |
| 8,281 |
|
| | | | | | | | | | | | | | | | | | |
| | As of December 31, 2020 | | As of December 31, 2019 | | As of December 31, 2018 | ||||||||||||
|
| Number of |
| Number of |
| Capacity |
| Number of |
| Number of |
| Capacity |
| Number of |
| Number of |
| Capacity |
Enel Distribution | | 57 | | 207 | | 7,554 | | 57 | | 207 | | 7,554 | | 56 | | 206 | | 8,398 |
(1) | The transformers’ voltage is in the range of 500 kV (in - high voltage, “hv”) and 1 kV (out - medium voltage, “mv”). |
(2) | On January 1, 2021, the transmission business assets were spun-off to Enel Distribution shareholders as Enel Transmission. |
(1) Voltage
51
(2) In 2017 a failure destroyed a transformer in the Quilicura SE, which caused its withdrawal from the system.
Distribution Network - Medium and Low Voltage Lines(1)
|
| As of December 31, 2018 |
| As of December 31, 2017 |
| As of December 31, 2016 |
| ||||||
|
| Medium Voltage |
| Low Voltage |
| Medium Voltage |
| Low Voltage |
| Medium Voltage |
| Low Voltage |
|
|
|
|
|
|
| (in Kilometers) |
|
|
|
|
| ||
Enel Distribution |
| 5,331 |
| 11,678 |
| 5,298 |
| 11,519 |
| 5,251 |
| 11,431 |
|
| | | | | | | | | | | | |
| | As of December 31, 2020 | | As of December 31, 2019 | | As of December 31, 2018 | ||||||
|
| Medium Voltage |
| Low Voltage |
| Medium Voltage |
| Low Voltage |
| Medium Voltage |
| Low Voltage |
| | | | | | (in Kilometers) | | | | | ||
Enel Distribution | | 5,406 | | 11,960 | | 5,349 | | 11,819 | | 5,331 | | 11,678 |
(1) Medium voltage lines: 1 kV - 34.5 kV; low voltage lines: 380-110 V.
(1) | Medium voltage lines: 1 kV - 34.5 kV; low voltage lines: 380-110 V. |
Transformers for Distribution(1)
|
| As of December 31, 2018 |
| As of December 31, 2017 |
| As of December 31, 2016 |
| ||||||
|
| Number of |
| Capacity |
| Number of |
| Capacity |
| Number of |
| Capacity |
|
|
|
|
| (in MVA) |
|
|
| (in MVA) |
|
|
| (in MVA) |
|
Enel Distribution |
| 21,767 |
| 4,739 |
| 21,838 |
| 4,575 |
| 21,876 |
| 4,505 |
|
| | | | | | | | | | | | |
| | As of December 31, 2020 | | As of December 31, 2019 | | As of December 31, 2018 | ||||||
|
| Number of |
| Capacity |
| Number of |
| Capacity |
| Number of |
| Capacity |
Enel Distribution | | 21,997 | | 5,108 | | 21,839 | | 4,963 | | 21,767 | | 4,739 |
(1) Voltage of these transformers is in the range of 34.5 kV (in - medium voltage) and 1 kV (out - low voltage).
(1) | These transformers’ voltage is in the range of 34.5 kV (in - medium voltage, “mv”) and 380-110 V (out - low voltage, “lv”). |
Insurance
Both ourOur electricity generation and distribution 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 tofrom 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 believeswe believe 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 accountconsidering the quality of the insurance companies and the coverage 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 meetengage with the insurance companies in order to obtainnegotiate what we believe is the most commercially reasonable insurance coverage.
Project Investments
We are continuously analyzinganalyze potential opportunities for growth.growth opportunities. The study and profitability assessment of our project portfolio is an ongoing effort. Industry technology is allowingallows for smaller, less environmentally damaging power plants. These plants can be built quicker,more quickly, allow greater flexibility to activate or deactivate according to system needs, and are generally preferred by the community.our stakeholders. We are favoringfavor renewable energy technology for our new power plant investments. Weinvestments and seek opportunities either by building new greenfield projects or by modernizing existing brownfield assets and improving (operationally and/operational or environmentally)environmental performance. TheEach project’s 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. Our project investments are ordinarily submitted for internal approvals in U.S. dollars, but occasionally they may be approved in another currency, including euros. The total amount invested as of the last fiscal year is presented in our functional currency, while the total approved investment is in the currency in which the project investment was approved, which may be different.
Below we list our most important projects under development; however,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
52
include connecting lines that could be owned by third parties and paid as tolls unless otherwise indicated. The financing for all of our projects described below comes from internally generated sources.
1.Distribution Business Projects
In 2020, our subsidiary Enel Distribution and its subsidiaries, Enel Colina and Empresa de Transmisión Chena, invested a total of Ch$ 116.7 billion in projects related to our customers’ natural growth rate, service quality requirements, and safety and information system needs.
The most relevant investments in 2020 include the following:
● | Ch$ 34.8 billion in the medium- and low-voltage network to facilitate new customer connections, including residential and large volume customers and real estate projects. |
● | Ch$ 22,5 billion to reinforce feeders, specifically those defined in our quality plan. Automation of the medium-voltage network increased rapidly due to the installation of 335 new remote-control devices, reaching 2,462 devices controlled by our centralized network operations center. |
● | Ch$ 20.7 billion to further our digitalization processes. |
● | Ch$ 19.9 billion to increase our distribution capacity to high- and medium-voltage facilities: Bicentenario, Pudahuel, Quilicura, Pajaritos, Altamirano, San Joaquin, and San Jose´s Substations, and to reinforce feeders in the municipalities of Cerro Navia, Chena, San Bernardo, Vizcaya, Terminal, and Los Vientos; |
● | Ch$ 6.2 billion to corrective network maintenance, install transmission lines, and interconnection and power substations; |
● | Ch$ 4.6 billion to comply with regulations regarding network and substation normalization; |
● | Ch$ 3.8 billion in anti-theft measures, such as the shielding and reinforcement of the network; and |
● | Ch$ 4.4 billion in network relocations due to new highways and requests from municipalities. |
Generation Business Projects
Projects completed during 2018Completed in 2020
Bocamina Optimization ProjectEnel Generation
Bocamina is a 478Antuco Smart Repowering Project
The Antuco repowering project was executed within our existing 321 MW coal-firedAntuco power plant, located in Coronel in the Bíobío Region in southern Chile, which consistsChile. Antuco is a run-of-the-river hydroelectric power plant with two Francis vertical units. It uses the waters of two units, Bocamina I (128 MW)the Polcura, Laja, and Bocamina II (350 MW). Bocamina II started commercial operationsPichipolcura Rivers and the discharges from the Abanico and El Toro power plants.
The project involved replacing one turbine (Unit I) installed 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 included1981, with an efficiency rate of 88%, with a new technical optimization plan. On April 2, 2015,turbine with a target efficiency rate of 94%, producing 204 GWh/year of new energy and increasing installed capacity by 1 MW. Replacing the Chilean Courtturbine in Unit I was a two-step process. Step one was conducted in September 2019, and step two was completed in November 2020, reaching commercial operation in November 2020.
53
As of December 31, 2020, the project has been completed, except for operational improvements. The total approved the new RCA, and the plant resumed operations in July 2015, after complying with all requested conditions established in the new RCA.
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 received the Provisional Acceptance Certificate.
· On October 17, 2018, we received the certificate of definitive reception of the building works for the south dome.
We expect that the estimated total investment will be Ch$ 62,103was US$ 14.5 million, of which Ch$ 61,357 million was7.0 billion (US$ 9.8 million) had been incurred as of December 31, 2018.2020.
A.Sauzal Smart Repowering Project
The Sauzal Smart Repowering project was executed within our existing 80 MW Sauzal power plant, located in the Libertador General Bernardo O’Higgins Region in central Chile. It is a run-of-the-river hydroelectric power plant with three Francis vertical units that use the waters of the Cachapoal and Claro Rivers.
The project involved replacing two turbines (Unit I and Unit II) installed in 1948, with an efficiency rate of 88%, with new turbines with a target efficiency rate of 94.7%, each producing 13.7 GWh/year of new energy. The project increased installed capacity by 3 MW.
As of December 31, 2020, the project has been completed except for operational improvements. The construction of Unit I began in July 2019, and it achieved commercial operation in October 2019. The construction of Unit II began in August 2020, and it achieved commercial operation in October 2020.
The total approved investment was US$ 10.5 million, of which Ch$ 5.2 billion (US$ 7.4 million) had been incurred as of December 31, 2020.
Projects under Construction in 2020
A.1 Enel Generation
Bocamina Coal Plant Landfill Closure Plan
The project considers the application of the best practices for ash dumpsite facilities. It includes improvements to the landfill’s infrastructure and operations, the implementation of a high standard for its closure, and fulfillment of the obligations arising from the Environmental Qualification Resolution (“RCA” in its Spanish acronym) approved in March 2015. The closure plan comprises waterproofing materials that include a conductive geomembrane, use of the highest thicknesses of fillers and substrates, a selection of native species, a high density of specimens per hectare, and a revegetation design according to reference ecosystems in the area, with the advice of Universidad de Concepción.
The closure plan is composed of two stages:
● | Stage 1: The approved project considers the closure of 67,000 m2 of the landfill. |
● | Stage 2: This stage will be executed when the landfill completes its operational life. |
In February 2019, the SEA issued all permits. In July 2019, the revegetation pilot was completed, and a notice to proceed with a contractor to complete stage 1 was given. The installation of waterproof materials and the application of soil and substrates fillers were completed on May 29, 2020. After this milestone, native species were planted, and the process was completed on September 16, 2020.
The total approved investment is €15.9 million, of which Ch$ 12.9 billion (€14.8 million) had been incurred as of December 31, 2020. We expect stage 2 to be completed in 2021-2022.
Los Cóndores Hydroelectric Project
The Los Cóndores project is located in the Maule Region, in the San Clemente area.area in central Chile. 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.
54
As of December 31, 2018, 65.6%2020, 75% of the project washad been completed, and 86.8%89% of the transmission lines werehad been completed and assembled, according to the lastassembled.
The total approved construction plan. We expect that the estimated total investment will be Ch$ 665,986 million,is US$ 1.2 billion, of which Ch$ 419,022 million was637.3 billion (US$ 879.0 million) had been incurred as of December 31, 2018. This2020. Construction began in April 2014, and we expect the project is being financed primarily with internally generated funds.to be completed by 2023.
SauzalRapel Smart Repowering Project
The SauzalRapel Hydroelectric Repowering project is towill be implementedexecuted within the Sauzalour existing 377 MW Rapel power plant, located in the Libertador General BernandoBernardo O’Higgins Region ofin central Chile. The power plant uses the water of the Cachapoal and Claro Rivers andRapel is a run-of-the-riverreservoir hydroelectric power plant with threefive Francis vertical units.units that use water from the Rapel River.
The project involves replacing two turbines (Unit 3 and Unit 4) installed in 1968 with a targetan efficiency rate of 95%, obtaining upless than 85%. The turbines will have a new hydraulic design, offering improved efficiency and a more extensive operation range. We expect to 3MWincrease installed capacity by 2 MW (1 MW each unit) and produce 67 GWh/year of new capacity and 13.7 GWh per year.energy. The contract was signed with Voithawarded in July 2018. During 2018, detailed engineering was carried outSeptember 2020, and the manufacturingcontractor’s basic design activities began immediately.
As of December 31, 2020, 2% of the runner parts, shaftproject had been completed. In 2021, the engineering design will be completed, and sealsmodel tests and the main manufacturing activities will be executed. Unit 3 will be dismantled, and the installation of the first unit commenced, with an overall progress of 37% as of December 2018.new turbine will begin in 2022. Once the new Unit 3 turbine has been installed, Unit 4 will be dismantled, and the new turbine will be installed.
The estimated total approved investment is US$ 10.511.9 million, of which US$ 2 million hasnone had been incurred as of December 31, 2018. This2020. We expect both units to be installed and the project to be completed by 2023.
EGP Chile
Azabache Solar Project
Azabache is a photovoltaic (“PV”) project in Calama in the Antofagasta Region in northern Chile and is being financed primarilyexecuted within our existing Valle de los Vientos wind farm. The project has an installed capacity of 61 MW, consisting of 154,710 monocrystalline bifacial PV modules with internally generated funds.a solar tracking system and occupying approximately 149 hectares.
Bocamina closure planThe plant is connected to the Valle de los Vientos substation, which is connected to the Calama substation. The interconnection solution includes the main transformer and a step-up substation with a conventional bay, including its ancillary elements.
A connection contract between EGP Chile and Acciona was signed, which requires the Usya PV solar power plant project (owned by Acciona) to install the second circuit of the landfillValle de los Vientos – Calama transmission line (13.6 km) and the extension of Valle de los Vientos substation.
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 Assessmenttotal approved in March 2015.
The projectinvestment 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.
· 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.
For stage 1 we estimate a total investment of Ch$ 6,555US$ 49 million, of which Ch$ 1,668 million was28.0 billion (US$ 39.4 million) had been incurred as of December 31, 2018.2020. Construction began in April 2020, and we expect the project to be completed by the end of the second quarter of 2021.
A.2 EGP Chile
Campos del Sol I Solar Project
The Campos del Sol I solar project is located in the Atacama Region in northern Chile, approximately 60 km northeast of Chile. ItCopiapó. The PV solar power plant has 382 MW of installed capacity and consists of 974,400 crystalline bifacial PV modules with a 382 MWsolar tracking system. It will be the largest PV solar power plant. Thisplant in Chile, covering approximately 1,700
55
hectares. The connection point includes two main transformers through the Carrera Pinto substation, owned by Transelec, via a 7.5 km, 220 kV transmission line.
The project was awarded to EGP Chile during the 2016 Distribution Companies Tender. EGP Chile intended to bid part of this project in the DisCo Tender 2016 and is expectedbilateral processes to reachmove up the commercial operation in 2021.date of operation. The land has been secured, the environmental approval has been obtained, and the power purchase agreements for 2021-2045 have already been confirmed. The project has potential synergies with the alreadyEGP Chile’s operational Carrera Pinto solar project. We expect a
The total approved investment ofis US$320.9 million, of which weCh$ 164.3 billion (US$ 231.2 million) had accrued US$ 2 millionbeen incurred as of December 31, 20182020. Construction began in August 2019, and we expect the project to be completed by the third quarter of 2021.
Cerro Pabellón Geothermal Extension Project
The Cerro Pabellón extension project is a geothermal energy plant with a capacity of 28 MW and is in the Antofagasta Region in northern Chile. It has potential synergies with our operational Cerro Pabellón geothermal project and will use existing infrastructure such as a substation and a transmission line.
The total approved investment is US$ 95.8 million, of which Ch$ 55.9 billion (US$ 78.7 million had been incurred as of December 31, 2020. Construction began in August 2019, and we expect the project to be completed by the end of the second quarter of 2021.
Domeyko Solar Project
The Domeyko PV solar project is in the Antofagasta Region in northern Chile. It has an installed capacity of 204 MW, consisting of 486,720 bifacial PV modules with a solar tracking system and occupying approximately 700 hectares.
The Domeyko project will be connected to the Puri substation, owned by Minera Escondida Ltda., via an 18 km, 220 kV interconnection line. The interconnection substation has a gas-insulated substation configuration, while the step-up substation will have a single bar configuration. The Domeyko project will sell energy to Enel Generation under a 20-year power purchase agreement.
The total estimated investment is US$ 164.2 million, of which Ch$ 71.7 billion (US$ 100.9 million) had been incurred as of December 31, 2020. Construction began in May 2020, and we expect the project to be completed by the end of the third quarter of 2021.
Finis Terrae Solar Extension Project
The Finis Terrae extension project is a PV solar power plant in María Elena in the Antofagasta Region in northern Chile and has an installed capacity of 126 MW.
The project has strong operational synergies with EGP Chile’s existing Finis Terrae power plant and will use the same transmission infrastructure as the existing Finis Terrae power plant. A new bay unit and new power transformer will be installed in the current substation for interconnection purposes.
The total approved investment is US$ 94.4 million, of which Ch$ 35.3 billion (US$ 49.7 million) had been incurred as of December 31, 2020. Construction began in May 2020, and we expect the project to be completed by the end of the fourth quarter of 2021.
Renaico II Wind Project
The Renaico II wind project is located in the Araucanía Region of Chile and itin southern Chile. It consists of a 133144 MW power plant with two farms: (i) the Las Viñas project, which consists ofincluding a 4858.5 MW wind power plant built by EGP Chile and (ii) the
56
Puelche project, which
consists of a 85an 85.5 MW wind power plant developed independently by Pacific Energy. The Puelche project will be entirely acquired in its entirety by EGP Chile. This
The project is expectedconsists of 32 wind turbine generators, interconnected to begin commercial operationsSEN through the existing Renaico I 220 kV substation. A new bay will be installed in 2021,the substation with a main transformer of 165 MVA. The Renaico II wind project has potential synergies with EGP Chile’s operational Renaico I wind project and will use existing infrastructure such as a substation and a transmission line. The land has been secured, and the environmental approvalapprovals were obtained.
The total approved investment is in process. We estimate a total investment of US$ 176.4 million, with US$ 0.51 million accruedof which Ch$ 77.5 billion (US$ 109.0 million) had been incurred as of December 31, 20182020.Construction began in April 2020, and we expect the project to be completed by the end of the third quarter of 2021.
Cerro Pabellón 3Sol de Lila Solar Project
The Cerro Pabellón 3Sol de Lila is a PV solar project is locatedin the Atacama Desert in the Antofagasta Region in northern Chile. Chile, at an altitude of 2,700 meters and approximately 250 km southeast of the city of Antofagasta. Due to the project’s remoteness, the construction of a camp with a capacity for 400 people is required.
It is a greenfield solar project with an installed capacity of 163 MW that consists of 407,400 crystalline bifacial PV modules with a 33 MW geothermal powersolar tracking system. The solar plant. We expect that this project will begin is connected to operate commercially in 2020. It has potential synergies with the operational Cerro Pabellón geothermal projectAndes substation, owned by AES Gener, and will use existing infrastructures such asincludes one main transformer and a substation and1.2 km, 220 kV transmission line.
The land has been secured and the environmental approvaltotal approved investment is in process. We expect a total investment of US$ 95.8129.7 million, none of which was accruedCh$ 58.5 billion (US$ 82.3 million) had been incurred as of December 31, 2018.2020. Construction began in February 2020, and we expect the project to be completed by the end of the third quarter of 2021.
B.Projects Underunder Development in 2020
We are currently evaluating the development of the following projects, which we classify as “under development”.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,as well as future tender prices for supplying the energy requirements of the regulated market and/orand negotiations with existing or new unregulated customers.
B.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.
Quintero Combined-Cycle Thermal Project
The Quintero project is located in the Valparaíso Region and consists ofin central Chile. It is an energy efficiency project that takeswill take advantage of the heat of the gases emitted by the existing turbines to produce steam through the installation ofby installing a steam turbine and a generator, which allows convertingwill convert the existing open cycleopen-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 wouldwill reach a totalfull capacity of 387 MW. We wouldwill deliver the produced energy to the SEN through the existing Quintero-San Luis line, a simple 220 kV circuit built to evacuate the energy oftransmit the combined-cycle power plant.plant’s energy.
In 2017, we started the preparation of the environmental impact studyassessment and the implementation of the sustainability plan. However, during August 2018, the Quintero and Puchuncaví areas suffered an environmentalecological crisis leavingthat left more than 300 people suffering from the toxic effects allegedly associated with gas emissions of other industries.industries’ gas emissions. As a result, the project was indefinitely postponed, and the environmental impact studyassessment has been suspended.
The total estimated total investment for the project is Ch$ 150,651US$ 215.1 million, of which Ch$ 2,858 million was2.9 billion (US$ 4.0 million) had been incurred as of December 31, 2018.2020.
Ttanti Combined-Cycle ProjectSan Isidro Power Plant Upgrade
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The San Isidro power plant is a combined cycle plant located in the Valparaiso Region in Central Chile. The power plant has two combined-cycle units, with a total installed capacity of 740 MW. The project consists of upgrading the existing gas turbines to improve the units’ efficiency. The capacity for each unit will increase by approximately 10 MW, which will increase the expected generation of the power plant.
The Ttantitotal estimated investment is US$ 10.2 million, of which Ch$ 51.8 million (US$ 0.1 million) had been incurred as of December 31, 2020. We expect work on the project to begin in 2023 and Unit 2 to be completed in 2023 and Unit 1 in 2026.
Taltal Combined-Cycle Thermal Project
The Taltal power plant 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 withnorthern Chile and has an aggregate installed capacity of 1,290240 MW (430comprised of two 120 MW for eachgas turbines. The project would convert the existing Taltal gas-fired, open-cycle plant into a combined-cycle plant by adding a turbine to the vapor phase. This turbine would use the steam generated by the gas turbines’ heat emissions to produce energy and considerably improve its efficiency. The steam turbine would add 130 MW of installed capacity, and therefore, the three units), and one unit would be able to use diesel oil as a backup in case of a shortage of natural gas. TheTaltal power plant would connectreach a total capacity of 370 MW. We would supply the energy produced to SEN via the SEN through a 0.5 kmexisting 220 kV double circuitdouble-circuit, Diego de Almagro – Paposo transmission line to the Atacama substation, which would be expanded for this purpose.line.
The environmental permit, requested through an Environmental Impact Assessment,EIA and submitted in December 2013, was approved in DecemberJanuary 2017 by the Environmental Evaluation Service (“SEA”SEA in its Spanish acronym) of the AntofagastaAntofagasata Region. Any decision related to the constructiondevelopment of the project will depend primarily on the commercial opportunities foreseen in the upcoming years, (pricessuch as prices in future tenders and/orand negotiations with unregulated customers, among other factors).others.
The total estimated total investment for the first unit is Ch$ 251,078US$ 196.4 million, of which Ch$ 1,319 million was2.9 billion (US$ 4.0 million) had been incurred as of December 31, 2018.2020. We expect the project to be completed in 2021-2023.
Taltal Combined-Cycle ProjectEGP Chile
Campos del Sol II Solar Project
The TaltalCampos del Sol II solar 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 turbineis in Copiapó in the vapor phase,Atacama Region and has an installed capacity of 398 MW. Campos del Sol II is a PV solar power plant consisting of 893,508 crystalline bifacial PV modules with a solar tracking system. The plant is built on approximately 1,000 hectares.
The connection point will be the Bella Mónica step-up substation, located between Campos del Sol I and Campos del Sol II. Bella Mónica is located 8 km from the Illapa substation, owned by Celeo Redes Chile Ltda., and is connected via a 220kV transmission line.
The total estimated investment is US$ 273.6 million, of which would useCh$ 12.8 billion (US$ 18.0 million) had been incurred as of December 31, 2020. We expect construction to begin in 2021 and the steam generated byproject to be completed in 2022-2023.
El Manzano Solar Project
The El Manzano solar project is located in the gas turbines’ heat emissionsMetropolitan Region of Chile, with an installed capacity of 101 MW. The land has been secured, and environmental approval has been obtained.
The total estimated investment is US$ 78.1 million, of which none had been incurred as of December 31, 2020. We expect construction to produce energy, which will considerably improve its efficiency. begin in 2022 and the project to be completed in 2023.
Finis Terrae 3 Solar Project
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The Taltal power plantFinis Terrae 3 solar project is located in the Antofagasta Region. Currently, the existing Taltal power plantRegion of Chile. It has two gas turbines with 120 MWan installed capacity each. The steam turbine would add 130of 18 MW and therefore,is an extension of 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.Finis Terrae Extension project currently under construction. The land has been secured, and environmental approval has been obtained.
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).
Thetotal estimated total investment is Ch$ 136,998US$ 11.1 million, of which Ch$ 2,87314.1 million was(US $ 0.02 million) had been incurred as of December 31, 2018.
Taltal Battery Energy Storage System2020. We expect construction to begin in 2021 and the project to be completed in 2021-2022.
PMGD Solar Projects
The project consistsPMGD solar projects represent a cluster of the installation of10 solar PV plants located in Chile’s central region, with a battery energy storage system (BESS) in the Taltal power plant to provide ancillary services in upcoming years.
The project would reach ancumulative installed capacity of 12 MW75 MW. The plants are located on separate plots of land, 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.environmental approval process is ongoing.
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 total estimated total investment is Ch$ 8,119US$ 51.6 million, of which Ch$ 15.1 million was4.7 billion (US$ 6.6 million) had been incurred as of December 31, 2018.2020. We expect construction to begin in 2021-2022 and the projects to be completed in 2021-2022.
Tarapacá Battery Energy Storage SystemSierra Gorda Solar Project
The Sierra Gorda PV solar project is in Sierra Gorda, near Calama, in the Antofagasta Region in northern Chile. The PV solar power plant has an installed capacity of 375 MW and occupies 850 hectares, with a perimeter of approximately 28 km.
It is a greenfield project that will be built inside the existing Sierra Gorda wind farm, which EGP Chile owns. The project has five main areas for PV modules inside the wind farm and an independent space for the medium voltage/high voltage substation. It consists of 830,000 monocrystalline bifacial PV modules with a solar tracking system. The interconnection substation is located 19 km from the installation of a BESSsolar plant, 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.Centinela substation owned by Red Eléctrica Chile.
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 total estimated total investment is Ch$ 9,427US$ 252.5 million, of which Ch$ 80.5 million was1.2 billion (US$ 1.7 million) had been incurred as of December 31, 2018.
C.2 EGP Chile2020. We expect construction to begin in 2021 and the project to be completed in 2022-2023.
Name |
| Capacity (MW) |
| Potential Synergies |
| Expected |
| Estimated |
| Amount accrued |
|
|
|
|
|
|
|
|
| (in US$ million) |
| ||
Azabache |
| 63 MW(1) |
| With use the same land as the already operational Valle de los Vientos wind project as well as existing transmission line towers. |
| 2021 |
| 49.0 |
| 0.34 |
|
Valle del Sol |
| 116 |
| With the operational Finis Terrae I solar project. |
| 2024 |
| 91.4 |
| 0.79 |
|
Finis Terrae Extension Project |
| 126 |
| With the operational Finis Terrae I solar project and use of existing infrastructure (including a substation and transmission line). |
| 2021 |
| 94.4 |
| 0.09 |
|
Sol de Lila |
| 122 |
| This project may interconnect with the Argentine transmission system. |
| 2023 |
| 97.9 |
| 0.81 |
|
Flor del Desierto |
| 50 |
| — |
| 2023 |
| 39.4 |
| 0.31 |
|
Los Manolos |
| 80 |
| — |
| 2023 |
| 62.6 |
| 0.33 |
|
(1) The first wind and photovoltaic hybrid at an industrial scale in Chile
Valle del Sol Solar Project
2.Distribution Business Projects
During 2018, our subsidiary Enel Distribution and its subsidiaries, Empresa Eléctrica de Colina and Luz Andes, invested a total Ch$ 96 billion in projects related to our customers’ natural growth rate, service quality requirements, safety and information system needs.
The most relevant investments in 2018 include the following:
· Ch$ 21 billionValle del Sol PV solar project is in the medium and low voltage network to allow for the connectionAtacama Desert, approximately 100 km west of our new customers, including residential customers, large volume clients, and real estate projects.
· Ch$ 17.0 billion to increase our distribution capacity, consisting of Ch$ 12 billion investedCalama in the San Pablo, Chicureo, Club Hípico substationsAntofagasta Region in northern Chile. It was awarded a 20-year power purchase agreement during the energy Distribution Companies Tender 2017 (2024-2043).
It is a greenfield solar project with an installed capacity of 163 MW that consists of 406,980 monocrystalline bifacial PV modules with a solar tracking system and occupying 320 hectares. Valle del Sol will connect to the Miraje substation, owned by Transelec, via a new 220 kV bay. The connection solution includes a step-up substation, one main transformer of 130/160 MVA (33/220 kV), and the interconnection 10 km, 220 kV transmission line.
The total estimated investment is US$ 125.4 million, of which Ch$ 1.030.2 billion for adding and reinforcing medium voltage feeders.
· Ch$ 15 billion to reinforce feeders, specifically those determined by our service quality plan. Automation of the medium voltage network increased rapidly(US$ 42.5 million) had been incurred as a result of the installation of 320 new remote control devices, reaching a total of 1,701 devices controlled by our Centralized Network Operations Center.
· Ch$ 4 billion in network relocations due to new highways and requests from municipalities, which imply changing the electricity cables, including in some cases placing them below ground.
· Ch$ 12 billion to buy and install 190,856 smart meters in 2018, reaching a total 291,719 smart meters throughout 32 districts in Santiago. Smart meters allow us to remotely and automatically read electricity consumption, connect and disconnect electricity supply and allow customers to install solar panels and inject their surplus energy into the distribution network without the need of any additional equipment. By 2025, we should have all of our clients with smart meters, according to current regulations.
In December 2017, the CNE published the Technical Standard of Quality of Service for Distribution systems (NTDC in its Spanish acronym). This norm seek to reduce the service interruption duration (known in the industry as System Average Interruption Duration Index or SAIDI) from the current 8.5 hours per customer in urban areas on an annual basis to only 5 hours (measured as an average per municipality) by 2020 and to less than one hour by 2050 as well as to reduce the frequency of interruptions (known as System Average Interruption Frequency Index or SAIFI) from the current 6 times per customer on an annual basis to 4.5 by 2020. As of December 31, 2018, our average SAIDI of2020. We expect construction to begin in 2021 and the 33 municipalities that we covered was 3 hours (a 32% reductionproject to be completed in comparison to 2017) and our SAIFI was 1.5 times.2021-2023.
Major Encumbrances
As of December 31, 2018,2020, we did not have full ownership of our assets and they are not subject to materialany major encumbrances.
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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.of this Report. Our audited consolidated financial statements as of December 31, 20182020, and 20172019 and for each of the yearsyear in the three-year period ended December 31, 2018,2020 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 |
1.Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company
WeThrough our subsidiaries, we own and operate through our subsidiaries, electricity generation, transmission, and distribution companies in Chile. Our revenues, income, and cash flowsflow are derived primarily come from the operations of our subsidiaries and associates in Chile.
Factors such as (i) hydrological conditions, (ii) fuel prices, (iii) regulatory developments, (iv) exceptionalextraordinary actions adopted by governmental authorities, and (v) changes in economic conditions may materially affect our financial results. In addition, ourOur 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. TheFor the years covered by this Report, the impact of these factors on us for the years covered by this Report, is discussed below.
After giving effect to the 2018 Reorganization (see “Item 4. Information on the Company — A. History and Development of the Company — the 2018 Reorganization”), sinceSince April 2, 2018, we ownhave owned 93.6% of Enel Generation and we consolidateconsolidated operations and results of EGP Chile, a wholly owned subsidiary.wholly-owned subsidiary, following the completion of the 2018 Reorganization. For further information regarding theour incremental acquisition of this company,Enel Generation, please refer to “Item 4. Information on the Company — A. History and Development of the Company. — History.” The effects of this transaction on our consolidated financial statements as of and for the years December 31, 20182020, and 2019 are described in Note 65 to our consolidated financial statements.
On November 2, 2019, the Ministry of Energy published Law No. 21,185, establishing a Transitional Mechanism for the Stabilization of Electric Power Prices for Customers subject to Tariff Regulation (the “Tariff Stabilization Law”). An agreement to sell up to US$ 290 million of the accounts receivables generated through this mechanism was executed with Goldman Sachs and the Inter-American Development Bank.
On September 14, 2020, the National Energy Commission published Exempt Resolution No. 340, which modified the technical provisions for implementing the Tariff Stabilization Law. This Resolution clarified that the payment to each supplier must be imputed to the payment of balances chronologically, first paying off the oldest balances and then the newest ones, and not on a weighted basis over the total payment balances pending, as the industry had interpreted before said date. The effects of the Tariff Stabilization Law as of December 31, 2020, and 2019 are described in Note 9a.1 to our consolidated financial statements.
In 2020 and 2019, we recorded impairment costs associated with accelerating the closures of the Tarapacá, Bocamina I, and Bocamina II coal-fired power plants (see Notes 16.e.x and 31.b. to our consolidated financial statements). In 2019, we accounted for non-recurring income from the early termination of three energy supply contracts signed in 2016 between Enel Generation and Anglo American Sur. The effects are described in Note 28.3 to our consolidated financial statements.
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a.Generation Business
A substantial part of our generation capacity is hydroelectric and depends on the prevailing hydrological conditions in Chile. Our installed capacity as of December 31, 2020, 2019, and 2018 2017 and 2016 was 7,4637,200 MW, 6,3517,303 MW, and 6,3517,463 MW, respectively, of which 48%49.5%, 55%48.6%, and 55%47,5% was hydroelectric, respectively. See “Item 4. Information on the Company — D. Property, Plant and Equipment.”
Hydroelectric generation was 9,712 GWh, 10,578 GWh, and 11,395 GWh 9,652 GWhin 2020, 2019, and 9,078 GWh in 2018, 2017 and 2016, respectively. Our 2018 hydroelectric generation was greater than 2017, continuing the same trend that occurreddecreased in 2017 and 2016. The increase was2020 compared to 2019, mainly related to lower hydrological production due to the slight increase in the total fluvial energy and rainfalls that were few in number but intense, especially during July and between October and November 2018. However,drier conditions. Since 2010, some importantcritical reservoirs are stillhave been at relatively low levels due to several years of accumulated drought, characterized by low rainfallsrainfall levels and a poor snowmelt, since 2010.low snowmelt.
Hydrological conditions in Chile can range from very wet, as a result of several years of abundant rainfall andwith lakes at their peak capacity, to extremely dry, as a consequence of a prolonged droughtsdrought 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, thereThere is a wide range of possible hydrological conditions between these two extremes, and their final effect on us may dependoften depends on the accumulated hydrology. For instance, a new year with drought conditions has less of ana smaller impact on us if it follows several periods of abundant rainfall as opposed toperiods instead of exacerbating a prolonged drought. Likewise, a goodan abundant hydrological year has lessa smaller marginal impact if it comeseffect after several wet years as opposed toinstead of after a prolonged drought.
In Chile, the period of the year that typically has the most precipitation is from May through August, and theAugust. The period in which snow and ice in the mountains melt at higher levels is during the warmer months, from October through March, providing water flow to lakes, reservoirs, and rivers, which supply our hydroelectric plants, most of themwhich are located in southern Chile. For purposes of discussing the impact of hydrological conditions on our business, we
We generally categorizeclassify 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 ourfactors. Our operating income can only be explained by looking at a combination of factors and not each one on a stand-alone basis.factors.
Hydrological conditions affect electricity market prices, generation costs, spot prices, tariffs, and the mix of hydroelectric, thermal, and NCRE generation, whichgeneration. CEN is constantly being determined bydefining the CENmix 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)the “spot price”) is determined by the system’s marginal cost of the system.cost. The marginal cost is the cost of the most expensive power plant in operation, given an efficiency-based dispatch. RegulationThe regulations also considersconsider capacity payments to generators, which remunerates each power plant’s installed capacity according to its availability and contribution to the system’system’s safety. This capacity payment is determined by the regulator every six months. Run-of-the-river hydroelectricHydroelectric and NCRE generation areis almost always the least expensive generation technology and normallytypically 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 significanthigh cost in extended drought conditions. The cost of thermal generation cost 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 tocan dispatch energy to the system at very low marginal costs, but they depend on the wind blowing of the wind or the shining of the sun.sun shining.
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 normallyusually increase spot prices. Spot market prices affect our results because we must purchase electricity in the spot market when our contracted energy sales are greatermore than our generation, and wegeneration. We sell electricity in the spot market when we have electricity surpluses.
There are manyHydrological conditions do not have an isolated effect but need to be evaluated in conjunction with other factors thatto understand the impact on our operating results better. Many different factors may affect our operating income, including
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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 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 |
| Expected effects on spot prices |
| Expected impact on our operating results | |||||
---|---|---|---|---|---|---|---|---|---|
| | ||||||||
Dry | | Higher spot prices | |
| |||||
| Reduced | |
| ||||||
| Increased thermal generation | |
| ||||||
| | ||||||||
Wet | | Lower spot prices | |
| |||||
| | | | ||||||
| Increased hydroelectric generation | |
| ||||||
| | | | ||||||
| Reduced thermal generation | |
|
If factors other than those described above apply, the expected impact of hydrological conditions on operating results will be differentdiffer 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.Distribution Business
b. | Distribution Business |
Our electricity distribution business is conducted through Enel Distribution in the Santiago metropolitan area, providing electricity to more than 1.92.0 million customers. Santiago is the country’sChile’s most densely populated area and has the highest concentration of industries, industrial parks, and office facilities in the country.facilities.
For the year ended December 31, 2018,2020, electricity sales amounted to 16,782were 16,481 GWh, representing a 2.1% increase when3.8% decrease compared to 2017.2019. For the year ended December 31, 2017,2019, electricity sales amounted to 16,43817,135 GWh, representing a 3.2%2.1% increase when compared to 2016.2018.
Distribution revenues are mainly derived from the resale of electricity purchased from generators. Revenues associated with distribution include the recovery of the cost of electricity purchased and the resulting revenues from the “Value Added from Distribution,” or VAD, plus the physical energy losses permitted by the regulator. Other revenues derived from our distribution business normallytypically consist of transmission revenues, charges for new connections and the maintenance, and rental of meters, among others. It also includes revenues derived from public lighting, infrastructure projects
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mainly associated with real estate development, and energy efficiency solutions, including air conditioning equipment, LED lights, etc., in all cases, including customers outside of our concession area.
Although these other revenue sources of revenue have increased, theour core business continues to be the distribution of electricity at regulated prices. Therefore, the electricity regulatory framework has a substantive impact on our distribution business results.
In particular, regulators set distribution tariffs taking into accountconsidering the cost of electricity purchases paid by distribution companies (which distribution companies pass on to their customers) and the VAD, all of which are intended to reflect the investment and operating costs incurred by distribution and generation companies and to allow them to earn a regulated level of return on their investments and guarantee service quality and reliability. Our earnings are determined to a large degree by government regulation, mainly through the tariff setting process. Our ability to buypurchase electricity relies highlyheavily on generation availability and, on regulation to a lesser degree.degree, regulation. The cost of electricity purchasedpurchases is passed on to end usersend-users through tariffs that are set for multi-year periods. Therefore, variations in the price at which a distribution company purchases electricity do not have an impact on our profitability.
In the past, we focused on reducing physical losses, especially those due to illegally tapped energy. Our physical losses have generally been around 5% for the lastover 20 years, a level close to theour concession’s distribution technical loss threshold for our concession.threshold. Reducing losses below this level requires additional investments to reduce illegal tapping and would not be expected to have an economically attractive return. Currently, we are working instead on improving our efficiency, especiallyprimarily through new technologies to automate our networks as well as in increasing our quality of service in order to improveenhance the efficiencyeffectiveness of our facilities, profitability of our business and increase our capacity to satisfy our growing number of customers and their increasing demands.
Enel Distribution’s tariff review process, which set the tariffs for the 2016-2020 period, was finalized in August 2017. The new tariffs were applied retroactively as of November 2016, and the review did not have a significant effect on Enel Distribution’s tariffs. Tariffs for residential, commercial, and industrial customers changed, but the changes offset each other, and Enel Distribution’s revenues remained stable. In September 2018, there was an extraordinary and non-retroactive tariff update process that will be effective until the next tariff settingtariff-setting process. This tariff increase is to recognizerecognizes the necessary investments to comply with the new requirements on the quality of service standards.standards and was not retroactive. Tariff reviews seek to capture distribution efficiencies and economies of scale resulting from economic growth.
c.Economic ConditionsThe technical bases for the tariff-setting process for 2020-2024 were published at the end of the first half of 2020. This is the first tariff-setting process where the CNE has carried out a single study. In the tariff-setting process for 2016-2020, the tariff was calculated using a weighted average between the Reference Company study (one-third) and the CNE study (two-thirds). During the second half of 2020, the consulting company that carried out the study was assigned, and, as of the date of this Report, the study has not yet produced conclusive results.
In response to the Covid-19 pandemic, Law No. 21,249 was published on August 8, 2020, providing exceptional measures for end-users of health services, electricity, and natural gas. The law prohibits utility companies from cutting off services to residential and small businesses due to late payment for 90 days following the publication of the law. Also, unpaid amounts accrued from March 18, 2020 to November 30, 2020, may be paid in up to 12 equal and consecutive monthly installments, beginning in December 2020. The monthly installments may not include fines, interest, or associated expenses. On December 29, 2020, Law No. 21,301 was ratified and extended the terms defined in Law No. 21,249, increasing the prohibition on cutting off services to 270 days from 90 days, as well as the maximum number of monthly installments to 36 from 12.
c. | Economic Conditions |
Macroeconomic conditions, such as economic growth or recessions, changes in employment levels, and inflation or deflation, may have a significant effect onsignificantly affect 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.plans and the cost of servicing U.S. dollar debt. For additional information, see “Item 3. Key Information — D. Risk Factors — Foreign exchange risks may adverselyunfavorably affect our results and the U.S. dollar value of dividends payable to ADS holders.” and “Item 3. Key Information — D. Risk Factors — Fluctuations in the
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Chilean economic fluctuations, certaineconomy, economic interventionist measures by governmental authorities, as well as political and financial events, or financial or other crises in any regionChile and worldwide may affect our results of operations, financial condition, and liquidity, as well asand 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 |
| 648.51 |
| 614.75 |
| 676.19 |
| 669.47 |
|
| | | | | | | | | | | | |
| | Local Currency U.S. Dollar Exchange Rates | ||||||||||
| | 2020 | | 2019 | | 2018 | ||||||
|
| Average |
| Year End |
| Average |
| Year End |
| Average |
| Year End |
Chilean pesos per U.S. dollar | | 792.22 | | 710.95 | | 702.63 | | 748.74 | | 640.29 | | 694.77 |
Source: Central Bank of Chile
d. | 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 toregarding 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 ofto prepare the consolidated financial statements, see Notes 2 and 3 of the Notes to our consolidated financial statements.
Impairment of Long-LivedNon-Financial Assets
From time to time, and principally at the end of anyeach fiscal year, we evaluate whether there is any indication that an asset has been impaired. Should any such indicationevidence exist, we estimate the recoverable amount of that asset to determine where appropriate, the amount of impairment.impairment loss. In the case of identifiable assets that do not generate cash flows independently, we estimate the recoverability of the cash generatingcash-generating unit to which the asset belongs, which is understood to be the smallest identifiable group of assets that generatesproduces independent cash inflows.
Notwithstanding the preceding paragraph, in the case of cash generatingcash-generating units to which goodwill or intangible assets with an indefinite useful life have been allocated, a recoverability analysis is performed routinely at the end of each period end.period.
The criteria used to identify the cash-generating units are in line with our management’s strategic and operational vision, within the specific characteristics of the business, the operating rules and regulations of the market in which we operate, and the corporate organization.
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 toTo calculate the recoverable value of property, plant and equipment, goodwill, and intangible assets that form part of a cash-generating unit, we use “valuethe value in use”use criteria in nearlypractically 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,cash-generating units’ revenues and costs using sector projections, past experience, and future expectations.
In general, these projections cover the next fivethree years, estimating cash flows for future years and applying reasonable growth rates, which in no case are increasing nor exceed the average long termlong-term growth rates for the Chilean electricity sector.sector in which we operate. At the end of December 2018,2020, projected cash flows were extrapolated using an annual growth rate of 3.1%between 2.0% and 2.9%.
These future64
Future cash flows are discounted at a given pre-tax rate to calculate their present value. Thisvalue at a pre-tax rate reflectsthat covers the cost of capital offor the business activity and the geographic area in Chile.which it is carried out. The discount rate is calculated taking into account the current time value of money and the risk premiums generally used by market participantsamong analysts for the specific business activity.activity and the geographic zone are taken into account to calculate the pre-tax rate. The pre-tax discount rates, expressed in nominal terms, applied at the end of December 2020 were between 6.3% and 8.2%.
The pre-tax nominal discount rates applied in 2018, 20172020, 2019, and 20162018 are as follows:
| | | | | | | | | | | |||||||||||
Year ended December 31, | Year ended December 31, |
| Year ended December 31, | ||||||||||||||||||
2018 |
| 2017 |
| 2016 |
| ||||||||||||||||
2020 | 2020 | | 2019 | | 2018 | ||||||||||||||||
Minimum |
| Maximum |
| Minimum |
| Maximum |
| Minimum |
| Maximum |
|
| Maximum |
| Minimum |
| Maximum |
| Minimum |
| Maximum |
6.9 | % | 11.0 | % | 7.5 | % | 10.7 | % | 8.1 | % | 12.2 | % | ||||||||||
6.3% | | 8.2% | | 7.7% | | 10.7% | | 6.9% | | 11.0% |
If the recoverable amount of the cash-generating unit is less than the net carrying amount of the cash generating unit,asset, the corresponding impairment loss provision is recognized for the difference and charged to “Reversal of impairment losslosses (impairment loss)losses) 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 adjustmentimpairment loss had occurred.been recognized for the asset. Impairment adjustments tolosses for goodwill are not reversible.
Litigation and Contingencies
We are currently involved in legal and tax proceedings. As discussed in Note 25 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$ 17.416.3 billion as of December 31, 2018.2020. This amount was based on consultations with our legal and tax advisors, who are carrying out our defense in these matters and an analysis ofanalyzing potential results, assuming a combination of litigation and settlement strategies.
HedgeHedges of 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, which are accounted for as they are cash flow hedge transactions, are charged net of taxes to an equity reserve account that forms part of “OtherOther Comprehensive Income” andIncome. They are 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 confirmingto confirm 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.
Pension and Post-Employment Benefit Liabilities
We have various defined benefit plans for our employees. These plans pay benefits to employees at retirement and use formulas based on years of service and employee compensations. We also offer certain additional benefits for some specific retired employees.
The liabilities shown for the pensions and post-employment benefits reflect our best estimate of the future cost of meeting our obligations under these plans. The accounting applied to these defined benefit plans involves actuarial calculations, which contain key assumptions that include employee turnover, life expectancy, retirement age, discount rates, the future level of employee compensations and benefits, the claims rate under medical plans, and future medical costs. These assumptions change as economic and market conditions vary, and any change in any of these assumptions could have a material effect on the reported results from operations.
65
The effect of an increase of 100 basis points in the discount rate used to determine the present value of the post-employment defined benefits would decrease the liability by Ch$ 4.35.6 billion, and Ch$ 5.3 billion, as of December 31, 20182020, and 2017, and the2019, respectively. The effect of a decrease of 100 basis points in the rate used to determine the present value of the post-employment defined benefits would increase the liability by Ch$ 4.86.1 billion, and Ch$ 5.8 billion as of December 31, 20182020, and 2017.2019, respectively.
.
Revenue and expense recognition
Revenue is recognized when the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which it is expected to be entitled upon the transfer of control, excluding the amounts collected on behalf of third parties.
We analyze and consider all relevant facts and circumstances for revenue recognition, applying the five-step model established by IFRS 15: 1) identifying the contract with a customer; 2) identifying the performance obligations; 3) determining the transaction price; 4) allocating the transaction price; and 5) recognizing revenue.
The following are the criteria for revenue recognition by type of good or service that we provide:
● | Electricity supply (sale and transportation): Corresponds to a single performance obligation that transfers to the customer several different goods or services that are substantially the same and have the same transfer pattern. Since the customer receives and simultaneously consumes the benefits that we provide, it is considered a performance obligation met over time. In these cases, we apply an output method to recognize revenue in the amount to which it is entitled to bill for electricity supplied to date. |
● | Generation: Revenue is recognized according to the physical deliveries of energy and power, at the prices established in the respective contracts, at the prices stipulated in the electricity market by the current regulations, or at the marginal cost of energy and power, depending on whether unregulated customers, regulated customers, or energy trading in the spot market are involved, respectively. |
● | Distribution of electricity: Revenue is recognized based on the amount of energy supplied to customers during the period, at prices established in the respective contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate. |
These revenues include an estimate of the service provided and not invoiced as of the balance sheet date. See Notes 2.3, 28, and Appendix 2.2 of our consolidated financial statements.
● | Sale and transportation of gas: Revenue is recognized over time, based on the actual physical deliveries of gas in the period of consumption, at the prices established in the respective contracts. |
● | Other services: Mainly the provision of supplementary services to the electricity business, construction of works and engineering, and consulting services. Customers control committed assets as they are created or improved. Therefore, we recognize this revenue over time based on progress, measuring progress through output methods (performance completed to date, milestones reached, etc.) or resource methods (resources consumed, hours of labor spent, etc.), as appropriate in each case. |
● | Sale of goods: Revenue from the sale of goods is recognized at a particular time when control of the goods has been transferred to the client, which generally occurs at the time of the physical delivery of the goods. Revenues are measured at the independent sale price of each good and any type of appropriate variable compensation. |
In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance obligations of the transaction, based on the control transfer pattern of each good or service that is separate and an independent selling price allocated to each of them, or two or more transactions jointly,
66
when these are linked to contracts with customers that are negotiated with a single commercial purpose and the goods and services committed represent a single performance obligation, and their selling prices are not independent.
We determine the existence of significant financing components in its contracts, adjusting the value of the consideration if applicable and reflecting the effects of the time value of money. However, we apply the practical solution provided by IFRS 15. We will not adjust the amount of the consideration committed for a significant financing component if we expect, at the beginning of the contract, that the period between the payment and the transfer of goods or service to the customer is one year or less.
We exclude the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue figure. We only record as revenue the payment or commission to which we expect to be entitled.
Given that we mainly recognize revenue for the amount to which we have the right to invoice, we have decided to apply the practical disclosure solution provided in IFRS 15, through which we are not required to disclose the aggregate amount of the transaction price allocated to the obligations of performance not met (or partially not met) at the end of the reporting period.
Also, we evaluate the existence of incremental costs of obtaining a contract and costs directly related to the fulfillment of a contract. These costs are recognized as an asset if their recovery is expected with the transfer of the related goods or services and amortized in a manner consistent with the transfer of the related goods or services. The incremental costs of obtaining a contract are recognized as an expense if the depreciation period of the asset that has been recognized is one year or less. Costs that do not qualify for capitalization are recognized as expenses incurred unless they are explicitly attributable to the customer.
As of December 31, 2020, and 2019, we had not incurred costs to obtain or fulfill a contract that met the conditions for such capitalization. The expenses incurred to gain a contract are substantially commission payments for sales that, even though they are incremental costs, are related to short-term contracts or performance obligations met at a particular time. Therefore, we would recognize these costs as an expense if they occurred.
Interest revenue (expenses) are recorded considering the effective interest rate applicable to the principal with pending amortization during the corresponding accrual period.
Impairment of financial assets
Under IFRS 9 Financial Instruments, we apply an impairment model based on expected credit losses based on our history, existing market conditions, and prospective estimates at the end of each reporting period. The new impairment model is applied to financial assets measured at amortized cost or fair value through other comprehensive income, except for investments in equity instruments.
The expected credit loss, determined considering Probability of Default (PD), Loss Given Default (LGD), and Exposure at Default (EAD), is the difference between all cash flows that are owed under the contract and all the cash flows that are expected to be received (that is, all cash deficiencies), discounted at the original effective interest rate.
To determine the expected credit losses, we apply two separate approaches:
● | General approach: Applied to financial assets other than trade accounts receivable, contractual assets, or lease receivables. This approach is based on evaluating significant increases in the credit risk of financial assets from the date of initial recognition. If the credit risk has not increased significantly on the date of issuance of the financial statements, the impairment losses are measured by reference to the expected credit losses in the next 12 months. If, on the other hand, the credit risk has increased significantly, the impairment is measured considering the expected credit losses for the lifetime of the asset. In general, the measurement of expected credit losses under the general approach is performed individually. |
67
● | Simplified approach: Applied to trade receivables, contract assets, and lease receivables. The impairment provision is consistently recognized by reference to the expected credit losses for the asset’s lifetime. This approach is most commonly applied because trade receivables represent the principal financial asset of Enel Chile and our subsidiaries. |
For trade accounts receivable, contractual assets, and accounts receivable for lease, we apply two types of evaluations of expected credit losses:
● | Collective evaluation: Based on grouping accounts receivable into specific groups or “clusters,” considering each business and the local regulatory context. Accounts receivable are grouped according to the characteristics of client portfolios in terms of credit risk, maturity information, and recovery rates. A specific definition of default is considered for each group. |
● | Analytical or individual evaluation: If accounts receivable are considered individually significant by management, and there is specific information on any significant increase in credit risk, we apply an individual evaluation of accounts receivable. For the individual evaluation, the PD is generally obtained from an external provider. |
Based on the reference market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for such accounts receivable, we mainly apply a default definition of 180 days after maturity to determine the expected credit losses, since this is considered an effective indicator of a significant increase in credit risk.
To measure the expected credit losses collectively, we consider the following assumptions:
● | PD: average default estimate, calculated for each group of trade accounts receivable, taking into account a minimum of 24-month historical data; |
● | LGD: calculated based on the recovery rates of a predetermined section, discounted at the effective interest rate; and |
● | EAD: accounting exposure on the date of the financial report, net of cash deposits, including invoices issued but not due, and invoices to be issued. |
The prospective adjustment can be applied based on specific management evaluations, considering qualitative and quantitative information to reflect possible future events and macroeconomic scenarios affecting the portfolio risk or the financial instrument.
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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, 2020, and 2019 |
2.Analysis of Results of Operations for the Years Ended December 31, 2018 and 2017
Consolidated Revenues and other operating income
The following table sets forth our revenues and other operating income by reportable segment for the years ended December 31, 20182020, and 2017:2019:
|
| Years ended December 31, |
| ||||||
|
| 2018 |
| 2017 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in %) |
| ||||
Generation Business |
|
|
|
|
|
|
|
|
|
Enel Generation, EGP Chile and subsidiaries |
| 1,580,653 |
| 1,634,937 |
| (54,284 | ) | (3.3 | ) |
Distribution Business |
|
|
|
|
|
|
|
|
|
Enel Distribution and subsidiaries |
| 1,263,224 |
| 1,326,659 |
| (63,435 | ) | (4.8 | ) |
Non-electricity business and consolidation adjustments |
| (386,716 | ) | (438,618 | ) | 51,902 |
| (11.8 | ) |
Total Revenues and other operating income |
| 2,457,161 |
| 2,522,978 |
| (65,817 | ) | (2.6 | ) |
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change |
| Change |
| | (in millions of Ch$) | | (in %) | ||||
Generation Business | | | | | | | | |
Enel Generation, EGP Chile, and subsidiaries | | 1,577,422 | | 1,726,612 | | (149,189) | | (8.6) |
Distribution Business | | | | | | | | |
Enel Distribution and subsidiaries | | 1,382,068 | | 1,412,872 | | (30,804) | | (2.2) |
Non-electricity business and consolidation adjustments | | (374,088) | | (368,650) | | (5,438) | | (1.5) |
Total Revenues and Other Operating Income (Loss) | | 2,585,402 | | 2,770,834 | | (185,432) | | (6.7) |
Generation Business: Revenues and other operating income
Revenues and other operating income from our generation business (which include EGP Chile salesdecreased Ch$ 149.2 billion, or 8.6%, in 2020 compared to 2019, explained by:
a. | Ch$ 121.1 billion associated with non-recurring income recorded in 2019 due to the early termination of three energy supply contracts with Anglo American Sur, partially offset by |
b. | Ch$ 7.7 billion in higher revenues from temporary facility rentals. |
a. Ch$ 29.1 billion of lower capacity payments;
b. 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; and
c. Ch$ 11 billion associated with the lower average energy sales price in Chilean pesosmainly due to the lower average exchange rate of the period, partially offset by higher physical sales of Ch$ 32.9 billion as a result of an 8%gas sales.
The decrease in sales to regulated clients;our generation business revenues and
(ii) Ch$ 35.4 billion of lower toll revenues;
all of which other operating income was partially offset byby:
a) | Ch$ 53.2 billion, due to higher prices caused by the depreciation of the Chilean peso against the U.S. dollar; |
b) | Ch$ 23.1 billion from ancillary services related to service quality and safety; and |
c) | Ch$ 10.7 billion from commodity hedging; partially offset by: |
d) | Ch$ 65.4 billion in physical net sales for 554 GWh, explained by 1,874 GWh from lower regulated customers partially offset by 1,141 GWh from unregulated customers and 179 GWh from the spot market, related primarily to customer migration and the lockdowns declared in the country’s urban areas due to the Covid-19 pandemic. |
69
Distribution Business: Revenues and other operating income
Revenues and other operating income from our distribution business decreased Ch$ 30.8 billion, or 2.2%, in 20182020 compared to 2017,2019, primarily due to:
(i) | Ch$ 48.2 billion in lower energy sales, primarily as the result of 654 GWh in lower physical energy sales, equivalent to Ch$ 50.3 billion, mainly from commercial and industrial customers, particularly during the second and third quarters of 2020 because of the lockdowns as a consequence of the Covid-19 pandemic. This decrease was partially offset by a higher average sales price as a consequence of a Ch$ 2.1 billion positive exchange rate effect; and |
(ii) | Ch$ 2.8 billion in other sales mainly due to (i) Ch$ 2.1 billion in lower income from a non-recurring sale of retail materials to Enel X Chile recorded in 2019 and (ii) Ch$ 0.7 billion in lower non-regulated business services revenues, such as the relocation of customer connections and networks. |
(i) a Ch$ 60.9 billion reductionThe decrease in our distribution business revenues and other services revenues, namely lower revenues from transmission tolls as a result of the new zonal transmission decree, and
(ii) Ch$ 10.3 billion of lower energy sales revenues mainly as a consequence of a Ch$ 33.7 billion decrease due to lower average sales prices resulting from the transfer of lower purchase prices, whichoperating income was partially offset by higher physical sales of 345 GWh equivalent to Ch$ 23.4 billion. These lower revenues were compensated by Ch$ 4 billion of higher products and services sales.of:
(iii) | Ch$ 18.8 billion from other services, mainly due to (i) Ch$ 11.4 billion in higher transmission tolls in the zonal transmission segment and (ii) Ch$ 7.4 billion from the construction of customer connections; and |
(iv) | Ch$ 1.4 billion in other operating revenues, mainly from insurance claims. |
The number of customers rose by 42,59035,802, or 1.8%, in 2018 compared2020 to 2017, totaling 1,924,984,a total of 2,008,018. The increase in customers was mainly newfrom residential and commercial customers.
Consolidated Operating Costs
Our operating costs are primarily energy purchases from third parties, fuel purchases,consumption, tolls paid to transmission companies, depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses.
The following two tables set forth the consolidated operating costs (excluding sellingdepreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative expenses)and selling expenses, which are discussed below under Consolidated Selling and Administrative Expenses) for the years ended December 31, 2018,2020, and 2017,2019, by category and by business segment.
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|
| Years ended December 31, |
| ||||||
|
| 2018 |
| 2017 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in %) |
| ||||
Energy purchases |
| 747,647 |
| 902,435 |
| (154,788 | ) | (17.2 | ) |
Fuel consumption |
| 231,028 |
| 280,739 |
| (49,711 | ) | (17.7 | ) |
Other variable procurement and services |
| 146,627 |
| 175,733 |
| (29,107 | ) | (16.6 | ) |
Transmission costs |
| 166,876 |
| 155,879 |
| 10,997 |
| 7.1 |
|
Total Consolidated Operating Costs |
| 1,292,177 |
| 1,514,787 |
| (222,610 | ) | (14.7 | ) |
|
| Years ended December 31, |
| ||||||
|
| 2018 |
| 2017 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in %) |
| ||||
Generation Business |
|
|
|
|
|
|
|
|
|
Enel Generation, EGP Chile and subsidiaries |
| 709,506 |
| 903,978 |
| (194,472 | ) | (21.5 | ) |
Distribution Business |
|
|
|
|
|
|
|
|
|
Enel Distribution and subsidiaries |
| 972,500 |
| 1,055,708 |
| (83,208 | ) | (7.9 | ) |
Non-electricity business and consolidation adjustments |
| (389,829 | ) | (444,899 | ) | 55,070 |
| (12.4 | ) |
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses) |
| 1,292,177 |
| 1,514,787 |
| (222,610 | ) | (14.7 | ) |
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change |
| Change |
| | (in millions of Ch$) | | (in %) | ||||
Energy purchases | | 864,863 | | 835,285 | | 29,579 | | 3.5 |
Fuel consumption | | 231,176 | | 230,944 | | 232 | | 0.1 |
Transmission costs | | 141,540 | | 196,849 | | (55,309) | | (28.1) |
Other variable procurement and services | | 136,866 | | 158,127 | | (21,261) | | (13.4) |
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses) | | 1,374,446 | | 1,421,205 | | (46,760) | | (3.3) |
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change |
| Change |
| | (in millions of Ch$) | | (in %) | ||||
Generation Business | | | | | | | | |
Enel Generation, EGP Chile, and subsidiaries | | 616,852 | | 678,188 | | (61,335) | | (9.0) |
Distribution Business | | | | | | | | |
Enel Distribution and subsidiaries | | 1,116,324 | | 1,114,936 | | 1,388 | | 0.1 |
Non-electricity business and consolidation adjustments | | (358,731) | | (371,919) | | 13,187 | | 3.5 |
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses) | | 1,374,446 | | 1,421,205 | | (46,760) | | (3.3) |
Generation Business: Operating Costs
Operating costs of our generation business decreased Ch$ 61.3 billion, or 9.0%, in 20182020 compared to 2017,2019, mainly due to:
·
1) | a decrease of Ch$ 55.4 billion, mainly explained by: |
· a Ch$ 49.7 billion decrease in fuel costs,lower transmission tolls primarily due to (i) Ch$ 30.542 billion in a lower electricity transmission charge (“CET” in its Spanish acronym) that is a component of the toll for feeding electricity into the national transmission system and (ii) Ch$ 18.1 billion in a lower cost of the zonal transmission system’s AAT (Spanish acronym for harmonization adjustment tariff); and
2) | a decrease of Ch$ 23.2 billion in other variable procurement and services, mainly due to lower costs of: |
· a Ch$ 12.1 billionThe decrease in other variable procurement and servicesour generation business operating costs which in turn was mostly attributable to (i) Ch$ 8.3 billion of lower costs related to the lease agreement with Eléctrica Santiago S.A., an unrelated company, to use its Nueva Renca combined-cycle power plant, allowing us to use our available LNG; (ii) Ch$ 3.7 billion of lower thermal emissions taxes; (iii) Ch$ 1.7 billion of lower commodity derivative costs; and (iv) Ch$ 1.1 billion of lower water consumption costs. These cost decreases were partlypartially offset by Ch$ 4.8 billion of higher costs in the gas commercialization business.of:
71
3) | Ch$ 17.0 billion in energy purchases, mainly explained by higher physical purchases in the spot market (1,425 GWh) due to (a) lower hydroelectric generation (866 GWh) as a result of the country’s hydrological conditions and (b) lower thermal dispatch (780 GWh) primarily related to lower coal-fired electricity generation; and |
4) | Ch$ 0.2 billion in fuel consumption primarily due to (a) Ch$ 23.7 billion in higher commodity hedging; (b) Ch$ 21.2 billion and Ch$ 0.3 billion in impairment losses on coal inventories and on diesel oil inventories, respectively, accounted for in the second quarter of 2020, due to the process to cease the operations of Bocamina II; (c) Ch$ 8.0 billion in gas consumption related to higher gas-fired electricity generation despite lower gas purchase prices; and (d) Ch$ 2.4 billion in fuel oil consumption, partly offset by Ch$ 56 billion in coal consumption related to lower coal-fired thermal generation and lower coal purchase prices during the period. |
Distribution Business: Operating Costs
Operating costs of our distribution business decreasedincreased slightly by Ch$ 1.4 billion in 20182020 compared to 2017,2019, mainly due to (i) Ch$ 53.2 billion ofto:
1) | Ch$ 3.9 billion in energy purchases largely explained by Ch$ 48.2 billion from a higher purchase price, partially offset by Ch$ 44 billion in lower physical purchases (759 GWh) during the period; and |
2) | Ch$ 0.9 billion in transportation costs due to higher zonal transmission toll payments to electricity distribution and transmission companies. |
The increase in our distribution business operating costs as a consequence of the new zonal transmisional decree; (ii) Ch$ 11.7 billion of lower energy purchases mainly attributable to a Ch$ 30.3 billion decrease due to lower average energy purchase prices, as a result of changes in node prices and lower surcharges homogenizing tariffs nationwide,was partially offset by Ch$ 18.6 billion in higher physical purchases required to satisfy demand; and (iii) Ch$ 18.3 billion in lower variable procurement and services costs, primarily for fines and compensations derived from extraordinary weather events that occurred in 2017, an insurance recovery in 2018, and other businesses such as meter rentals and street lighting services.by:
3) | Ch$ 3.5 billion in lower other variable procurement and services, explained by (a) Ch$ 2.1 billion from the non-recurring sale of retail materials to Enel X Chile recorded in 2019 and (b) Ch$ 1.5 billion in other costs, mainly related to emergency plans. |
Consolidated Selling and Administrative Expenses
Our selling and administrative expenses are salaries and other compensation administrative expenses, depreciation, amortization and impairment losses, and office materials and supplies, assupplies.
The following two tables set forth inour selling and administrative expenses for the following two tables:years ended December 31, 2020, and 2019, by category and by business segment:
72
Table of Contents Years ended December 31, 2018 2017 Change Change (in millions of Ch$) (in%) Depreciation, amortization and impairment losses 220,750 160,621 60,129 37.4 Other fixed costs 167,210 161,824 5,386 3.3 Employee benefit expense and others 106,419 107,115 (695 ) (0.6 ) Total Consolidated Selling and Administrative Expenses 494,380 429,560 64,820 15.1
|
| Years ended December 31, |
| ||||||
|
| 2018 |
| 2017 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Generation Business |
|
|
|
|
|
|
|
|
|
Enel Generation, EGP Chile and subsidiaries |
| 337,527 |
| 267,099 |
| 70,428 |
| 26.4 |
|
Distribution Business |
|
|
|
|
|
|
|
|
|
Enel Distribution and subsidiaries |
| 131,465 |
| 138,441 |
| (6,976 | ) | (5.0 | ) |
Non-electricity business and consolidation adjustments |
| 25,388 |
| 24,020 |
| 1,368 |
| 5.7. |
|
Total Consolidated Selling and Administrative Expenses |
| 494,380 |
| 429,560 |
| 64,820 |
| 15.1 |
|
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change |
| Change |
| | (in millions of Ch$) | | (in %) | ||||
Depreciation, amortization, and impairment losses | | 942,931 | | 527,437 | | 415,494 | | 78.8 |
Other fixed costs | | 190,593 | | 184,143 | | 6,450 | | 3.5 |
Employee benefit expenses and others | | 111,687 | | 111,994 | | (307) | | (0.3) |
Total Consolidated Selling and Administrative Expenses | | 1,245,212 | | 823,574 | | 421,638 | | 51.2 |
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change |
| Change |
| | (in millions of Ch$) | | (in %) | ||||
Generation Business | | | | | | | | |
Enel Generation, EGP Chile, and subsidiaries | | 1,056,586 | | 652,489 | | 404,098 | | 61.9 |
Distribution Business | | | | | | | | |
Enel Distribution and subsidiaries | | 165,855 | | 145,642 | | 20,213 | | 13.9 |
Non-electricity business and consolidation adjustments | | 22,771 | | 25,443 | | (2,673) | | (10.5) |
Total Consolidated Selling and Administrative Expenses | | 1,245,212 | | 823,574 | | 421,638 | | 51.2 |
Consolidated selling and administrative expenses from continuing operations increased Ch$ 421.6 billion in 20182020 compared to 2017,2019, mainly due to an increase in the generation business. Thea Ch$ 404.1 million increase in the generation business, is mainly explained by the inclusion of the depreciation of EGP Chile that amounted to Ch$ 62.1 billion.by:
(i) | an increase of Ch$ 415.5 billion in depreciation, amortization, and impairment costs in 2020 compared to 2019, mainly due to: |
a) | Ch$ 407.3 billion in the generation business segment, due to Ch$ 417.8 billion from Enel Generation as a result of the Ch$ 697.9 billion impairment recognized in 2020 related to accelerated schedule for the closure of the Bocamina II coal-fired power plant, compared to the impairment recognized in 2019 related to the announcement of the closures of the Tarapacá and Bocamina I coal-fired power plants, all of this as a result of the announced closure as part of our decarbonization process. This effect was partially offset by a decrease of Ch$ 11.1 billion, explained by Ch$ 21 billion in lower Enel Generation expenses primarily related to the depreciation of the coal-fired power plants impaired in 2019 and 2020, offset by Ch$ 10.3 billion in EGP Chile depreciation, mainly due to exchange rate effects; and |
b) | Ch$ 9.7 billion in the distribution business segment, mainly due to (i) Ch$ 4.9 billion in impairment expense of trade accounts receivable related to higher commercial debt partly caused by the Covid-19 pandemic; (ii) Ch$ 2.6 billion in intangible amortization related to software; and (iii) Ch$ 1.9 billion in fixed asset depreciation due to an increase in the transfer of assets to operations in connection with optimizing distribution network infrastructure to improve efficiency and quality of service. |
(ii) | Ch$ 6.5 billion in other fixed costs, mainly due to (i) higher technical support and administrative services and (ii) higher operation and maintenance costs related to customer service (call center and meter reading), maintenance, and repairs. |
Selling and administrative expenses in our distribution business decreased in 2018 compared to 2017, primarily due to Ch$ 5.9 billion in payroll expenses associated with extraordinary employee bonuses given to employees during 2017.
Consolidated Operating Income
The following table sets forth our operating income by reportable segment for the years ended December 31, 20182020, and 2017:2019:
|
| Years ended December 31, |
| ||||||
|
| 2018 |
| 2017 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Generation Business |
|
|
|
|
|
|
|
|
|
Enel Generation, EGP Chile and subsidiaries |
| 533,620 |
| 463,860 |
| 69,760 |
| 15.0 |
|
Distribution Business |
|
|
|
|
|
|
|
|
|
Enel Distribution and subsidiaries |
| 159,259 |
| 132,510 |
| 26,749 |
| 20.2 |
|
Non-electricity business and consolidation adjustments |
| (22,275 | ) | (17,740 | ) | (4,535 | ) | 25.6 |
|
Total Consolidated Operating Income |
| 670,605 |
| 578,631 |
| 91,974 |
| 15.9 |
|
Operating margin (1) |
| 27.3 | % | 22.9 | % | — |
| — |
|
73
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
Generation Business | | | | | | | | |
Enel Generation, EGP Chile, and subsidiaries | | (96,017) | | 395,935 | | (491,952) | | (124.3) |
Distribution Business | | | | | | | | |
Enel Distribution and subsidiaries | | 99,889 | | 152,294 | | (52,405) | | (34.4) |
Non-electricity business and consolidation adjustments | | (38,128) | | (22,174) | | (15,954) | | (72.0) |
Total Consolidated Operating (Loss) / Income | | (34,255) | | 526,055 | | (560,310) | | (106.5) |
Operating margin(1) | | (1.3)% | | 19.0% | | — | | — |
(1) Operating margin, a measure of efficiency, represents income as a percentage of revenues.
(1) | Operating margin, a measure of efficiency, represents operating income as a percentage of revenues. However, caution must be applied in making comparisons among periods, which may have experienced non-recurring gains or losses, as was the case in 2020 and 2019 with the expense related to the closure of two coal-fired power plants. |
Our operating income in 2018 increased2020 decreased compared to 20172019 due to the combinationfollowing:
Generation Business
Revenues totaled Ch$ 1.6 trillion as of the following:
· Hydrological conditions in Chile have been below the historical average since 2010. However, in 2018 hydrological conditions were more humid than in 2017. This allowed us to produce more electricity through hydroelectric generation rather than through thermal generation, which is more expensive. In addition, the commissioning of new NCRE plants reduced the impact of dry conditions and the interconnection between the SIC and SING also helps to reduce or stabilize marginal costs. Therefore, the marginal cost of electricity generation decreased in 2018 when compared to 2017 notwithstanding higher prices for our fuels. As a result, we were able to cover our energy deficit in the spot market at lower prices. While our physical sales increased when compared to 2017, they were at lower average sales prices, and our customer mix changed because during 2018 a portion of our regulated customers chose the unregulated tariff regime instead, all of which led toDecember 31, 2020, a decrease of our consolidated revenues. However,8.6%, mainly due to the incorporationincome generated in March 2019 from the early termination of EGP Chile, our operatingthe contracts with Anglo American Sur, and lower sales from gas commercialization, partially offset by higher energy sales associated with a positive effect on the average sales price expressed in Chilean pesos.
The costs (mainly energy purchases) considerably decreasedtotaled Ch$ 617 billion as of December 31, 2020, a decrease of 9.0% compared to 2019, resulting from lower transportation expenses and lower other variable procurement and services costs.
Operating income was affected by the impairment of the Bocamina II coal-fired generating unit recognized in 2018, which compensated2020, compared to the impairment recognized in 2019 related to the announcement of the closures of the Tarapacá and Bocamina I coal-fired power plants, partially offset by lower depreciation and amortization expense, primarily associated with the lower revenuesdepreciation of the impaired coal-fired plants in 2019 and 2020.
Distribution Business
Revenues were Ch$ 1.4 trillion as of December 31, 2020, a decrease of 2.2% compared to 2019, mainly due to lower energy sales. Physical sales were 16,481 GWh as of December 31, 2020, reflecting a decline of 3.8% compared to 2019, mainly due to lower sales in the commercial and industrial segments primarily associated with quarantines imposed in the Santiago metropolitan region during the Covid-19 pandemic.
The costs remained stable at Ch$ 1.1 trillion as of December 31, 2020.
Operating income was mainly affected by (i) a higher impairment loss on trade receivables due to higher trade debt, primarily as a result of the Covid-19 pandemic; (ii) higher amortization of intangibles due to IT developments; and (iii) a higher depreciation of fixed assets due to an increase in our sellingthe transfer of assets to operations in connection with optimizing distribution network infrastructure to improve efficiency and administrative expenses, also due to the inclusionquality of EGP Chile.
· In the distribution business, although our revenues decreased in 2018 when compared to 2017, our operating costs also significantly decreased when compared to 2017, due primarily to the weather emergencies we faced in 2017, and to a lesser degree, lower selling and administrative expenses. As a result, our distribution business operating income increased in 2018.service.
Consolidated Financial and Other Results
The following table sets forth our financial and other results for the years ended December 31, 20182020, and 2017:2019:
74
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
Financial results | | | | | | | | |
Financial income | | 36,160 | | 27,399 | | 8,761 | | 32.0 |
Financial costs | | (127,409) | | (164,898) | | 37,489 | | 22.7 |
Gain (loss) from indexed assets and liabilities | | 2,086 | | (2,982) | | 5,068 | | 169.9 |
Foreign currency exchange differences | | (23,272) | | (10,412) | | (12,860) | | (123.5) |
Total financial results | | (112,435) | | (150,893) | | 38,458 | | 25.5 |
Other Results | | | | | | | | |
Share of the profit (loss) of associates and joint ventures accounted for using the equity method | | 3,509 | | 366 | | 3,143 | | 858.6 |
Other gains (losses) | | 9,489 | | 1,793 | | 7,696 | | 429.2 |
Total Other results | | 12,998 | | 2,159 | | 10,839 | | 502.0 |
Total Consolidated Financial and Other Results | | (99,437) | | (148,734) | | 49,297 | | 33.1 |
|
| Years ended December 31, |
| ||||||
|
| 2018 |
| 2017 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Financial results |
|
|
|
|
|
|
|
|
|
Financial income |
| 19,934 |
| 21,663 |
| (1,729 | ) | (8.0 | ) |
Financial costs |
| (122,184 | ) | (53,511 | ) | (68,673 | ) | 128.3 |
|
Gain from indexed assets and liabilities |
| (818 | ) | 916 |
| (1,734 | ) | (189.3 | ) |
Foreign currency exchange differences |
| (7,807 | ) | 8,517 |
| (16,324 | ) | (191.7 | ) |
Total financial results |
| (110,875 | ) | (22,415 | ) | (88,460 | ) | 394.7 |
|
Other Results |
|
|
|
|
|
|
|
|
|
Share of the profit (loss) of associates and joint ventures accounted for using the equity method |
| 3,190 |
| (2,697 | ) | 5,887 |
| (218.3 | ) |
Gain from sales of assets |
| 3,411 |
| 113,241 |
| (109,830 | ) | (97.0 | ) |
Total Other results |
| 6,601 |
| 110,544 |
| (103,943 | ) | (94.0 | ) |
Total Consolidated Financial and Other Results |
| (104,274 | ) | 88,129 |
| (192,403 | ) | (218.3 | ) |
Financial Results
We recorded a higherlower net financial expense for the year ended December 31, 20182020, compared to 2017. This is2019, primarily attributable to (i) higher financial costs mainly due to higher interest on bank loans and bonds amounting to Ch$ 37 billion mainly related to our new debt to finance the 2018 Reorganization, plus higher interest expense related to the consolidationto:
(i) | a decrease of Ch$ 37.5 billion in financial costs, mainly due to: |
a) | Ch$ 23.8 billion from capitalized interest primarily related to the development of NCRE projects and greater continuity in the development of the Los Cóndores project, despite the Covid-19 pandemic; |
b) | Ch$ 14.5 billion related to the Tariff Stabilization Law, mainly explained by higher expenses recognized during the fourth quarter of 2019 when the law was implemented; and |
c) | Ch$ 7.3 billion in interest on bank loans, primarily due to the amortization of Enel Chile debt totaling Ch$ 213.8 billion and EGP Chile debt for Ch$ 187.4 billion; partially offset by |
d) | Ch$ 7.7 billion in higher interest on derivative contracts. |
(ii) | an increase of Ch$ 8.8 billion in financial income, mainly Ch$ 10.1 billion related to the Tariff Stabilization Law amounting, of which Ch$ 9.8 billion represents the impact of changes to the technical provisions established to implement such law determined by the CNE through Exempt Resolution No. 340, issued in September 2020, which was partially offset by Ch$ 1.7 billion in lower income on short-term fixed income investments. |
(iii) | an increase of Ch$ 5.1 billion in gains related to indexation of assets and liabilities primarily due to: |
a) | Ch$ 3.2 billion in lower indexation losses related to IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch of our subsidiary Enel Generation located in Argentina; and |
b) | Ch$ 1.9 billion from indexed financial instruments and derivatives. |
(iv) | an increase of Ch$ 12.9 billion in losses from exchange rate differences, mainly due to negative exchange rate effects arising from: |
a) | Ch$ 26.3 billion in trade account receivables, including a Ch$ 36.5 billion negative effect related to the Tariff Stabilization Law that set the U.S. dollar as the currency for the accounts receivables of pending billings to regulated customers; |
75
b) | Ch$ 3.4 billion in trade account payables, including the Ch$ 11.2 billion positive effect related to the Tariff Stabilization Law; and |
c) | Ch$ 2.1 billion in financial debt and derivatives; partially offset by |
d) | the favorable exchange rate difference effect on (i) cash and cash equivalents for Ch$ 11.0 billion and (ii) other financial assets and liabilities for Ch$ 7.9 billion. |
Other Results
Our gain from the disposition of assets decreasedincreased Ch$ 7.9 billion in 20182020 compared to 2017, primarily2019, mainly explained by the sale of Electrogas in February 2017the Quintero-San Luis transmission line for Ch$ 105.3 billion.9.4 billion in December 31, 2020, compared to net income from the sale of a gas turbine to the related company Enel Generación Costanera for Ch$ 1.3 billion recognized in 2019.
We also registered a higheran increase of Ch$ 3.1 billion in the share of the profit (loss) of associates and joint ventures accounted forrecognized using the equity method in 20182020 when compared to 2017, mainly explained by better results from HidroAysén amounting to Ch$ 5.9 billion until its liquidation.2019.
Consolidated Income Tax Expenses
The effective tax rate was an income tax benefit of 60.8% in 2020 compared to an income tax expense of 16.2% in 2019.
Consolidated income tax expenses totaledbenefit increased Ch$ 153.5142.5 billion in 2018, an increase of Ch$ 10.1 billion, or 7.1%, when2020 compared to 2017.2019. This is mainly due to:
(1) | Ch$ 112.8 billion in higher income tax benefit due to the higher impairment loss recognized in 2020 as a result of our decarbonization plan; |
(2) | Ch$ 33.7 billion in higher income tax benefit related to Enel Generation’s fixed-asset goodwill recognized in 2020, resulting from the merger of GasAtacama Chile in 2019; and |
(3) | Ch$ 32.7 billion in lower income tax expense, due to non-recurring revenues as a result of the income generated in 2019 by the early termination of three energy supply contracts with Anglo American Sur. |
The increase in consolidatedour income tax expensesbenefit was primarily due to an increase ofpartially offset by the statutory tax rate from 25.5% in 2017 to 27% in 2018 leading to Ch$ 8.5 billion in higher taxes. As a result, the effective tax rate increased to 27.1% in 2018 compared to 21.5% in 2017. non-recurrence of:
(4) | Ch$ 29.3 billion in income tax benefit in 2019, resulting from the goodwill recognized due to the absorption of GasAtacama Argentina by GasAtacama Chile. |
For further details, please refer to Note 2019 of the Notes to our consolidated financial statements.
Consolidated Net Income
The following table sets forth our consolidated net income before taxes, income tax expenses, and net income for the years ended December 31, 20182020, and 2017:2019:
|
| Years ended December 31, |
| ||||||
|
| 2018 |
| 2017 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Operating income |
| 670,605 |
| 578,631 |
| 91,974 |
| 15.9 |
|
Other results |
| (104,274 | ) | 88,129 |
| (192,403 | ) | (218.3 | ) |
Net income before taxes |
| 566,330 |
| 666,760 |
| (100,430 | ) | (15.1 | ) |
Income tax expenses |
| (153,482 | ) | (143,342 | ) | (10,140 | ) | 7.1 |
|
Consolidated Net income |
| 412,848 |
| 523,418 |
| (110,570 | ) | (21.1 | ) |
Net income attributable to the Parent Company |
| 361,710 |
| 349,383 |
| 12,327 |
| 3.5 |
|
Net income attributable to non-controlling interests |
| 51,138 |
| 174,035 |
| (122,897 | ) | (70.6 | ) |
76
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2020 |
| 2019 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
Operating income (loss) | | (34,255) | | 526,055 | | (560,310) | | (106.5) |
Other results | | (99,437) | | (148,734) | | 49,297 | | 33.1 |
Net (Loss) / Income before Taxes | | (133,692) | | 377,321 | | (511,013) | | (135.4) |
Income tax (expenses) / benefit | | 81,305 | | (61,228) | | 142,533 | | 232.8 |
Consolidated Net (Loss) / Income | | (52,387) | | 316,093 | | (368,480) | | (116.6) |
Net income attributable to the Parent Company | | (50,860) | | 296,154 | | (347,014) | | (117.2) |
Net income attributable to non-controlling interests | | (1,527) | | 19,939 | | (21,465) | | (107.7) |
The decrease in net income attributable to non-controlling interests in 2018 compared to 2017 is primarily due to the Ch$ 124.6 billion decrease of netNet income attributable to the non-controlling interestsParent Company decreased Ch$ 347 billion in 2020 compared to 2019, mainly explained by an increase in impairment expense associated with the accelerated schedule for the Bocamina II coal-fired power plant closure as part of the decarbonization process and the income in 2019 from the early termination of three contracts signed in 2016 between Enel Generation for 2018, which in turn is mainly due to the decrease of percentage of minority shareholders of Enel Generation as a result of our increase controlling and economic interest in Enel Generation after the completion of the 2018 Reorganization.Anglo American Sur.
3. Analysis of Results of Operations for the Years Ended December 31, 20172019 and 20162018
Consolidated Revenues and other operating income
The following table sets forth our revenues and other operating income by reportable segment for the years ended December 31, 20172019, and 2016:2018:
| | | | | | | | | |||||||||
| | Years ended December 31, | |||||||||||||||
|
| 2019 |
| 2018 |
| Change | | Change | |||||||||
|
| Years ended December 31, |
| ||||||||||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
| ||||||||
|
| (in millions of Ch$) |
| (in%) |
| ||||||||||||
| | (in millions of Ch$) | | (in %) | |||||||||||||
Generation Business |
|
|
|
|
|
|
|
|
| | | | | | | | |
Enel Generation and subsidiaries |
| 1,634,937 |
| 1,659,727 |
| (24,790 | ) | (1.5 | ) | ||||||||
Enel Generation, EGP Chile, and subsidiaries | | 1,726,612 | | 1,580,653 | | 145,958 | | 9.2 | |||||||||
Distribution Business |
|
|
|
|
|
|
|
|
| | | | | | | | |
Enel Distribution and subsidiaries |
| 1,326,659 |
| 1,315,761 |
| 10,898 |
| 0.8 |
| | 1,412,872 | | 1,263,224 | | 149,648 | | 11.8 |
Non-electricity business and consolidation adjustments |
| (438,618 | ) | (433,921 | ) | (4,696 | ) | 1.1 |
| | (368,650) | | (386,716) | | 18,066 | | 4.7 |
Total Revenues and other operating income |
| 2,522,978 |
| 2,541,567 |
| (18,589 | ) | (0.7 | ) | | 2,770,834 | | 2,457,161 | | 313,673 | | 12.8 |
Generation Business: Revenues and other operating income
Revenues and other operating income from our generation business decreasedincreased Ch$ 146 billion in 20172019 compared to 2016.2018, explained by:
(i) | an increase of Ch$ 105 billion in other operating income, mainly due to: |
a) | an increase of Ch$ 121.1 billion in non-recurring income from the early termination of three energy supply contracts with Anglo American Sur, offset by |
b) | a decrease of Ch$ 16.5 billion in revenues due to the non-recurring income from insurance compensation for claims related to incidents at Tarapacá received in 2018. |
(ii) | an increase of Ch$ 46.6 billion in revenues from electricity sales, mainly attributable to: |
a) | an increase of Ch$ 183.3 billion in sales due to a higher average sales price in Chilean pesos as a result of a higher average exchange rate for the period, offset by a decrease of Ch$ 92.2 billion due to a decline of 855 GWh in physical sales (2,933 GWh less to regulated customers and 275 GWh less in spot market sales, partially compensated by 2,353 GWh more to non-regulated customers). The |
demand in October and November 2019 explained by the social crisis in Chile. In the case of spot market sales, the reduction is primarily due to lower hydrological generation of our plants; |
b) | a decrease of Ch$ 40.8 billion in revenues from exchange rate hedging derivatives; and |
c) | a decrease of Ch$ 7.5 billion in revenues from commodities hedging, such as coal and Brent oil; and |
(iii) | a decrease of Ch$ 5.9 billion in other sales mainly due to a reduction of Ch$ 6.1 billion |
Distribution Business: Revenues and other operating income
Revenues and other operating income from our distribution business increased Ch$ 150 billion in 20172019 compared to 2016,2018, primarily due to an increase in customer consumption of Ch$ 17.3 billion, mainly attributable to (i) greater sales of Ch$ 9.8 billion to residential customers, (ii) higher unregulated customer sales of Ch$ 4.3 billion, and (iii) greater revenues from non-electricity sales of Ch$ 3.8 billion, mainly sales of products and connections to telecommunications companies.to:
(i) | An increase of Ch$ 114.5 billion in sales due to a higher average sale price in Chilean pesos as a result of a higher exchange rate for the period; |
(ii) | an increase of Ch$ 22.6 billion, due to higher physical sales of 325 GWh; and |
(iii) | an increase of Ch$ 11.1 billion, due to the positive effect on the tariff that originated from the application of the technical standard of quality of service for distribution systems, which was established by the CNE in a resolution promulgated on December 2017. |
The number of customers rose by 56,87547,229 in 2017 compared2019 to 2016, totaling 1,882,394,a total of 1,972,216. The increase in customers was mainly newin the residential customers.segment.
Consolidated Operating Costs
TotalOur operating costs consistare primarily of energy purchases from third parties, fuel purchases,consumption, and tolls paid to transmission companies, depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses.
The following table setstwo tables set forth the principal items for our consolidated operating costs by category(excluding depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses, which are discussed below under Consolidated Selling and Administrative Expenses) for the years ended December 31, 2017,2019, and 2016:2018, by category and by business segment.
|
| Years ended December 31, |
| ||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
|
|
|
|
|
|
|
|
|
|
Energy purchases |
| 902,435 |
| 891,747 |
| 10,688 |
| 1.2 |
|
Fuel consumption |
| 280,739 |
| 295,149 |
| (14,409 | ) | (4.9 | ) |
Transmission costs |
| 155,879 |
| 195,123 |
| (39,244 | ) | (20.1 | ) |
Other variable procurement and services |
| 175,733 |
| 115,401 |
| 60,333 |
| 52.3 |
|
Total Consolidated Operating Costs |
| 1,514,787 |
| 1,497,420 |
| 17,368 |
| 1.2 |
|
The following table sets forth our consolidated operating costs (excluding selling and administrative expenses) by reportable segment for the years ended December 31, 2017 and 2016:
|
| Years ended December 31, |
| ||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Generation Business |
|
|
|
|
|
|
|
|
|
Enel Generation and subsidiaries |
| 903,978 |
| 895,060 |
| 8,918 |
| 1.0 |
|
Distribution Business |
|
|
|
|
|
|
|
|
|
Enel Distribution and subsidiaries |
| 1,055,708 |
| 1,042,329 |
| 13,378 |
| 1.3 |
|
Non-electricity business and consolidation adjustments |
| (444,899 | ) | (439,970 | ) | (4,929 | ) | 1.1 |
|
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses) |
| 1,514,787 |
| 1,497,420 |
| 17,367 |
| 1.2 |
|
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2019 |
| 2018 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
| | | | | | | | |
Energy purchases | | 835,285 | | 747,647 | | 87,638 | | 11.7 |
Fuel consumption | | 230,944 | | 231,028 | | (84) | | (0.0) |
Transmission costs | | 196,849 | | 166,876 | | 29,973 | | 18.0 |
Other variable procurement and services | | 158,127 | | 146,627 | | 11,501 | | 7.8 |
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses) | | 1,421,205 | | 1,292,177 | | 129,028 | | 10.0 |
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| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2019 |
| 2018 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
Generation Business | | | | | | | | |
Enel Generation, EGP Chile, and subsidiaries | | 678,188 | | 709,506 | | (31,319) | | (4.4) |
Distribution Business | | | | | | | | |
Enel Distribution and subsidiaries | | 1,114,936 | | 972,500 | | 142,436 | | 14.6 |
Non-electricity business and consolidation adjustments | | (371,919) | | (389,829) | | 17,910 | | 4.6 |
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses) | | 1,421,205 | | 1,292,177 | | 129,028 | | 10.0 |
Generation Business: Operating Costs
Operating costs of our generation business increaseddecreased Ch$ 31 billion in 20172019 compared to 2016,2018, mainly due to Ch$ 51.7 billion higher other variable procurement and services costs, which in turn was mostly attributable to (i) Ch$ 29.5 billion higher costs in the gas commercialization business, (ii) Ch$17.3 billion higher thermal emissions taxes and (iii) Ch$ 7.6 billion higher commodity derivative costs and increasedto:
(i) | a decrease of Ch$ 53 billion in energy purchases, equivalent to a reduction of 24.9% compared to 2018, partly explained by a decline of 1,850 GWh in physical energy purchases (1,216 GWh in spot market purchases and 634 GWh in contracted energy purchases), explained by the higher availability of our power plants and a decrease in physical sales. This lower cost includes the positive effect of the consolidation of EGP Chile with Enel Chile, which led to a net Ch$ 60.2 billion decrease in Enel Chile’s cost of energy purchases due to the elimination of related-party transactions (sales between EGP Chile and Enel Generation). |
(ii) | Fuel consumption costs remained unchanged in the aggregate, with higher coal costs completely offsetting lower fuel oil and gas costs: |
a) | a decrease of Ch$ 7.8 billion in fuel oil consumption significantly related to the lower dispatch of the power plants that operate with fuel oil; |
b) | a decrease of Ch$ 6 billion in gas consumption cost, mainly due to the lower price of gas as a result of an increase in the supply of gas from Argentina; and |
c) | an increase of Ch$ 13.7 billion in coal consumption costs due to higher thermal dispatch as a consequence of the poorer hydrologic conditions in Chile in 2019. |
(iii) | an increase of Ch$ 15 billion in transportation costs, mainly due to: |
a) | an increase of Ch$ 14.7 billion in gas transportation costs; |
b) | an increase of Ch$ 0.7 billion in regasification costs related to higher gas fueled electricity generation; and |
c) | a decrease of Ch$ 0.5 billion in toll expenses. |
(iv) | An increase of Ch$ 6.8 billion in other variable procurement and services costs, mainly due to: |
a) | an increase of Ch$ 10.5 billion in thermal emissions tax cost; |
79
b) | an increase of Ch$ 1.7 billion in other various electricity generation supply costs (such as water, chemicals, etc.); and |
c) | a decrease of Ch$ 5.5 billion in costs of sales in the gas commercialization business. |
Distribution Business: Operating Costs
Operating costs of our distribution business increased Ch$ 142 billion in 20172019 compared to 2016,2018, mainly due to (i) Ch$ 16.1 billion higher other variable procurement and service costs attributable to greater outages, reinstatement and emergency plan costs related to extraordinary climatic events in June and July 2017 amounting to Ch$ 15.5 billion (including provisions for fines amounting to Ch$ 8.4 billion, legal damage compensation payments for Ch$ 3.6 billion, the payment of voluntary compensations for Ch$ 3.4 billion), and (ii) increased transportation expenses for Ch$ 2.6 billion.to:
(i) | an increase of Ch$ 109.4 billion due to a higher average purchase price; |
(ii) | an increase of 397 GWh in physical purchases required to satisfy demand, equivalent to Ch$ 20.8 billion; |
(iii) | an increase of Ch$ 12.9 billion due to higher transportation costs; and |
(iv) | a decrease of Ch$ 0.6 billion in other variable procurement and services. |
Consolidated Selling and Administrative Expenses
SellingOur selling and administrative expenses relate toare salaries and other compensation administrative expenses, depreciation, amortization and impairment losses, and office materials and supplies.
The following table setstwo tables set forth our consolidated selling and administrative expenses in Chilean pesos and as a percentage of total consolidated selling and administrative expenses for the years ended December 31, 20172019, and 2016:2018, by category and by business segment:
| | | | | | | | | |||||||||
| | Years ended December 31, | |||||||||||||||
|
| 2019 |
| 2018 |
| Change | | Change | |||||||||
|
| Years ended December 31, |
| ||||||||||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
| ||||||||
|
| (in millions of Ch$) |
| (in%) |
| ||||||||||||
|
|
|
|
|
|
|
|
|
| ||||||||
| | (in millions of Ch$) | | (in %) | |||||||||||||
| | | | | | | | | |||||||||
Depreciation, amortization and impairment losses |
| 160,621 |
| 197,587 |
| (36,966 | ) | (18.7 | ) | | 527,437 | | 220,750 | | 306,687 | | 138.9 |
Other fixed costs |
| 161,824 |
| 170,769 |
| (8,945 | ) | (5.2 | ) | | 184,143 | | 167,211 | | 16,932 | | 10.1 |
Employee benefit expense and others |
| 107,115 |
| 108,002 |
| (887 | ) | (0.8 | ) | | 111,994 | | 106,419 | | 5,575 | | 5.2 |
Total Consolidated Selling and Administrative Expenses |
| 429,560 |
| 476,358 |
| (46,798 | ) | (9.8 | ) | | 823,574 | | 494,380 | | 329,194 | | 66.6 |
The following table sets forth our consolidated selling and administrative expenses by reportable segment for the years ended December 31, 2017 and 2016:
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2019 |
| 2018 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
Generation Business | | | | | | | | |
Enel Generation, EGP Chile, and subsidiaries | | 652,489 | | 337,527 | | 314,962 | | 93.3 |
Distribution Business | | | | | | | | |
Enel Distribution and subsidiaries | | 145,642 | | 131,465 | | 14,177 | | 10.8 |
Non-electricity business and consolidation adjustments | | 25,443 | | 25,388 | | 55 | | 0.2 |
Total Consolidated Selling and Administrative Expenses | | 823,574 | | 494,380 | | 329,194 | | 66.6 |
|
| Years ended December 31, |
| ||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Generation Business |
|
|
|
|
|
|
|
|
|
Enel Generation and subsidiaries |
| 267,099 |
| 333,281 |
| (66,182 | ) | (19.9 | ) |
Distribution Business |
|
|
|
|
|
|
|
|
|
Enel Distribution and subsidiaries |
| 138,441 |
| 116,837 |
| 21,603 |
| 18.5 |
|
Non-electricity business and consolidation adjustments |
| 24,020 |
| 26,240 |
| (2,220 | ) | (8.5 | ) |
Total Consolidated Selling and Administrative Expenses |
| 429,560 |
| 476,358 |
| (46,798 | ) | (9.8 | ) |
Consolidated selling and administrative expenses decreasedincreased Ch$ 329 billion in 20172019 compared to 2016,2018, mainly due to a reduction in the generation business. The reduction in the generation business is primarily due to (i) lower impairment losses of property, plant and equipment of Ch$ 30.8 billion due to the non-recurring impairment charges of Ch$ 24.2 billion booked in 2016 related to NCRE projects and the Neltume and Choshuenco projects (see “— 2. Analysis of Result of operations for the year ended December 31, 2016 and 2015 — Consolidated Selling and Administrative Expenses”); (ii) lower other fixed costs of Ch$ 16.5 billion primarily attributable to the non-recurring impairment charges of Ch$ 35.4 billion related to the waiver of water rights of the Bardón, Chillán 1 and 2, Futaleufú, Huechún and Puelo hydroelectric projects recorded in 2016 compared with the Ch$ 25.1 billion loss recognized in 2017 in connection with Enel Generation’s decision to abandon the Neltume and Choshuenco projects for being economically unfeasible to reduce the net book value of the associated assets to zero; and (iii) lower depreciation and amortization of Ch$ 15.3 billon primarily due to the modification of the remaining useful life of fixed assets applied to Property, Plant, and Equipment in 2017.
Selling and administrative expenses in our distribution business increased in 2017 compared to 2016, primarily due to (i) Ch$ 9.8 billion higher other fixed costs, mainly attributable to an increase in emergency attention, line maintenance and a tree trimming plan of Ch$ 8.6 billion, (ii) Ch$ 9.1 billion higher depreciation and amortization and impairment losses due to an increase in depreciation related to construction works that became operational and (iii) a Ch$ 2.6 billion increase in employee expenses due to extraordinary non-recurrent employee bonuses related to the new collective bargaining process carried out with Enel Distribution’s unions in 2016.generation business, explained by:
(i) | the impairment expense associated with the Tarapacá and Bocamina I coal-fired generating units of Ch$ 197.2 billion and Ch$ 82.8 billion, respectively, as a result of their announced closures as part of our decarbonization process, and higher depreciation contributed by EGP Chile of Ch$ 27 billion; |
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(ii) | an increase of Ch$ 8.9 billion in costs of maintenance and repair services in the generation segment, an increase of Ch$ 3.8 billion in maintenance costs associated with the technical distribution standard, and an increase of Ch$ 3.5 billion in disposals and removals from service in property, plant, and equipment; and |
(iii) | an increase in employee benefit expenses corresponding to (i) an increase of Ch$ 3.1 billion in personnel expense, mainly due to higher staffing and the effect of the consolidation of EGP Chile for a full year in 2019 compared to nine months in 2018; and (ii) a decrease of Ch$ 2.1 billion in the capitalization of personnel cost. |
Consolidated Operating Income
The following table sets forth our operating income by reportable segment for the years ended December 31, 20172019, and 2016:2018:
|
| Years ended December 31, |
| ||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Generation Business |
|
|
|
|
|
|
|
|
|
Enel Generation and subsidiaries |
| 463,860 |
| 431,386 |
| 32,474 |
| 7.5 |
|
Distribution Business |
|
|
|
|
|
|
|
|
|
Enel Distribution and subsidiaries |
| 132,510 |
| 156,594 |
| (24,084 | ) | (15.4 | ) |
Non-electricity business and consolidation adjustments |
| (17,740 | ) | (20,191 | ) | 2,452 |
| (12.1 | ) |
Total Consolidated Operating Income |
| 578,631 |
| 567,789 |
| 10,841 |
| 1.9 |
|
Operating margin(1) |
| 22.9 | % | 22.3 | % | — |
| — |
|
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2019 |
| 2018 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
Generation Business | | | | | | | | |
Enel Generation, EGP Chile, and subsidiaries | | 395,935 | | 533,620 | | (137,685) | | (25.8) |
Distribution Business | | | | | | | | |
Enel Distribution and subsidiaries | | 152,294 | | 159,259 | | (6,965) | | (4.4) |
Non-electricity business and consolidation adjustments | | (22,174) | | (22,275) | | 101 | | 0.5 |
Total Consolidated Operating Income | | 526,055 | | 670,605 | | (144,550) | | (21.6) |
Operating margin(1) | | 19.0% | | 27.3% | | — | | — |
(1) Operating margin, a measure of efficiency, represents operating income as a percentage of revenues.
(1) | Operating margin, a measure of efficiency, represents operating income as a percentage of revenues. However, caution must be applied in making comparisons among periods, which may have experienced non-recurring gains or losses, as was the case in 2019 with the expense related to the closure of two coal-fired power plants. |
Our operating income in 2017 increased slightly2019 decreased compared to 2016 primarily2018 due to:
��
Generation Business
Operating income was affected by the non-recurring loss generated from the impairment related to the combination of:announcement of the closure of the Tarapacá and Bocamina I coal-fired power plants, partially offset by the non-recurring income generated by the early termination of three energy supply contracts with Anglo American Sur.
· Hydrological conditions in Chile have been belowOn the historical average since 2010. However, in 2017,other hand, during 2019, hydrological conditions were slightly more humid thanone of the driest in 2016, mainly during the fourth quarterlast 10 years in Chile, causing a decrease in the generation of 2017. This allowed us to produce more electricity throughfrom hydroelectric generation rather thanplants. As a result, we increased thermal generation, which is more expensive. In addition, theincreased our operating costs.
The commissioning of new NCRE plants reducedand the interconnection between the central and northern interconnected systems helped to reduce the impact of dry conditions. Therefore,the change in our energy matrix and stabilize the marginal cost of electricity generation decreasedoperating costs in 2017 when2019 compared to 2016.2018. As a result, we were able to cover our energy deficit in the spot market at lower prices. OurThis energy deficit decreased mainly due to i) greater generation from our thermal plants, and ii) increased availability of Argentine natural gas for our combined cycles.
Although our physical sales decreased when compared to 2016 and our customer mix changed because a portion of our regulated customers chose the unregulated tariff regime instead. Our selling and administrative expenses decreased considerably in 2017, mainly2019, they were sold at higher average sales prices expressed in Chilean peso due to a higher average exchange rate, which was partially offset by lower revenues as a result of the impairmentsmigration of customers from the regulated market to the non-regulated market.
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Distribution Business
Operating costs increased due to a higher average energy purchase price, higher physical purchases, and, write-offs we bookedto a lesser degree, higher operation and maintenance costs, depreciation of fixed assets and amortization of intangible assets due to higher transfers of constructions in 2016.
· In theprogress to assets in operation. As a result, our distribution business although our physical sales and unregulated sales related to infrastructure projects and public lighting increasedoperating income decreased in 2017 when compared to 2016, in June and July 2017 we faced rain storms and the most damaging snow storm in Santiago since 1970, leaving parts of the capital without power for over one week. These situations significantly increased our costs due to emergency responses including payments related to damage compensation, fines, lines maintenance and tree trimming plans.2019.
Consolidated Financial and Other Results
The following table sets forth our financial and other results for the years ended December 31, 20172019, and 2016:2018:
| | | | | | | | | |||||||||
| | Years ended December 31, | |||||||||||||||
|
| 2019 |
| 2018 |
| Change | | Change | |||||||||
|
| Years ended December 31, |
| ||||||||||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
| ||||||||
|
| (in millions of Ch$) |
| (in%) |
| ||||||||||||
| | (in millions of Ch$) | | (in %) | |||||||||||||
Financial results |
|
|
|
|
|
|
|
|
| | | | | | | | |
Financial income |
| 21,663 |
| 23,106 |
| (1,443 | ) | (6.2 | ) | | 27,399 | | 19,934 | | 7,465 | | 37.4 |
Financial costs |
| (53,511 | ) | (58,199 | ) | 4,689 |
| (8.1 | ) | | (164,898) | | (122,184) | | (42,714) | | (35.0) |
Profit for indexed assets and liabilities |
| 916 |
| 1,632 |
| (716 | ) | (43.9 | ) | ||||||||
Gain (loss) from indexed assets and liabilities | | (2,982) | | (818) | | (2,164) | | 264.5 | |||||||||
Foreign currency exchange differences |
| 8,517 |
| 12,978 |
| (4,462 | ) | (34.4 | ) | | (10,412) | | (7,807) | | (2,605) | | (33.4) |
Total |
| (22,416 | ) | (20,483 | ) | (1,932 | ) | 9.4 |
| ||||||||
Total financial results | | (150,893) | | (110,875) | | (40,018) | | (36.1) | |||||||||
Other Results |
|
|
|
|
|
|
|
|
| | | | | | | | |
Share of the profit (loss) of associates and joint ventures accounted for using the equity method |
| (2,697 | ) | 7,878 |
| (10,575 | ) | n.a. |
| | 366 | | 3,190 | | (2,824) | | (88.5) |
Gain from sales of assets |
| 113,241 |
| 121,490 |
| (8,249 | ) | (6.8 | ) | ||||||||
Total |
| 110,544 |
| 129,368 |
| (18,824 | ) | (14.6 | ) | ||||||||
Gain (loss) from sales of assets | | 1,793 | | 3,411 | | (1,618) | | (47.4) | |||||||||
Total Other results | | 2,159 | | 6,601 | | (4,441) | | (67.3) | |||||||||
Total Consolidated Financial and Other Results |
| 88,129 |
| 108,885 |
| (20,756 | ) | (19.1 | ) | | (148,734) | | (104,274) | | (44,460) | | (42.6) |
Financial Results
We recorded a higher net financial expense for the year ended December 31, 20172019, compared to 2016. This is2018, primarily attributable to:
(i) | financial costs increased Ch$ 42.7 billion, mainly due to: |
a) | an increase of Ch$ 19 billion in expenses related to the Tariff Stabilization Law; |
b) | an increase of Ch$ 14.8 billion in financial expenses due to the consolidation of EGP Chile for a full year in 2019 compared to nine months in 2018; |
c) | an increase of Ch$ 11.9 billion in interest on bank loans related to our corporate reorganization carried out in 2018; |
d) | an increase of Ch$ 1.8 billion in financial expenses due to factoring operations; and |
e) | a decrease of Ch$ 4.9 billion in financial expenses due to the loan renegotiation between EGP del Sur and Enel Finance International. |
(ii) | an increase of Ch$ 7.5 billion in financial income, mainly due to: |
a) | an increase of Ch$ 5.2 billion in interest income related to the application of the Tariff Stabilization Law; |
b) | an increase of Ch$ 5.3 billion in interest income related to regulated customer accounts receivables to be billed before to the application of the Tariff Stabilization Law; and |
82
c) | a decrease of Ch$ 2.4 billion in interest income on short-term fixed income investments, and Ch$ 0.2 billion in lower interest income from refinancing to customers. |
(iii) | an increase of Ch$ 2.2 billion in losses related to indexation primarily due to: |
a) | an increase of Ch$ 1.6 billion in losses due to a negative impact of IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch of the Enel Generación Group located in Argentina; |
b) | a decrease of Ch$ 0.8 billion in income from recoverable taxes; |
c) | a decrease of Ch$ 0.5 billion in income from hedging derivative contracts; partially offset by |
d) | a decrease of Ch$ 0.7 billion in losses as a result of indexation of financial liabilities recorded in U.F. |
(iv) | a decrease of Ch$ 2.6 billion in income from exchange rate differences, mainly due to negative exchange rate arising from: |
(v) | a decrease of Ch$ 2.6 billion in income from exchange rate differences, mainly due to negative exchange rate arising from: |
a) | a decrease of Ch$ 6.4 billion in forward contracts; and |
b) | a decrease of Ch$ 0.5 billion in cash and cash equivalents; partially offset by |
c) | the positive effects of (i) an increase of Ch$ 3 billion in trade accounts payable, and (ii) an increase of Ch$ 1.1 billion in trade accounts receivable, including an increase of Ch$ 3.8 billion due to the Tariff Stabilization Law that dollarized the regulated customer accounts receivable whose bills are outstanding. |
Other Results
Our gain from disposition of assets decreased in 2019 compared to lower gains from foreign currency exchange differences, mainly as2018, primarily due to a resultdecrease of the lower Chilean peso valueCh$ 1.7 billion in sales of the U.S.
dollar intercompany debt owed by Enel Generation to Enel Américas forthird parties.
We also registered a decrease of Ch$ 10.1 billion that was offset by greater income on cash and cash equivalents in U.S. dollars for Ch$ 5.7 billion. These lower gains were offset by Ch$ 4.72.8 billion in lower financial costs, mainly due to lower interest expenses on bank loans and public bonds for Ch$ 4.7 billion. The reduction of our financial result was also the consequence of Ch$ 1.4 billion lower financial income due to a settlement agreement we entered into with YPF in 2016 for Ch$ 2.0 billion and lower customer refinancing income for Ch$ 1.9 billion in 2017, offset by higher income from temporary investments in fixed income securities for Ch$ 2.6 billion.
Other Results
Our share of the profit (loss) of associates and joint ventures accounted for using the equity method for the year ended December 31, 2017, decreased compared to 2016, primarily due to the sale of our former associate Electrogas in February 2017 and GNL Quintero in September 2016, accounting for a Ch$ 5.2 billion and Ch$ 2.8 billion decrease in equity investment profits, respectively. In addition, the loss registered in connection with HidroAysén increased by Ch$ 2.0 billion. For additional information on the termination and liquidation of HidroAysén, see “Item 4. Information on the Company — C. Organizational Strucuture — Selected Related and Jointly-Controlled Companies — HidroAysén.”
We also registered a lower gain from the sales of assets in 20172019 when compared to 2016. In 2017 we recorded a2018, mainly due to lower results compared to 2018 from (i) HidroAysén, which was liquidated in 2018, amounting to Ch$ 105.31.7 billion, gain from the saleand (ii) GNL Chile S.A. of Electrogas and the sale of a land owned by GasAtacama for Ch$ 7.6 billion, while in 2016 we recognized a Ch$ 121.3 billion gain in 2016 from the sale of GNL Quintero.1.1 billion.
Consolidated Income Tax Expenses
The effective tax rate decreased to 16.2% in 2019 compared to 27.1% in 2018.
Consolidated income tax expenses totaleddecrease of Ch$ 143.392.2 billion in 2017, an increase of Ch$ 31.9 billion, or 28.7%, when2019 compared to 2016.2018. This decrease is mainly due to:
(i) | a decrease of Ch$ 75.6 billion in tax expense as a result of the impairment of Bocamina I and Tarapacá coal-fired power plants in relation to their announced closures as part of the decarbonization process; |
(ii) | a decrease of Ch $ 29.3 billion, arising from the absorption of GasAtacama Argentina by GasAtacama Chile; |
(iii) | a decrease of Ch$ 8.1 billion in income tax expense associated with lower results; |
83
(iv) | a decrease of Ch$ 6.3 billion in expense corresponding to non-refundable credits attributed to tax losses in 2018; |
(v) | a decrease of Ch$ 5.1 billion in income tax expense for Enel Chile due to a loss incurred on the sale of its interest in GasAtacama Chile to Enel Generation; and |
(vi) | an increase of Ch$ 32.7 billion in income tax expense for the non-recurring revenues generated by the early termination of three energy supply contracts with Anglo American Sur. |
The increase in consolidated income tax expenses was primarily due to (i) a Ch$ 13.5 billion higher expense due to the reversal of the deferred income tax related to the dissolution of Central Canela S.A., (ii) Ch$ 13.1 billion greater income tax expenses related to lower exchange rate and price-level restatement losses (which increases the taxable income) and (iii) Ch$ 8.0 billion related to the increase of the statutory tax rate, from 24.0% to 25.5%. The increase in consolidated income tax expenses resulted in the increase of the effective income tax rate.
The effective tax rate was 21.5% in 2017 compared to 16.5% in 2016. For further details, please refer to Note 1720 of the Notes to our consolidated financial statements.
Consolidated Net Income
The following table sets forth our consolidated net income before taxes, income tax expenses and net income for the years ended December 31, 20172019 and 2016:2018:
| | | | | | | | |
| | Years ended December 31, | ||||||
|
| 2019 |
| 2018 |
| Change | | Change |
| | (in millions of Ch$) | | (in %) | ||||
Consolidated Operating income | | 526,055 | | 670,605 | | (144,550) | | (21.6) |
Consolidated Other results | | (148,734) | | (104,274) | | (44,460) | | (42.6) |
Consolidated Net income before taxes | | 377,321 | | 566,331 | | (189,010) | | (33.4) |
Income tax expenses | | (61,228) | | (153,483) | | 92,255 | | 60.1 |
Consolidated Net income | | 316,093 | | 412,848 | | (96,755) | | (23.4) |
Net income attributable to the Parent Company | | 296,154 | | 361,710 | | (65,556) | | (18.1) |
Net income attributable to non-controlling interests | | 19,939 | | 51,138 | | (31,199) | | (61.0) |
|
| Years ended December 31, |
| ||||||
|
| 2017 |
| 2016 |
| Change |
| Change |
|
|
| (in millions of Ch$) |
| (in%) |
| ||||
Consolidated Operating income |
| 578,631 |
| 567,789 |
| 10,841 |
| 1.9 |
|
Consolidated Other results |
| 88,129 |
| 108,885 |
| (20,756 | ) | (19.1 | ) |
Consolidated Net income before taxes |
| 666,759 |
| 676,674 |
| (9,915 | ) | (1.5 | ) |
Income tax expenses |
| (143,342 | ) | (111,403 | ) | (31,939 | ) | 28.7 |
|
Consolidated Net income |
| 523,417 |
| 565,271 |
| (41,854 | ) | (7.4 | ) |
Net income attributable to the Parent Company |
| 349,383 |
| 384,160 |
| (34,777 | ) | (9.1 | ) |
Net income attributable to non-controlling interests |
| 174,035 |
| 181,111 |
| (7,076 | ) | (3.9 | ) |
The decrease in net income attributable to non-controlling interests in 20172019 compared to 20162018 of Ch$ 31.2 billion is primarily due to the Ch$ 5.8 billion decrease in the percentage of net income attributable to the non-controlling interestsminority shareholders of Enel Generation for 2017, which in turn is mainly duecorresponding to the decrease of the net income of Enel Generation by Ch$ 95.9 billion. The controlling andChile’s increased economic interest in Enel Generation wasafter the same in both years.
B.Liquidity and Capital Resources.completion of the 2018 Reorganization.
Liquidity and Capital Resources. |
Our main assets are our consolidated Chilean subsidiaries, Enel Generation, EGP Chile, and Enel Distribution. The following discussion of cash sources and uses reflects the key drivers of our cash flow.
We receive cash inflows from our subsidiaries and related companies. Our subsidiaries’ and associates’ cash flows may not always be available to satisfy our own liquidity needs because there may be a time lag before we have effective access to those funds through dividends or capital reductions. However, we believe that cash flow generated from our business operations, as well as cash balances, borrowings from commercial banks, short- and long-term intercompany loans, and ample access to the capital markets will be sufficient to satisfy all our needs for working capital, expected debt service, dividends, and planned capital expenditures in the foreseeable future.
84
Set forth below is a summary of our consolidated cash flow information for the years ended December 31, 2018, 20172020, 2019, and 2016:2018:
| | | | | | |
| | Year ended December 31, | ||||
|
| 2020 |
| 2019 |
| 2018 |
| | (in billions of Ch$) | ||||
Net cash flows provided by operating activities | | 756 | | 744 | | 736 |
Net cash flows used in investing activities | | (555) | | (312) | | (1,882) |
Net cash flows provided by (used in) financing activities | | (128) | | (440) | | 967 |
Net increase (decrease) in cash and cash equivalents before the effect of exchange rates changes | | 73 | | (8) | | (179) |
Effect of exchange rate changes on cash and cash equivalents | | 23 | | (1) | | 5 |
Cash and cash equivalents at the beginning of the period | | 236 | | 245 | | 419 |
Cash and cash equivalents at the end of the period | | 332 | | 236 | | 245 |
|
| Year ended December 31, |
| ||||
|
| 2018 |
| 2017 |
| 2016 |
|
|
| (in billions of Ch$) |
| ||||
Net cash flows provided by operating activities |
| 736 |
| 636 |
| 615 |
|
Net cash flows used in investing activities |
| (1,882 | ) | (146 | ) | (63 | ) |
Net cash flows provided by (used in) financing activities |
| 967 |
| (318 | ) | (446 | ) |
Net increase (decrease) in cash and cash equivalents before effect of exchange rates changes |
| (179 | ) | 172 |
| 105 |
|
Effect of exchange rate changes on cash and cash equivalents |
| 5 |
| 2 |
| (4 | ) |
Cash and cash equivalents at beginning of period |
| 419 |
| 246 |
| 144 |
|
Cash and cash equivalents at end of period |
| 245 |
| 419 |
| 246 |
|
For the year ended December 31, 2018,2020, net cash flow provided by operating activities increased 15.7%Ch$ 12 billion, or 1.6%, compared to the same period in 2017.2019. The increase was in part the result of lower payments as detailed below:of:
(i) | Ch$ 94 billion in collections from leasing and the subsequent sale of these assets, mainly from Ch$ 82 billion Enel X Chile received from leasing electric buses to the AMPCI consortium and Ch$ 4 billion Enel Distribution received from the leasing of public lighting; and |
(ii) | Ch$ 81 billion in lower income tax payments in 2020, explained by (i) Ch$ 48.6 billion Enel Chile received in tax refunds from the recognition of tax losses; (ii) Ch$ 15.4 billion in lower Enel Distribution monthly tax payments; (iii) Ch$ 9.8 billion in lower Pehuenche monthly tax payments; and (iv) Ch$ 9.3 billion EGP Chile received in tax refunds from the recognition of tax losses. |
(i) a decrease of Ch$ 147 billion in payments to suppliers of goods and services mainly due to:These operating activity net cash flow increases were partially offset by:
(iii) | Ch$ 92 billion in lower sales of goods and services, comprised mainly of: |
i) | Ch$ 100.5 billion from Enel Generation, mainly due to the non-recurrence of the 2019 early termination of electricity supply contracts with Anglo American for Ch$ 106.5 billion, partially offset by |
ii) | Ch$ 12.1 billion from Enel X Chile, mainly due to higher collections from the sale of energy-efficient products. |
a. the positive effect of adding EGP Chile into our consolidated perimeter, which led to a net reduction of Ch$ 107 billion in our cost of energy purchases as a consequenceThe effects of the elimination of related party transactions (sales of EGP Chile to Enel Generation and Enel Distribution);
b. a decrease of Ch$ 37 billion in fuel costs to Enel Generation;
(ii) a decrease of Ch$ 49 billion in income tax payments during 2018 primarily due to Ch$45 billion in tax refunds for recognition of tax losses in Celta and higher monthly payments made by GasAtacama in 2017; and
(iii) a decrease of Ch$ 9 billion in payments to and on behalf of employees from operating activities, mainly in Enel Distribution, which registered higher payments in 2017 associated with retirement plans and union agreements.
This was partially offset by a decrease of Ch$ 109 million in collections from the sale of goods and services, comprised mainly of:
(i) a decrease of Ch$ 95 billion in collections from Enel Generation, on a stand-alone basis and excluding intercompany transactions, due to a lower average sales price and lower sales to regulated customers;
(ii) a decrease of Ch$ 41 billion in collections from GasAtacama, excluding intercompany transactions, due to lower physical sales mainly in the spot market;
(iii) a decrease of Ch$ 39 billion in collections from Enel Distribution, excluding intercompany transactions, dueCovid-19 pandemic led to a reduction in billingsenergy consumption during lockdown periods, which negatively impacted Chile’s economic activity and affected our collections. However, in December 2020, Enel Distribution Chile transferred collection rights from transmission tolls partially offset by; and
(iv) an increase of Ch$ 57 billion in collections from EGP Chile, excluding intercompany transactions as a resultportion of its acquisition and consolidationtrade receivables for the nine-month periodsale of energy to some customer segments for Ch$ 44.8 billion. See Note 9.a.2 of the Notes to our consolidated financial statements.
(iv) | Ch$ 23 billion in lower insurance claims, mainly due to the non-recurrence of 2019 insurance claims of Ch$ 12.5 billion for Tarapacá and Ch$ 9.7 billion for Los Cóndores; |
(v) | Ch$ 17 billion in higher payments by Enel X Chile for manufacturing or acquiring assets leased to third parties and the acquisition of electric buses for leasing, and by Enel Distribution for the construction of public lighting to lease to municipalities; |
(vi) | Ch$ 16 billion in other payments for operating activities, primarily due to Ch$ 10.5 billion in higher VAT payments by Enel X Chile and Ch$ 8.2 billion in higher green emissions tax payments by Enel Generation; and |
85
(vii) | Ch$ 10 billion in higher payments to and on behalf of employees for operating activities, mainly by Enel Distribution for Ch$ 8.7 billion associated with remunerations and union agreements. |
For the year ended December 31, 2019, net cash flow provided by operating activities increased Ch$ 8 billion, or 1.1%, compared to the same period in 2018. The increase was in part the result of:
(i) | a decrease of Ch$ 52 billion in income tax payments during 2019, explained by Enel Generation’s lower income tax payments due to lower monthly and annual tax payments of Ch$ 82.8 billion and an increase of Ch$ 17.9 billion in tax refunds, offset by (i) Ch$ 45 billion of higher income tax payments by GasAtacama Chile due to tax refunds received in 2018 from the recognition of tax losses in Celta and monthly tax payments and (ii) Ch$ 5 billion of higher monthly tax payments by Enel Distribution; |
(ii) | an increase of Ch$ 21 billion in collections from insurance claims mainly due to insurance claims for Tarapacá for Ch$ 12.5 billion and Los Cóndores for Ch$ 9.7 billion; and |
(iii) | an increase of Ch$ 16 billion in collections from the sale of goods and services, comprised mainly of: |
(i) | an increase of Ch$ 7 billion in Enel Distribution, due to higher physical sales; and |
(ii) | an increase of Ch$ 6 billion in Enel X Chile. |
These operating activity net cash flow increases were partially offset by:
(iv) | an increase of Ch$ 17 billion in other payments for operating activities, due to higher VAT payments from EGP del Sur for new wind plants in operation since the second half of 2018; |
(v) | a decrease of Ch$ 22 billion in other collections from operating activities, due to the non-recurrence of a 2018 VAT refund, relating to the construction of the Cerro Pabellón project; and |
(vi) | an increase of Ch$ 40 billion in payments by Enel X Chile for electric buses to lease to third parties and Enel Distribution to construct public lighting to lease to local municipalities. |
For further information regarding our operating results in 20182020, 2019, and 2017,2018, please see “—“Item 5. Operating and Financial Review and Prospects — A. Operating Results.Results — 2. Analysis of Results of Operations for the Years Ended December 31, 20182020 and 2017.”
For the year ended December 31, 2017, net cash flow provided by operating activities increased 3.4% compared to the same period in 2016. The increase was in part the result of:
(i) a decrease of Ch$ 102 billion in other payments for operating activities mainly attributable to an increase of Ch$ 132 billion in additional tax payments in 2016, generated in accordance with Peruvian tax law as a result of the spin-offs of the non-Chilean electricity businesses in 2016, paid in March 2016 by Enel Generation (Ch$ 116 billion)2019” and Enel Distribution (Ch$ 16 billion), and partially offset by an increase of Ch$ 29 billion in VAT in 2017;
(ii) a decrease of Ch$ 51 billion in payments to suppliers of goods and services, comprised mainly of Ch$ 41 billion from Enel Distribution, mostly as a consequence of lower energy purchases from third parties; and
(iii) an increase of Ch$ 11 billion in other collections from operating activities, comprised mainly of tax refunds in the context of the 2016 Reorganization from Peru to Enel Generation corresponding to excess tax paid in 2016.
This was partially offset by a decrease of Ch$ 88 million in collections from the sale of goods and services, comprised mainly of:
(i) a decrease of Ch$ 62 billion in collections from Enel Distribution, excluding intercompany transactions, due to lower energy billing during 2017 compared to the same period in 2016, as a result of the non-application of the government’s price decree that establishes the “Average Node Price”, which was applied retroactively to November 2016;
(ii) a decrease of Ch$ 63 billion in collections from GasAtacama, excluding intercompany transactions, due to lower physical sales mainly in the spot market; and
(iii) an increase of Ch$ 41 billion in collections from Enel Generation, on a stand-alone basis and excluding intercompany transactions, due to higher natural gas sales and higher collections from energy sales.
Finally, the increase was also offset by an increase of Ch$ 57 billion in income tax paid during 2017, primarily due to the absence of the tax credit benefit corresponding to dividends received from Enel Generation’s former non-Chilean subsidiaries.
For further information regarding our operating results in 2017 and 2016, please see “— A. Operating Results. — 3. Analysis of Results of Operations for the Years Ended December 31, 20172019 and 2016.2018.”
For the year ended December 31, 2018,2020, net cash flows used in investing activities increased 1,185%were outflows amounting to Ch$ 555 billion, representing an increase of 78% or Ch$ 243 billion, compared to the same period in 2019. The aggregate investment in 2020 was mainly explained by:
(i) | Ch$ 515 billion in fixed assets investments carried out by our subsidiaries, mainly explained by Ch$ 282 billion by EGP Chile in developing renewable projects, Ch$ 140 billion by Enel Generation, mainly due to the construction of the Los Cóndores power plant, and Ch$ 93 billion by Enel Distribution to improve its networks; and |
(ii) | Ch$ 40 billion in investments in intangible assets, explained by Ch$ 18 billion by Enel Distribution, Ch$ 12 billion by EGP Chile, and Ch$ 9 billion by Enel Generation, mainly due to software purchases and concessions. |
For the year ended December 31, 2019, net cash flows used in investing activities decreased 83% compared to the same period of 2017.2018. The increaselower investment in 2019 was mainly due to the non-recurrence of the 2018 Reorganization completed on April 2, 2018, withwhen we invested Ch$ 1,624 million related to theour tender offer for our additional equity
86
interest in Enel Generation, and a decreasewhich was offset by net cash inflows in 2018 in the net collection from related companies of Ch$ 116 billion in other collections from the sale of equity or debt instruments belonging to other entities related to the sale of Electrogas.38.4 billion.
For the year ended December 31, 2017,2020, net cash flows used for investingin financing activities increased 131%were Ch$ 128 billion compared to the same period of 2016. The increase was mainly due to the acquisitioncash flows used in financing activities of Ch$ 266440 billion in fixed assets,2019.
The aggregate cash payments associated with financing activities in 2020 were primarily related to Los Cóndores project and extension of the electrical network, partially offset by Ch$ 116 billion in other collections from the sale of equity or debt instruments belonging to other entities related to the sale of Electrogas, and proceeds of Ch$ 4 billion received from the sale of land by GasAtacama.due to:
(i) | Ch$ 312 billion in dividend payments, of which Ch$ 187 billion was paid to Enel, our controlling shareholder; |
For further information regarding the 2018 Reorganization and the acquisition of fixed assets in 2017, please see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures and Divestitures.”
(ii) | Ch$ 151 billion in loan and bond payments (including Ch$ 119 billion by EGP Chile and Ch$ 32 billion by Enel Generation); and |
(iii) | Ch$ 139 billion in interest payments (Ch$ 58 billion paid by Enel Generation, Ch$ 24 billion paid by EGP Chile, and Ch$ 57 billion paid by Enel Chile), partially offset by |
(iv) | aggregate cash inflows from financing activities in 2020, primarily from a Ch$ 485 billion loan provided to Enel Chile by Enel Finance International N.V., a related company. |
For the year ended December 31, 2018,2019, net cash flows used in financing activities amounted to Ch$ 440 billion compared to the cash flows provided by financing activities increased 404% compared to 2017of Ch$ 967 in 2018, mainly to finance the 2018 Reorganization.
The aggregate cash payments associated with financing activities in 2019 were primarily due to:
(i) | Ch$ 315 billion in payments of loans and bonds (including Ch$ 214 billion by Enel Chile on a stand-alone basis related to the 2018 Reorganization, and Ch$ 70 billion by EGP Chile); |
(ii) | Ch$ 236 billion in dividend payments, of which Ch$ 134 billion was paid to Enel, our controlling shareholder; and |
(iii) | Ch$ 134 billion in interest payments (Ch$ 51 billion paid by Enel Generation, Ch$ 38 billion paid by EGP Chile, and Ch$ 45 billion paid by Enel Chile). |
These payments were partially offset by aggregate cash inflows from financing activities in 2018 were2019, primarily due to:
(i)from a loan of Ch$ 625284 billion in Yankee bonds issued by us;
(ii) Ch$ 940 billion in bank loans granted to us; and
(iii) Ch$ 666 billion in proceeds from the issuance of shares in connection with the tender offer and related capital increase made as part of the 2018 Reorganization.
The aggregate cash outflows from financings activities in 2018 were primarily due to:
(i) Ch$ 820 billion in payments of loans and bonds (including Ch$ 749 billion from us on a stand-alone basis, related to the 2018 Reorganization and Ch$ 65 billion from EGP Chile);
(ii) Ch$ 231 billion in dividend payments, of which Ch$ 118 billion was paidprovided to Enel our controlling shareholder;
(iii) Ch$ 116 billion in interest expense (Ch$ 47 billion paidChile by Enel Generation, Ch$ 41 billion paid by EGP Chile and Ch$ 28 billion paid by us); andFinance International N.V., an affiliated finance company.
(iv) Ch$ 72 billion in payments to acquire treasury shares.
For the year ended December 31, 2017, net cash flows used in financing activities decreased 29% compared to 2016, mainly due to lower dividend payments due in part to the payment of dividends by Enel Distribution and Enel Generation to Enel Américas prior to the spin-offs in 2016, and lower other cash outflows associated with cash allocations related to the 2016 Reorganization.
The aggregate cash outflows from financing activities in 2017 were primarily due to:
(i) Ch$ 261 billion in dividend payments, of which Ch$ 96 billion was paid to Enel, our controlling shareholder;
(ii) Ch$ 44 billion in interest expense, mainly paid by Enel Generation on a stand-alone basis;
(iii) Ch$ 6 billion in payments of loans and bonds paid by Enel Generation on a stand-alone basis; and
(iv) Ch$ 5 billion mainly of derivatives instrument payments executed by Enel Generation.
For a description of liquidity risks resulting from the inability of our subsidiaries to transfer funds, please see “Item 3. Key Information — D. Risk Factors — We depend on payments from our subsidiaries to meet our payment obligations.”
We coordinate the overall financing strategy of our subsidiaries. However, our subsidiaries independently develop their capital expenditure plans and customarily finance their capital expansion programs through internally generated funds, intercompany financings, or direct financings. We,In recent years, we have adopted a preference to incur debt at the parent company level in Enel Chile and to finance most of the obligations of our subsidiaries through intercompany loans. Among the advantages to this financing strategy is the mitigation of structural subordination risk arising from subsidiary debt, with its favorable consequences for us from the perspective of rating agency credit ratings. Furthermore, we as a holding company can frequently access liquidity from several sources on a stand-alone basis,better terms and conditions than some of our subsidiaries. However, we have no legal obligations or other commitments to support our subsidiaries financially. In some cases, we may finance our subsidiaries through intercompany loans. For information regarding our commitments for capital expenditures, see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures and Divestitures” and our contractual obligations table set forth below under “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations.”
87
As of December 31, 2018,2020, our consolidated interest-bearing debt totaled Ch$ 2,479 billion (including2.9 trillion, including Ch$ 447 billion1.2 trillion in debt that EGP Chile and Enel Chile incurred with Enel Finance International N.V.), and had the following maturity profile:
| | | | | | |
Maturity Profile of Our Consolidated Interest-Bearing Debt | ||||||
2021 |
| 2022-2023 |
| 2024-2025 |
| After 2025 |
(in billions of Ch$) | ||||||
159 | | 383 | | 608 | | 1,690 |
· Ch$ 329 billion in 2019;
· Ch$ 170 billion from 2020 to 2021;
· Ch$ 194 billion from 2022 to 2023; and
· Ch$ 1,786 billion thereafter.
We haveOur American Depositary Shares have been listed and traded on the NYSE since April 26, 2016, and may in2016. In the future, accesswe may again tap the international equity capital markets (including SEC-registered ADS offerings). Our subsidiary Enel Generation accessed the international equity capital markets, with a SEC-registered ADS offering on August 3, 1994. Enel Generation activelyWe also issued bonds in the United States (“Yankee Bonds”) in the past,2018 and we, on an individual basis, have issued bondsmay issue Yankee Bonds for US$ 1,000 million in 2018 and,the future depending on liquidity needs, may issue Yankee bonds in the future. Since 1996, Enel Generation and Pehuenche have issued a total of US$ 2.8 billion in Yankee Bonds.needs.
The following table lists ourthe Yankee Bonds issued by us and the aggregate principal amount outstanding as of December 31, 2018.2020:
| | | | | | | | | | |
| | | | | | | | Aggregate Principal Amount | ||
Issuer |
| Term |
| Maturity |
| Coupon |
| Issued |
| Outstanding |
| | | | | | | | (in millions of US$) | ||
Enel Chile | | 10 years | | June 2028 | | 4.875% | | 1,000 | | 1,000 |
|
|
|
|
|
|
|
| Aggregate Principal Amount |
| ||
Issuer |
| Term |
| Maturity |
| Coupon |
| Issued |
| Outstanding |
|
|
|
|
|
|
| (%) |
| (in millions of US$) |
| ||
Enel Chile |
| 10 years |
| June 2028 |
| 4.875 |
| 1,000 |
| 1,000 |
|
The following table lists the Yankee Bonds issued by our subsidiary, Enel Generation, and the aggregate principal amount outstanding as of December 31, 2018. The weighted average annual coupon interest rate for such bonds is 5.8%, without giving effect to each bond’s duration, or put options.2020:
|
|
|
|
|
|
|
| Aggregate Principal Amount |
| ||
Issuer |
| Term |
| Maturity |
| Coupon |
| Issued |
| Outstanding |
|
|
|
|
|
|
| (%) |
| (in millions of US$) |
| ||
Enel Generation |
| 10 years |
| April 2024 |
| 4.250 |
| 400 |
| 400 |
|
Enel Generation (1) |
| 30 years |
| February 2027 |
| 7.875 |
| 230 |
| 206 |
|
Enel Generation (2) |
| 40 years |
| February 2037 |
| 7.325 |
| 220 |
| 70.8 |
|
Enel Generation (1) |
| 100 years |
| February 2097 |
| 8.125 |
| 200 |
| 40 |
|
Total |
|
|
|
|
| 5.813 | (3) | 1.050 |
| 717 |
|
| | | | | | |
| | | | | Aggregate Principal Amount | |
Issuer | Term | Maturity | Coupon | | Issued | Outstanding |
| | | | | (in millions of US$) | |
Enel Generation | 10 years | April 2024 | 4.250% | | 400 | 400 |
Enel Generation(1) | 30 years | February 2027 | 7.875% | | 230 | 206 |
Enel Generation(2) | 40 years | February 2037 | 7.325% | | 220 | 71 |
Enel Generation(1) | 100 years | February 2097 | 8.125% | | 200 | 40 |
Total | | | 5.813% | (3) | 1,050 | 717 |
(1) | Enel Generation repurchased some of these bonds in 2001. |
(2) | Holders of the Enel Generation 7.325% Yankee Bonds due 2037 exercised a put option on February 1, 2009, for a total amount of US$ 149.2 million. The remaining US$ 70.8 million principal amount of the Yankee Bonds matures in February 2037. |
(3) | Weighted-average coupon by outstanding amount. |
(1) Enel Generation repurchased some of these bonds in 2001.
(2) Holders of the Enel Generation 7.325% Yankee Bonds due 2037 exercised a put option on February 1, 2009, for a total amount of US$ 149.2 million. The remaining US$ 70.8 million principal amount of the Yankee Bonds mature in February 2037.
(3) Weighted-average coupon by outstanding amount.
We also have access to the Chilean domestic capital markets. Our subsidiary, Enel Generation, has issued debt instruments including commercial paper and medium- and long-term bonds that arehave been primarily sold to Chilean pension funds, life insurance companies, and other institutional investors.
The following table lists UF-denominated Chilean bonds issued by Enel Generation that are outstanding as ofon December 31, 2018.2020:
|
|
|
|
|
| Coupon (inflation |
| Aggregate Principal Amount |
| ||||
Issuer |
| Term |
| Maturity |
| adjusted rate) |
| Issued |
| Outstanding |
| ||
|
|
|
|
|
| (%) |
| (in millions of UF) |
| (in millions of US$) |
| (in billions of Ch$) |
|
Enel Generation Series H |
| 25 years |
| October 2028 |
| 6.20 |
| 4.00 |
| 84.4 |
| 59 |
|
Enel Generation Series M |
| 21 years |
| December 2029 |
| 4.75 |
| 10.0 |
| 396.8 |
| 276 |
|
Total |
|
|
|
|
| 5 | (1) | 14.0 |
| 481.2 |
| 334 |
|
| | | | | | | |
| | | Coupon (inflation | | Aggregate Principal Amount | ||
Issuer | Term | Maturity | adjusted rate) | | Issued | Outstanding | |
| | | | | (in millions of UF) | (in millions of UF) | (in billions of Ch$) |
Enel Generation Series H | 25 years | October 2028 | 6.20% | | 4.00 | 1.71 | 49.77 |
Enel Generation Series M | 21 years | December 2029 | 4.75% | | 10.00 | 8.18 | 237.85 |
Total | | | 5.00% | (1) | 14.00 | 9.89 | 287.62 |
(1) Weighted-average coupon by outstanding amount.
(1) | Weighted-average coupon by outstanding amount. |
For a fullcomplete description of local bonds issued by Enel Generation, see “Unsecured liabilities detailed by currency and maturity” in Note 21.2 of the Notes to our consolidated financial statements.
88
We may also participate in the international and local commercial bank markets through syndicated or bilateral senior unsecured loans, including both fixed termfixed-term and revolving credit facilities. In 2020, we entered into a bilateral revolving loan for up to US$ 290 million with Enel Finance International N.V. The amounts outstanding or available under our syndicated and revolving loanloans as of December 31, 2018, is set forth2020, are summarized in the table below.
| | | | | | | | | ||||||
Borrower |
| Type |
| Maturity |
| Facility Amount |
| Amount Drawn | ||||||
| | | | | | (in millions of US$) | | (in millions of US$) | ||||||
|
|
|
|
| ||||||||||
Enel Chile | |
| |
| |
| | — | ||||||
Enel Chile | | Bilateral Revolving Loan | | June 2024 | | 50 | | — | ||||||
Enel Chile | | Bilateral Revolving Loan | | June 2021 | | 290 | | — | ||||||
Total | | | | | |
| | — |
Enel Generation’s undrawnThe syndicated revolving credit facility isfacilities are governed by the laws of the State of New York and doesYork. The disbursement is not contain a conditionsubject to the compliance of conditions precedent requirement regarding the non-occurrence of a “Material Adverse Effect” (or MAE, as defined contractually) prior to a disbursement,, thus allowing us fullcomplete flexibility to draw on it for up to US$ 200 million as of December 31, 2018, and as of the date of this Report from such committed revolving facilitiesa drawdown, under any circumstances including situations involving a MAE. On
December 21, 2018, we also entered into a 4-year revolving credit line with Enel International Finance N.V.an MAE, for up to US$ 400440 million with an availability period of 6 months, which as of December 31, 2018,2020, and were undrawn as of the date of this Report remained undrawn.March 31, 2021.
We may also borrow from banks in Chile under fully committed facilities, under which a potential MAE would not be an impediment toimpede this source of liquidity. In 2016,2019, Enel GenerationChile entered into a 3-year5-year bilateral revolving loan for an aggregate amount of UF 2.8Ch$ 34,000 million, (Ch$ 79 billion as of December 31, 2018) as set forthoutlined in the table below.
| | | | | | | | | |
Borrower |
| Type |
| Maturity |
| Facility Amount |
| Amount Drawn | |
| | | | | | (in millions of | | (in millions of | |
Enel | |
| |
| |
| | — |
This facility matured in March 2019 and was not renewed.
As a result, of the foregoing, we have access to fully committed undrawn revolving loans, both international and domestic, for up to Ch$ 495347 billion in the aggregate as of December 31, 2018,2020, and up to Ch$ 417 billion as of the date of this Report.March 31, 2021.
On January 12, 2018, we entered into a senior unsecured term loan credit agreement. The credit agreement provides for an 18-month facility, originally comprised of a Ch$ 667.9 billion Term A Loan Commitment and a US$ 900 million Term B Loan Commitment, and is governed by the laws of the State of New York. We entered into this credit agreement to fund the financial needs arising from the 2018 Reorganization. In March 2018, we drew down Ch$ 517.7 billion from the Term A Loan Commitment and US$ 697.5 million from the Term B loans Loan Commitment. This facility matures on July 12, 2019. This loan was substantially repaid with proceeds obtained from our first Yankee bond issuance in June 2018.
We and our subsidiaries also borrow routinely from uncommitted Chilean bank facilities with approved lines of credit for approximately Ch$ 5348 billion in the aggregate, none of which are currently drawn. Unlike the committed lines described above, which are not subject to aan MAE conditionscondition precedent prior to disbursements, these facilities are subject to a greater risk of not being disbursed in the event of a MAE, and thereforean MAE. Our liquidity could limit our liquiditybe limited under such circumstances.
We mayOn December 21, 2018, we entered into a 4-year revolving credit line with Enel Finance International N.V. for up to US$ 400 million. This loan was drawn entirely in June 2019 and became a bilateral term loan with maturity in December 2022. Additionally, on January 3, 2020, we entered into a loan agreement with Enel Finance International N.V. for a US dollar-denominated loan for a total of US$ 200 million, with a maturity in July 2023. On March 11, 2020, we entered into a loan agreement with Enel Finance International N.V. for a US dollar-denominated loan of US$ 400 million, with a maturity in March 2030.
EGP Chile has also accessaccessed the Chilean commercial paperbank market under programs that need to be registeredthrough a bilateral loan agreement, which as of December 31, 2020, totaled US$ 150 million, with the CMF. a final maturity in December 2021. EGP Chile also entered into a loan agreement with Enel Finance International N.V. for a US dollar-denominated loan, which as of December 31, 2020, had US$ 644 million outstanding, with a maturity in December 2027. EGP Chile also entered into subsidized financing with Interamerican Development Bank through a US dollar-denominated loan, which as of December 31, 2020, had US$ 30 million outstanding, with a maturity in November 2022.
In addition, in March 2018, we registered a 30-year local bond program with the CMF for UF 15 million (Ch$ 595436 billion as of December 31, 2018)2020). Finally, we can also access other types of financing, including supplier credits, leasing, among others.
EGP Chile has also accessed the Chilean bank market through bilateral loan agreements, which asAs of December 31, 2018, totaled Ch$ 278 billion, with a final maturity in December 2021. In addition, EGP Chile incurred in debt with Enel International Finance N.V. through a US dollar-denominated loan, which2020, and as of December 31, 2018, had US$ 644 million (Ch$ 447 billion) outstanding, with a maturity in December 2027.the date of this Report, there have been no issuances of bonds under this program.
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Only Enel Generation’s outstanding debt facilities, with the exception ofexcept their Yankee Bonds, include financial covenants. The types of financial covenants, and their respective limits, vary from one typekind of debt to another. As of December 31, 2018,2020, the most restrictive financial covenant affecting Enel Generation was the leveragedebt-to-equity ratio in connection with the bilateral revolving loan facility that matured in March 2019, and the syndicated senior unsecured loan that matures in February 2020. Under such covenants, the maximum additional debt that could be incurred without a breach is Ch$ 1,956 billion.UF-denominated Chilean bonds. As of December 31, 2018,2020, and as of the date of this Report, our subsidiaries are in compliancewe comply with the financial covenants contained in theirour debt instruments.
As is customary for certain credit and capital market debt facilities, a significant portion of our financial indebtedness is subject to cross defaultcross-default provisions. Each of the revolving credit facilitiesUF-denominated Chilean bonds described above, as well asand Yankee Bonds issued by us and Enel Generation havehas cross default provisions with different definitions, criteria, materiality thresholds, and applicability as to the subsidiaries that could give rise to a cross default.cross-default.
The cross default provision for our credit agreement executed in January 2018, governed byOur subsidiaries’ debt may trigger the laws of the State of New York, refers to defaults of the borrower, without reference to any subsidiary. Under such credit facility, only matured defaults of the borrower exceeding US$ 100 million qualify for a potential cross default when the principal exceeds US$ 100 million, or its equivalent in other currencies. In the case of a matured default above the materiality threshold, the revolving credit facility’s lenders would have the option to accelerate if lenders representing more than 50% of the aggregate debt of a particular outstanding facility chose to do so.
The cross default provisions for the Enel Generation revolving credit facility that is due in February 2020, governed by the laws of the State of New York, refers to defaults of the borrower, without reference to any subsidiary. Under such credit facility, only matured defaults of the borrower exceeding US$ 50 million qualify for a potential cross default when the principal exceeds US$ 50 million, or its equivalent in other currencies, although its subsidiaries do not have any financial obligation. In the case of a matured default above the materiality threshold, the revolving credit facility’s lenders would have the option to accelerate if lenders
representing more than 50% of the aggregate debt of the outstanding facility chose to do so. All of our and Enel Generation’s Yankee Bonds are unsecured and not subject to any guarantees by any of its subsidiaries or parent companies.
The local facility of Enel Generation was due in March 2019 and was not renewed.
The cross defaultcross-default provision of our Yankee Bonds may be triggered by our subsidiaries’ debt.Bonds. A matured default of Enel Generation or any of its subsidiaries could result in a cross defaultcross-default to the Yankee Bonds issued by usEnel Generation and by Enel Generationus if such matured default, on an individual basis, has a principal exceeding certain materiality thresholds. Enel Generation’s subsidiaries do not currently have any financial obligations. In the case of a matured default above the materiality threshold, holders of Yankee Bonds would have the option to accelerate if either the trustee or bondholders representing at least 25% of the aggregate debt of a particular series then outstanding chose to do so. Enel Generation’s local bonds do not have cross defaultcross-default provisions arising from its subsidiaries.
PaymentThe UF-denominated Chilean bonds provide that the cross-default can be triggered only by default of the issuer itself, in cases where the amount in default exceeds US$ 50 million in individual debt or its equivalent in other currencies. However, the acceleration must be requested in a meeting of bondholders by at least 50% of the bondholders of the affected series.
The payment of dividends and distributions by our subsidiaries and affiliates representrepresents an importantessential source of funds for us.funds. The payment of dividends and distributions by certain subsidiaries and affiliates are potentially subject to legal restrictions, such as legal reserve requirements, capital and retained earnings criteria, and other contractual restrictions.conditions. We are currently in compliance with the legal restrictions, and therefore, they currentlynow do not affect the payment of dividends or distributions to us. Certain credit facilities and investment agreements of our subsidiaries may restrict the payment of dividends or distributions in certain specialexceptional circumstances. For instance, one of Enel Generation’s UF-denominated Chilean bonds restricts the amount oflimits intercompany loans that Enel Generation and its subsidiaries are allowed tocan lend to related parties. The threshold for such aggregate restriction of intercompany loans is currently US$ 100 million, equal to approximately Ch$ 69 billion. After a liability management process carried out by Enel Generation, the threshold was increased to US$ 500 million (equal to Ch$ 347 million), which, as of the date of this Report, is still subject to the final approval by the CMF.million. For a description of liquidity risks resulting from our company status, please see “Item 3. Key Information — D. Risk Factors— We depend on payments from our subsidiaries to meet our payment obligations.”
Our estimated capital expenditures for 20192021 through 20212023 are expected to amount to Ch$ 1,3551,674 billion, which includes maintenance capital expenditures, investment in expansion projects under execution, such as those for Los Cóndores project, as well as water rights and expansion projects that are still under evaluation, in which case we would undertake them only if deemed profitable.
We do not currently anticipate liquidity shortfalls affecting our ability to satisfy the material obligations described in this Report. We expect to be able to refinance our consolidated indebtedness as it becomes due, fund our purchase obligations with internally generated cash, and fund capital expenditures with a mixture of internally generated cash and borrowings.
C.LIBOR TransitionResearch
The U.K. Financial Conduct Authority found that the London Interbank Offered Rate (“LIBOR”) had inconsistencies in its calculations and Development, Patentsrecommended that it be based on actual transactions. As a result, the authority agreed to stop requiring banks to comply with the submission of interbank rates to calculate LIBOR as of December 31, 2021. On March 5, 2021, LIBOR succession dates (December 31, 2021, for EUR, CHF, JPY, and Licenses, etc.GBP LIBOR for all tenors and one week and two-month USD LIBOR and June 30, 2023, for all other USD LIBOR tenors) were announced. LIBOR will be discontinued, and alternative benchmark rates are expected to replace it. Currently, there is no clear opinion about the benchmark rate that will replace LIBOR. Still, market participants expect that a risk-free rate, such as the Secured Overnight Financing Rate (“SOFR”), a broad measure of the cost of borrowing overnight collateralized by U.S. Treasury securities, to replace it, in the context of operations involving U.S. banks.
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This reform may affect us in the following ways:
(vii) | Interest payments on loans and derivatives: Financial risks arising from using a new benchmark rate, where interest payments previously based on LIBOR may increase or decrease. There is also a risk concerning data availability relating to the timely disclosure of market information, which may also affect the effectiveness of hedges. |
(viii) | Financial systems: Operational risk arising from the necessity to modify and adapt our financial systems to report, evaluate, or calculate payments under the new required benchmark rates. |
(ix) | Fair value measurement: Financial risks arising from how changes to benchmark rates in our debt obligations could adversely affect fair value measurements. |
(x) | Contracts: Legal and financial risk relating to the renegotiation of ISDA and local derivative contracts. |
As of March 31, 2021, our total debt exposure to LIBOR was US$ 550 million. Although we have debt obligations that refer to LIBOR that expire after 2021, all of them include provisions to transition from LIBOR to an alternative benchmark rate. However, at this time, we cannot determine the extent these changes will affect us.
Enel Chile has intercompany debt obligations that stipulate that if LIBOR is not available, a replacement rate quoted by reference banks chosen by lenders that are leaders in the European interbank market for deposits in U.S. dollars and a period comparable to the corresponding interest period may be used. Under a line of credit, intragroup operations must be promptly determined at market conditions. The proposed new reference rates will probably differ from LIBOR.
In 2020, we executed a Revolving Credit Facility Agreement (“RFA”) for up to US$ 290 million with Enel Finance International N.V. that provides for a replacement rate for LIBOR quoted by reference banks chosen by lenders that are leaders in the European interbank market. As of March 31, 2021, the agreement was undrawn.
In 2019, we executed a Senior Unsecured Revolving Credit Agreement (“SURCA”) for up to US$ 100 million that includes specific language regarding the replacement of LIBOR for an alternative rate of interest that accounts for the prevailing market convention for determining a rate of interest for syndicated loans in the United States at that later time. We also executed an RFA for up to US$ 50 million with Enel Finance International N.V. that stipulates a replacement rate for LIBOR quoted by reference banks chosen by lenders that are leaders in the European interbank market. As of March 31, 2021, the SURCA and RFA were undrawn.
Additionally, we have a term loan for US$ 400 million from Enel Finance International N.V. that stipulates a replacement rate for LIBOR quoted by reference banks chosen by lenders that are leaders in the European interbank market.
Our subsidiary EGP Chile has a bank loan for US$ 150 million with specific clauses providing for an alternative specified rate to replace LIBOR as a result of the reforms under discussion in the United Kingdom as of the date of the contract. The loan is due before December 31, 2021.
C. | Research and Development, Patents and Licenses, etc. |
None.
D. | Trend Information. |
Our subsidiaries are engagedengage in the generation, transmission, and distribution of electricity in Chile, which is undergoing changes includingChile. These sectors experience more restrictive government regulations, the introduction of new technologies and business models, and more competition. Our businesses are subject todepend on a wide range of conditions that may result in significant variability in our
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earnings and cash flows from year to year. We seek to establish a conservative and well-balanced commercial policy which aimsaimed at controlling relevant variables, reducing risks, and providing stability to our results of operations.
Generation
Our operating income is affected by several factors including contracted electricity prices, prevailing hydrological conditions, the price of fuels used to generate thermal electricity, contracted obligations, generation mix, and the electricity prices prevailing in the spot market, among others. With the consolidation of EGP Chile as of April 2018, we added 1,189 MW of installed capacity. We expect that NCRE will boost the growth of our generation business in the long term.
Sales prices and energy costs are among the main drivers of our results of operations of our electricity generation business.business results. The quantity of electricity sold has been generally stable over time, with increases reflecting economic and demographic growth. Our profits from contracted sales rely on our ability to generate or buy electricity at a cost lower than contracted prices. However, the applicable price for electricity sales and purchases in the spot market is much harder to predict because the spot generation price is influenced by several factors, including hydrology and fuel prices. Abundant hydrological conditions generally lower spot prices while dry conditions increase them, althoughthem. However, NCRE generation may partly mitigate this effect on prices may be partly mitigated with NCRE generation.prices.
Our operating income might not be adversely impacted adversely even when we are required tomust buy electricity at high prices in the spot market if our commercial policy is appropriately managed. Our goal is to have a conservative and well-balanced commercial policy that controls relevant variables, provides stability tostabilizes our profits and mitigates our exposure to the volatility of the spot marketmarket's volatility. We do so by contracting a significant portion of our expected electricity generation through long-term electricity supply contracts. The optimal level of electricity supply commitments is one that protects us against low marginal cost conditions, such as those existing during a rainy season, while still taking advantage of high marginal cost conditions, such as higher spot market prices during dry years. In order toTo determine the optimal mix of long-term contracts and sales in the spot market, we project our aggregate generation taking into considerationconsidering our diversified generation mix and the incorporation ofincorporating new projects under construction under dry hydrology. We then create demand estimates using standard economic theory and forecast the system’s marginal cost using proprietary stochastic models. We may also participate in the energy forward derivatives market, which allowsallowing us to negotiate volumevolumes and future price, in orderprices to ensure demand and avoid buying in the spot market, which has high volatility and risk.
Our sales contracts to customers not subject to regulated prices are not standardized, and the contractual terms and conditions are individually negotiated. When negotiating these contracts, we try to set the price at a premium over future expected spot prices to mitigate the risk of increases in future spot prices. However, the premium can vary substantially depending on several conditions such as node values, load profile, and the term of the contract. Our contracted sales with regulated customers represent on average more than 67%represented approximately 50% of our sales in 2020, allowing us to maintain steady prices for longermore extended periods, normallytypically 10 to 15 years, which, combined with our balanced commercial policy, generally provides for a stable profit. Most
With the consolidation of our current regulated tariffs are indexed to the U.S. CPI and, to a lesser extent, to commodity prices. We expect regulated tariffs to remain fairly stable, without material changes before 2021, with a downward trendEGP Chile as a result of the full integrationApril 2018, we added 1,189 MW of the two electricity systems, the former SIC (central and southern Chile) and SING (northern Chile), into one interconnected system, the SEN, since November 2017. This integration is expected to increase system generation efficiency, especially under extreme situations, and also improve investment and commercialization opportunities in both markets, mainly allowing for a higher dispatch of solar and wind power plants located in northern areas of Chile which will have a direct benefit to our own NCRE power plants located in that zone.installed capacity. We expect that NCRE will boost growth in our generation business.
We expect the Los Cóndores willhydro plant to be completed during 2020,by 2023, adding an average of 600 GWh of annual generation to our consolidated generation capacity. In 2022 and 2024, we expect significant price decreases, mainly due to the start of operations of projects tendered in 2016 and 2017, respectively, including our Campos del Sol, Cerro Pabellón 3extension, and Renaico II projects.
In 2022, distribution company contracts awarded to Enel Generation in the auction of August 2016 auction will come into effect and thereforeeffect. Therefore, we expect the tariffs of our regulated contractsagreements will decrease as a consequence ofdue to the lower prices offered by NCRE providers. In 2024, contracts awarded in the November 2017 auction the last such process, will come into effect with an average price of the total awardedallocated energy of US$ 32.5 per MWh, 32% lower than the average price of the previous tender process. The total amount of energy tendered was based on NCRE offers, representing a milestone in the industry. We were awarded 54% of the total tender of 2,200 GWh per annum, corresponding to 1,180 GWh per annum at an average price of US$ 34.7 per MWh with a mix of wind, solar, and geothermal generation which will be provided through NCRE projects backed upsupported by conventional energy.
We regularly 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 expectedprojected new capacity and allow us to stabilize our income. ConsideringSome of the resultslatest long-term power purchase agreements awarded are with the mining companies BHP Billiton (for 3 TWh per annum), Collahuasi (1 TWh per
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annum), and Anglo American (3 TWh per annum). Considering the last two tenderstenders' results for regulated customers, we expect to continue increasingincreased competition in the NCRE market competitiveness.market. As a result, offered prices will probablymay continue to decrease, but at a lower rate compared tothan previous years.
Spot prices could also be affected by international prices of fuel commodities such as fuel oil, coal and LNG, since Chile does not produce those fuels in any significant quantities. Fuel prices directly affect our thermal generation costs, which as of December 31, 2018, represented 37% of our installed capacity. Commodity prices, mainly oil, have significantly increased since their lowest level in the first quarter of 2016, characterized by a high volatility. The trend is expected to continue into 2019.
During the last few years, NCRE generation has grown much faster than expected, mainly as a consequence ofdue to the technological improvement in wind and solar technologies and the associated declining amount of capital required to deploy them. The government also established a regulated tender framework that allows the energy market to access this price reduction in the medium and long term. Currently, NCRE (solar,solar, wind and geothermal) generationgeothermal installed capacity represents 18%approximately 23% of the total market share,installed capacity in Chile, according to the monthly CEN report for March 2019. Currently,December 2020. EGP Chile has a competitive pipeline of projects with a short time-to-market, which is possible because of current commercial opportunities through PPA contracts.
For the period 2019-2021, we expect to invest Ch$ 1,355 billion in investments related to projects of current and future development, including research studies necessary to develop other generation and maintenance projects of distribution networks and existing generation power plants. By 2021, renewable projects under development are expected to increase the current installed capacity by 1.1 GW.
With respect to the development of new projects to increase our installed capacity, our strategy is to focus infocuses on creating synergies with plants in operation and obtaining economies of scale by combining existing plants with new NCRE projects to achieve greater competitiveness. We expect to continue competing in the future through PPA contracts, in partpartly associated with the migration of regulated customers from the distribution business, mainly mining and large industries, who are demandingdemand NCRE sources to reduce their energy costs and to clean their own carbon footprint. The continuous addition of NCRE power plants to the grid will require further transmission network reinforcement and market flexibility and focus on operational efficiency to combine the different technologies while maintaining the security and the system’s supply reliability, which is typically a NCRE weakness.reliability. Wind and solar sources are the NCRE sources most widely used NCRE sources. They have higher intermittency than other non-NCRE facilities sincebecause they can only generate electricity when the wind blows or the sun shines. Battery energy storage solutions will likely play a keyvital role in the next decade, providing a crucial solution for frequency control and grid stability in the context of significant wind and solar penetration.
Distribution
Distribution customers who can choose between regulated and unregulated tariffs are switchingcontinue to switch to unregulated tariffs, thereby becoming direct generation company customers and paying tolls to distribution companies. These customers are tenderingtender their energy needs, either directly or in association with other customers, because unregulated tariffs are currently lower than regulated tariffs that are based on contracts previously tendered in the past at higher prices. We expect this trend may continue in the future until lower cost contractslower-cost agreements are recognized in the regulated tariffs. Based on the latest tender processes, itthis difference in tariffs may last until 2024 with the recognition of the 2017 tendered prices in the regulated tariff.
We expect organic growth expansion in the distribution business, mainly coming from the digitalization of the network. We expectplan to invest in new technologies that will automate our networkssystems to achieve better operational and economic efficiency. The investment in theseNew technology includes smart meters, will be recognized in the regulated tariffs. These smart meterswhich allow bi-directional communication, digitized and interconnected networks, and also enable our consumers to improve their energy efficiency. We will continue investing in this technology since it will allow us to reduce costs mainly in remote meter reading without an inspector,on-site inspection, remotely manage the disconnection and reconnection processes, and improve response times to better address extreme weather emergencies better by significantly reducing failure recognition time. These instruments will also facilitate efficient maintenance that is more efficient, as well asand provide a necessary technical tool through which residential customers may inject their future excess energy into the electrical system.
Adverse Effects of the Covid-19 Pandemic
In February 2021, Chile began to implement a widespread vaccination program starting with a priority for the elderly, those with a greater health hazard, and those with greater exposure risk, such as those who work in health services. We expect that in 2021, the severe impact of Covid-19 will subside in relation to 2020 and anticipate a trend that at least partly reverses the negative consequences experienced last year. However, increases in infection rates as of March 2021 indicate a potential second wave of Covid-19. As a result, the Chilean government established new quarantine measures, placing more than 80% of the population in complete lockdown, including the entire Santiago metropolitan region. The government also announced the tightening of Chile’s borders through the month of April 2021. Chilean citizens and residents may enter Chile but are not allowed to depart from the country unless they qualify for exceptional consideration. Non-resident foreigners will not be allowed to enter Chile but will be permitted to depart from the country. We may also experience virus strains for which there are no known antibodies yet.
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Tariffs Stabilization Mechanism: Deferral of Electricity Distribution Tariffs
Due to the social crisis in October 2019, the Chilean government began implementing measures to address protesters’ social concerns. One of these measures established a mechanism for stabilizing electricity prices for regulated customers, the “Tariff Stabilization Mechanism.” It is related to Law No. 21,185 of the Ministry of Energy. The new law provides that regulated customer tariffs between July 1, 2019, and December 31, 2020, will remain at the levels prevailing as of June 30, 2019, and will not benefit from any indexation until December 31, 2020. This stabilized tariff is known as “Regulated Customer Stabilized Price” (“PEC” in its Spanish acronym).
From January 1, 2021, until the end of the Tariff Stabilization Mechanism, the tariffs will be those defined in the semi-annual decrees referred to in Article 158 of the Electricity Law but may not be higher than the PEC adjusted according to the consumer price index (the “adjusted PEC”). The difference between PEC or adjusted PEC and the rate that should have been charged under the applicable PPAs will create accounts receivable in favor of the generation companies. A price stabilization funding program was implemented by the CNE and is effectively financed by companies in the generation industry, including our subsidiary Enel Generation, through accounts receivable that are generated by the differences between the contractual rates and the stabilized rates, which are expected to enable the generation companies to recover the lost revenues by December 31, 2027. We may suffer a financial loss due to this revenue deferral because generation companies are being asked to finance such deferral. An agreement to sell up to US$ 290 million of the accounts receivables generated through this mechanism was executed with Goldman Sachs and the Inter-American Development Bank. Please see Note 9 of the Notes to our consolidated financial statements for further information.
The tariff deferral directly affects electricity generation companies by decreasing revenues, affecting their cash flows, and increasing the need to finance their operations. The maximum accounts receivable for the Tariff Stabilization Mechanism will be US$ 1,350 million, and the balance will be paid beginning July 1, 2023, through tariffs set above the PPA rates and must be collected no later than December 31, 2027. The regulator will issue semi-annual decrees that will identify the price of the contractual conditions of the PPAs, and the differences not collected under the PPAs, in their equivalent in U.S. dollars. These differences, in the form of accounts receivable, will not accrue interest, except that the balances not collected as of January 1, 2026, will accrue interest at the rate of six-month LIBOR, or the equivalent rate that replaces it, plus a spread corresponding to the country risk at the date of application.
E.Off-balance Sheet Arrangements.Reduction of the Profitability of Distribution Companies
The Ministry of Energy’s Law No. 21,194, published on December 21, 2019, lowered distribution companies’ profitability by (i) reducing the rate of return allowed on investment costs from a 10% annual rate in real terms to a rate in the range of 6-8% per annum; and (ii) forcing the after-tax rate of return of distribution companies not to differ by more than two percentage points above and three percentage points below the rate defined by the CNE.
Voluntary Retirement Program
In April 2021, the Company announced a Voluntary Retirement Program, open to men of at least 60 and women of at least 55 years old, with an incentive for qualifying employees who voluntarily anticipate their retirement. The program is one of the initiatives that the Group is promoting in the context of its digitization strategy in 2021-2024, enabling the adoption of new work and operation models, and demands new skills and knowledge to make processes more efficient and effective at a time when the transformation of the Company’s platforms and business processes is becoming increasingly relevant to the Company’s clients and stakeholders. As a consequence of this restructuring plan, the Company will account for an expense of approximately Ch$ 17.5 billion in 2021.
E. | Off-balance Sheet Arrangements. |
We are not a party to any off-balance sheet arrangements.
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F.Tabular DisclosureTable of Contractual Obligations.Contents
F. | Tabular Disclosure of Contractual Obligations. |
The table below sets forth our cash payment obligations as of December 31, 2018:2020:
|
| Payments due by Period |
| ||||||||
Ch$ billion |
| Total |
| 2019 |
| 2020-2021 |
| 2022-2023 |
| After 2023 |
|
Purchase obligations(1) |
| 12,776 |
| 4,023 |
| 3,977 |
| 3,393 |
| 1,383 |
|
Interest expense(2) |
| 1,086 |
| 128 |
| 242 |
| 211 |
| 505 |
|
Yankee bonds |
| 1,193 |
| — |
| — |
| — |
| 1,193 |
|
Local bonds(3) |
| 357 |
| 53 |
| 62 |
| 62 |
| 180 |
|
Financial Leases |
| 16 |
| 3 |
| 8 |
| 5 |
| — |
|
Pension and post-retirement obligations(4) |
| 57 |
| 7 |
| 8 |
| 7 |
| 35 |
|
Bank debt |
| 960 |
| 283 |
| 272 |
| 149 |
| 256 |
|
Total contractual obligations |
| 16,445 |
| 4,497 |
| 4,569 |
| 3,831 |
| 3,553 |
|
| | | | | | | | | | |
| | Payments Due by Period | ||||||||
Ch$ billion |
| Total |
| 2021 |
| 2022-2023 |
| 2024-2025 |
| After 2025 |
Purchase obligations(1) | | 8,769 | | 3,227 | | 3,000 | | 1,856 | | 686 |
Interest expense | | 936 | | 132 | | 235 | | 178 | | 392 |
Yankee bonds | | 1,221 | | — | | — | | 284 | | 936 |
Local bonds(2) | | 270 | | 30 | | 61 | | 54 | | 125 |
Lease obligations | | 68 | | 9 | | 15 | | 6 | | 38 |
Pension and post-retirement obligations(3) | | 76 | | 10 | | 11 | | 10 | | 45 |
Bank debt(2) | | 1,297 | | 107 | | 448 | | 229 | | 513 |
Total contractual obligations | | 12,637 | | 3,515 | | 3,770 | | 2,617 | | 2,736 |
2) | Represents net value, including derivatives. |
3) | Our pension and post-retirement benefit plans are unfunded. Cash flow estimates in the table are based on such obligations, including certain estimated variable factors such as interest. Cash flow estimates in the table relating to our unfunded plans are based on future discounted payments necessary to meet all of our pension and post-retirement obligations. |
(1) Includes generation and distribution business purchase obligations, which are comprised mainly of energy purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of Ch$ 8,404 billion, 65.8% corresponds to energy purchased for distribution, 23.3% corresponds primarily to fuel supply, maintenance of medium and
G. | Safe Harbor. |
The information contained in Items 5.E and 5.F containsincludes statements that may constitute forward-looking statements. See “Forward-Looking Statements” in the “Introduction” of this information statement,Report for safe harbor provisions.
Item 6.Directors, Senior Management, and Employees
A. | Directors and Senior Management. |
A.Directors and Senior Management.
Directors
Our Boardboard of Directorsdirectors consists of seven members who are elected for a three-year term at anthe Ordinary Shareholders’ Meeting (“OSM”). Following the end of their term, they may be re-elected or replaced. If a vacancy occurs in the interim, the Boardboard of Directorsdirectors will elect a temporary director to fill the vacancy until the next OSM, at which time the entire Boardboard of Directorsdirectors will be elected to afor new three-year term.terms. Our Executive Officersexecutive officers are appointed and hold office at the discretion of the Boardboard of Directors.directors.
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The members of our Boardboard of Directorsdirectors as of December 31, 20182020, were as follows:
Directors |
| Position |
| Age(1) |
| Current Position |
Herman Chadwick P. |
| Chairman |
| 74 |
| 2016 |
Salvatore Bernabei |
| Director |
| 46 |
| 2016 |
Pablo Cabrera G. |
| Director |
| 71 |
| 2016 |
Daniele Caprini |
| Director |
| 46 |
| 2018 |
Giulio Fazio |
| Director |
| 48 |
| 2016 |
Fernán Gazmuri P. |
| Director |
| 75 |
| 2016 |
Juan Gerardo Jofré M. |
| Director |
| 70 |
| 2016 |
| | | | | | |
Directors |
| Position | | Age(1) |
| Current Position |
Herman Chadwick P. | | Chairman | | 76 | | 2016 |
Salvatore Bernabei | | Director | | 47 | | 2016 |
Pablo Cabrera G. | | Director | | 73 | | 2016 |
Daniele Caprini | | Director | | 47 | | 2018 |
Giulio Fazio | | Director | | 50 | | 2016 |
Fernán Gazmuri P. | | Director | | 76 | | 2016 |
Juan Gerardo Jofré M. | | Director | | 71 | | 2016 |
| | | | | | |
(1) | As of April 30, 2021. |
(1) AsA new board of April 30, 2019.
At ordinary shareholders meetingdirectors was elected at the OSM held on April 25, 2018, the members of our Board of Directors were elected to28, 2021, for a three-year terms endingterm that ends in April 2021. During the Board of Directors’ meeting held on April 25, 2018, Mr. Chadwick was appointed Chairman and Messrs. Gazmuri, Cabrera and Jofré as members of the Directors’ Committee. Mr. Gazmuri was also appointed Financial Expert of the Directors’ Committee.2024.
Set forth below are brief biographical descriptions of the members of our Boardboard of Directors,directors, three of whom reside outside Chile and four of whom residelive in Chile, as of December 31, 2018:2020.
Herman Chadwick P.
Mr. Chadwick is a law partner at Chadwick & Cía. and a director of several companies unrelated to us, including Inversiones Aguas AndinasMetropolitanas, a Chilean holding company that owns a water utility company, and Viña Santa Carolina, a Chilean winery.winery, Centro de Estudios Públicos, a public policy think tank, and Carola, a mining company. Mr. Chadwick is an advisorchairman of the board and arbitrator at Centro de Arbitraje y Mediación de la Cámara de Comercio de Santiago, an association that provides arbitration services to resolve legal disputes.services. He is also vice-chairman of IntervialChile, a highway concession company. Mr. Chadwick holds a law degree from Pontificia Universidad Católica de Chile.
Salvatore Bernabei
Mr. Bernabei ishas been the Headhead of Global Procurementglobal procurement of Enel since May 2017. He has been Headwas head of Renewable Energiesrenewable energy Latin America of Enel Green Power (2016-2017) and Country Managercountry manager for Chile and the Andean Countries (2013-2016). He joined Enel in 1999 and has held several positions involving project integration, execution, inspection, operationsin engineering, construction, operation & maintenance, safety environment and logistics.quality of life. Mr. Bernabei holds a degree in industrial engineering from Università degli Studi di Roma “Tor“Tor Vergata”, and an MBA from Politecnico di Milano.
Pablo Cabrera G.
Mr. Cabrera is a member of the Chilean SocietySociedad Chilena de Derecho Internacional. Mr. Cabrera was director of International Law. Mr. CabreraAcademia DiplomáticaAndrés Bello (2010-2014) and served concurrently as ambassador to the Holy See, to the Sovereign Military Order of Malta and Albania (2006-2010), to the People’s Republic of China (2004-2006) to, Russia and Ukraine (2000-2004) and to the UKUnited Kingdom and Ireland (1999-2000). He also headed the Subsecretaría de Marina de Chile (1995-1999). Mr. Cabrera holds a law degree from Pontificia Universidad Católica de Chile and is a certified career diplomat from Academia DiplomDiplomáticaática Andrés Bello.
Daniele Caprini
Mr. Caprini ishas been the Headhead of Enel’s Group Planning and Reporting andControl for Enel SpA since 2018. He was the CFO of Enel Colombia since 2016.(2016-2017). He headed Enel’s Financial Valuation and Investment Control (2013-2015), Management Control (2015-2016) and Strategic Planning M&A and Financial Valuation (2009-2013) of Enel Green Power S.A. Mr. Caprini holds a degree in economics from the Università degli Studi di Siena and an MBA from Roma Università LUISS.
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Giulio Fazio
Mr. Fazio ishas been the Headhead of Enel’s Legal and Corporate Affairs since January 2016. Previously he held a comparablesimilar position at Enel Green Power S.p.A. (2008-2014). Since 2004, he has worked in finance and antitrust operations in Enel’s Legal Department.legal department. Mr. Fazio first joined an Enel affiliate in 1996. He holds a degree in law and a Ph.D. from Università degli Studi di Palermo.
Fernán Gazmuri P.
Mr. Gazmuri has been a board memberserved on the boards of companies unrelated to us. He is Currently Vice Chairmancurrently vice-chairman of Invexans S.A., a holding company that owns NEXANS, a French telecom and Maritime Cable Companymaritime cable company, and a Directorchairman of Citroën Chile S.A.C., He has been chairman of the Chilean Security Association, Invexans S.AAsociación Chilena de Seguridad, and vice-chairman of the Sociedad de Fomento Fabril (SOFOFA) and Asociación Nacional Automotriz de Chile. InFrom 2013-2016, he was director of Empresa Nacional del Petróleo (ENAP), the Chilean state-owned oil company and Vice-Chairmancompany. He was vice-chairman of the Chilean International Chamber of Commerce.Commerce of Chile from 2005-2009. In 2016, Mr. Gazmuri was awarded the Jorge Alessandri Rodríguez distinction by the Asociación de Industriales Metalúrgicos y Metalmecánicos, due to his outstanding professional and business career. In 2014, Mr. Gazmuri was awarded the Ordre national du Mérite by the Republic of France. He holds a degree in business administration from Pontificia Universidad Católica de Chile.
Juan Gerardo Jofré M.
Mr. Jofré is a director of CAP S.A., a mining and steel company, and a member of the self-regulatory council of the Asociación de Aseguradores de Chile, the insurance companies association. InFrom 2010-2014, he was Chairmanchairman of the Boardboard of Codelco, the Chilean state-owned copper mining company. He has been a director of Enel Generation and several prominent Chileanunrelated companies, unrelated to us,including Latam Airlines S.A., D&S S.A., Viña San Pedro S.A. and Sociedad Química y Minera de Chile, S.A., Banco Santander Chile, among others. He has held several managerial positions, primarily in Banco with Santander Chile and affiliates.Group. He holds a degree in business administration from Pontificia Universidad Católica de Chile.Chile.
Executive Officers
Set forth below are our Executive Officersexecutive officers as of December 31, 2018.2020:
Executive Officers |
| Position |
| Age(1) |
| Joined Enel or |
| Current Position |
Paolo Pallotti |
| Chief Executive Officer |
| 56 |
| 1990 |
| 2018 |
Angel Barrios R. |
| IT Officer |
| 49 |
| 1994 |
| 2018 |
Juan José Bonilla A. |
| Procurement Officer |
| 40 |
| 2010 |
| 2018 |
Raffaele Cutrignelli |
| Internal Audit Officer |
| 38 |
| 1995 |
| 2016 |
Marcelo Antonio de Jesus |
| Chief Financial Officer |
| 49 |
| 2018 |
| 2018 |
Monica De Martino |
| Regulatory Affairs Officer |
| 43 |
| 2011 |
| 2017 |
Alison Dunsmore M. |
| Services Officer |
| 39 |
| 2005 |
| 2018 |
José Miranda M. |
| Communications Officer |
| 37 |
| 2014 |
| 2016 |
Antonella Pellegrini |
| Sustainability Officer |
| 57 |
| 2000 |
| 2017 |
Andrés Pinto B. |
| Safety Officer |
| 40 |
| 2010 |
| 2017 |
Liliana Schnaidt H. |
| Human Resources Officer |
| 40 |
| 2009 |
| 2018 |
Claudia Navarrete C. |
| Planning and Control Officer |
| 46 |
| 1998 |
| 2018 |
Pedro Urzúa F. |
| Institutional Affairs Officer |
| 49 |
| 2012 |
| 2016 |
Domingo Valdés P. |
| General Counsel |
| 55 |
| 1993 |
| 2016 |
| | | | | | | | |
Executive Officers |
| Position | | Age(1) | | Joined Enel |
| Current Position |
Paolo Pallotti | | Chief Executive Officer | | 58 | | 1990 | | 2018 |
Giuseppe Turchiarelli | | Chief Financial Officer | | 50 | | 1998 | | 2019 |
Eugenio Belinchon | | Internal Audit Officer | | 44 | | 1998 | | 2020 |
Liliana Schnaidt H. | | Human Resources Officer | | 41 | | 2009 | | 2018 |
Domingo Valdés P. | | General Counsel | | 57 | | 1993 | | 2016 |
(1) | As of April 28, 2021. |
(1) As of April 30, 2019.
Set forth below are brief biographical descriptions of our Executive Officers,executive officers, all of whom reside in Chile.
Paolo Pallotti: Mr. Pallotti was the CFO of Enel Américas inuntil 2018. He played a keycrucial role in various Enel corporate reorganization processes. He has beenserved as CFO of Enel’s Italian businesses (2014-2018), Financial Directorfinancial director of Enel’s Infrastructure & Networks division (2012), and director of Enel Energia S.p.A. (2015-2018) and Enel Italia S.r.L (2017-2018). He holds a degree in electronic engineering from Università degli Studi di Ancona.
Angel Barrios R.: Giuseppe Turchiarelli:Mr. BarriosTurchiarelli has held severalprominent financial positions related to Information Systems, including Head of ICT, a subsidiaryin Enel since 1998, among which he served as CFO of Enel Chile (2014-2018). Mr. Barrios holds a degreeLatin America BV (2009-2011), CFO for renewable generation in civil engineeringItaly and Europe (2001-2012), head of Planning and Control of the Enel Green Power group (2012-2013), CFO for Iberia and Latin America (2013-2015), head of Planning and Control in informatics from Universidad Santa MaríaItaly (2015-2017), and a master’s degree in Information Technology from Universidad Santa María.
Juan José Bonilla A.: Mr. Bonilla was CEO of EGP Chile in 2017CFO for Europe and was Operation and Maintenance Manager of EGP North America (2014-2016)Africa (2017-2019). Before, he held managerial positions at EGP including Head of Wind Maintenance and Technical Support. He holds a degree in industrial engineerbusiness administration from Escuela Superior de Ingenieros Industriales de Madrid,Università degli Studi di Cagliari and an executive MBA from ESERPLUISS Business School,.
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Eugenio Belinchon: Mr. Belinchon has held various responsibilities in the Internal Audit function for Enel in Europe and a master’s degree from Universidad San Pablo - CEU.
Raffaele Cutrignelli: Mr. Cutrignelli wasLatin America since 1998. He served as head of Enterprise Risk Management for the Iberia-Latam region (2009-2013). In 2014, he returned to Internal Audit, Officer for Codensa and Emgesa (2015-2016) andserving in different capacities at the Head of Latin American Audit for EGPlevel. He served as an audit manager and compliance officer in Brazil (2013-2015)Colombia (2016-2019). Mr. CutrignelliHe holds a degree in international businesseconomics from Nottingham TrentComplutense University and a master’s degree in audit and internal controls from Universitá di Pisa.
Marcelo Antonio de Jesus: Mr. de Jesus was CFO at Eletropaulo and a member of the Business Council of AES Group companies and held finance positions at TAM Linhas Aéreas S.A,Latam Airlines Group, Flora Higiene y Belleza, Syngenta and AES Latin America & Caribbean. He graduated from Universidad de São Caetano do Sul Business School and holds a master’s degree in business administration from Dom Cabral Foundation.
Mónica De Martino: Ms. De Martino was Head of EGP Regulatory Affairs Latin America (2011-2017). She holds a degree in political science from Libera Università Internazionale degli Studi Sociali Guido Carli, an MBA from Columbia Business School and a graduate degree from London Business School.
Alison Dunsmore M.: Ms. Dunsmore has held various Enel positions including Head of Commercial Management (2013-2015) and Chief of Staff and Head of Strategic Planning (2015-2017). Ms. Dunsmore holds a degree in civil industrial engineer from Universidad de Santiago de Chile.
José Miranda M.: Before joining Enel, Mr. Miranda worked for eleven years at Televisión Nacional de Chile, a state-owned Chilean TV channel. He is an audiovisual communicator with a degree from DUOC UC and a graduate degree in management from Universidad de Chile.
Antonella Pellegrini: Ms. Pellegrini has held managerial positions in business development and sustainability for EGP affiliates since 2014. She holds a degree in marketing and communications from Istituto Europeo di Design.
Andrés Pinto B.: Mr. Pinto has held managerial positions in project planning, cost control and operations for Enel affiliates since 2010. Mr. Pinto holds a degree in civil engineering from Pontificia Universidad Católica de Chile.
Claudia Navarrete C.: Ms. Navarrette held management positions in analysis and financial control in 2012-2018. Ms. Navarrete holds a degree in civil engineering, a master’s degree in computer science and anexecutive MBA from Pontificia Universidad CatólicaInstituto de ChileEmpresa.
Liliana Schnaidt H.: Ms. Schnaidt held positions in EGPEnel Green Power business development, with a focusfocusing on solar energy (2009-2018). Ms. SchnaidtShe holds a degree in civil engineering from Pontificia Universidad Católica de Chile.
Pedro Urzúa F.: Mr. Urzúa has been Institutional Affairs Officer for Chile and the Andean Countries for EGP (2012-2016), Director of Corporate Affairs of ENAP (2009-2012), director of Fundación Acción RSE (2012) and Communications Director of ENAP Sipetrol (2009-2012). He a holds a degree in journalism from Universidad de Artes y Ciencias de la Comunicación.
Domingo Valdés P.: Mr. Valdés is the Secretarygeneral counsel of the Boards of Directors ofLegal and Corporate Affairs for both Enel Américas and Enel Chile and Enel Américas andserves as secretary of both their boards of directors. He is a Professortenured professor of Economiceconomic and Antitrust Lawantitrust law at Universidad de Chile. and graduated summa cum laude from its law school. Mr. Valdés also holds a law degree from Universidad de Chile and a master’ in law degreean LL.M. from the University of Chicago.
B.Compensation.Chicago.
B. | Compensation. |
At the OSM held on April 25, 2018,28, 2021, our shareholders approved theour board of directors’ compensation policy for our Board of Directors.policy. Director compensation consists of a monthly fixed compensation of UF 216 per month and an additional fee of UF 79.2 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings, within the respective fiscal year. The Chairmanchairman of the Boardboard is entitled to double the compensation of other directors.
TheOur Directors Committee members of our Directors’ Committee are paid a monthly fixed compensation of UF 72 per month and an additional fee of UF 26.4 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings. The monthly fees (fixed and variable) are considered as advances on the annual variable fee.
If a director serves on one or more Boardsboards of Directorsdirectors of the subsidiaries and/or associate companies or serves as director of other companies or corporations in whichwhere the economic group holds an interest directly or indirectly, the director can only receive compensation from one of these Boards of Directors.boards.
Executive Officers of our Company and/Our Company’s, subsidiaries’, or of our subsidiaries or associate companiesaffiliates’ executive officers will not receive compensation in the case thatif they serve as directordirectors of any other affiliate. However, compensationthe officer may be received by the officerreceive compensation to the extent that it is expressly and previously authorized as an advance payment of the variable portion of the wage to be paid by the affiliate with which the officer signed a contract.
In 2018,2020, the total compensation paid to each of our directors, including fees for attending Directors’Directors Committee meetings, was as follows:
| | | | | | | | | | | | | |||||||||||
Director |
| Fixed |
| Ordinary and |
| Directors’ |
| Ordinary and |
| Total |
|
| Fixed |
| Ordinary and Extraordinary Session | | Directors | | Ordinary and Extraordinary Session (Directors Committee) | | Variable |
| Total |
|
|
|
|
|
| (in Th Ch$) |
|
|
|
|
| ||||||||||||
| | (in ThCh$) | |||||||||||||||||||||
Herman Chadwick P. |
| 133,016 |
| 48,773 |
| — |
| — |
| 181,789 |
| | 148,808 | | 59,109 | | — | | — | | — | | 207,918 |
Salvatore Bernabei |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Salvatore Bernabei(1) | | — | | — | | — | | — | | — | | — | |||||||||||
Pablo Cabrera G. |
| 66,508 |
| 24,386 |
| 22,176 |
| 8,842 |
| 121,912 |
| | 74,404 | | 29,555 | | 24,801 | | 9,852 | | — | | 138,612 |
Daniele Caprini |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Giulio Fazio |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Daniele Caprini(1) | | — | | — | | — | | — | | — | | — | |||||||||||
Giulio Fazio(1) | | — | | — | | — | | — | | — | | — | |||||||||||
Fernán Gazmuri P. |
| 66,508 |
| 24,386 |
| 22,176 |
| 8,842 |
| 121,912 |
| | 74,404 | | 29,555 | | 24,801 | | 9,852 | | — | | 138,612 |
Juan Gerardo Jofré M. |
| 66,508 |
| 24,386 |
| 22,176 |
| 8,842 |
| 121,912 |
| | 74,404 | | 29,555 | | 24,801 | | 9,852 | | — | | 138,612 |
Total |
| 332,540 |
| 121,931 |
| 66,527 |
| 26,526 |
| 547,525 |
| | 372,021 | | 147,774 | | 74,404 | | 29,555 | | — | | 623,753 |
(1) | Messrs. Bernabei, Caprini, and Fazio waived their compensation as directors of the Company due to their positions as employees of other companies in Enel. |
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We do not disclose to our shareholders or otherwise, any information about an individual Executive Officer’sexecutive officer’s compensation. Executive Officersofficers are eligible for variable compensation under a bonus plan. The annualyearly bonus plan is paid to our Executive Officersexecutive officers for achieving company-wide objectives and for their individual contribution to our results and objectives.goals. The annual bonus plan provides for a range of bonus amounts according to seniority level and consists of a certain multiple of gross monthly salaries. For the year ended December 31, 2018,2020, the aggregate gross compensation, paid orand accrued, for all of our Executive Officers,executive officers, attributable to the fiscal year 2018,2020, was Ch$ 2,676 million in fixed compensation and 2.6 billion, including Ch$ 765419 million in variable compensation and benefits.
We entered into severance indemnity agreements with all of our Executive Officers, pursuant to which weexecutive officers. We will pay a severance indemnity in the event offor voluntary resignation or termination by mutual agreementunderstanding among the parties. The severance indemnity does not apply if the termination is due to willful misconduct, prohibited negotiations, unjustified absences, or abandonment of duties, among other causes, as defined in Article 160 of the Chilean Labor Code. All of our employees are entitled to legala severance payindemnity if terminated due to our needs, as defineddescribed in Article 161 of the Chilean Labor Code.
The total amounts accrued as of the end of 2018 to provideWe did not pay severance indemnity to our Executive Officers totaled Ch$ 391.4 million.executive officers in 2020. There are no other amounts set aside or accrued to provide for pension, retirement or similar benefits for our Executive Officers.executive officers.
C. Board Practices.
Our Boardcurrent board of Directors in office as of December 31, 2018,directors was elected at the OSM held on April 25, 2018,28, 2021, for a three-year term that ends in April 2021.three years. For information about eachthe directors in office as of the directorsDecember 31, 2020, and the year that they began their service on the Boardboard of Directors,directors, see “Item 6. Directors, Senior Management and Employees — A. Directors and Senior Management” above. Members of the Boardboard of Directorsdirectors do not have service contracts with us or with any of our subsidiaries that provide them benefits upon the termination of their service.
Corporate Governance
We are managed by a Boardboard of Directors, in accordance withdirectors, following our bylaws, consisting of seven directors who are elected by our shareholders at anthe OSM, each of whom servesserving for a three-year term. Following the end of their term,terms, they may be re-elected indefinitely or replaced. Staggered terms are not permitted under Chilean law. If a vacancy occurs on the Boardboard of Directorsdirectors during the three-year term, the Boardboard of Directorsdirectors may appoint a temporary director to fill the vacancy. A vacancy triggers an election for every seat on the Boardboard of Directorsdirectors at the next OSM.
Chilean corporate law provides that a company’s Boardboard of Directorsdirectors is responsible for the managementmanaging and representation ofrepresenting a company in all matters concerning its corporate purpose, subject to theits bylaws’ provisions of the company’s bylaws, and the shareholders’ resolutions. In addition to the bylaws, our Boardboard of Directorsdirectors has adopted regulations and policies that guide our corporate governance principles.
Our corporate governance policies are mainly included in the following policies or procedures: the Manual for the Management of Information of Interest to the Market (the “Manual”), the Human Rights Policy (Política de Derechos Humanos), the Code of Ethics, and athe Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Penal Risk Prevention Model, the “Guidelines 231: Guidelines applicable to non-Italian subsidiaries in accordance with Legislative Decree 231 of June 8, 2001”Enel Global Compliance Program on Corporate Criminal Liability (the “Guidelines 231”“Enel Global Compliance Program”), the Risk Management and Control System, and procedures issued in compliance with General Norm Regulation 385 (“NCG 385” in its Spanish Acronym), issued by the CMF.CMF, which deals with corporate governance matters.
In order toTo ensure compliance with Securities Market Law 18,045 and CMF regulations, our Boardboard of Directorsdirectors approved the Manual at theits meeting held on February 29, 2016 and2016. It ratified such decision at its meeting held on March 23, 2016. This document addresses applicable standards regarding the information in connection with transactions of our securities and those of our affiliates, entered into by directors, management, principal executives, employees, and other related parties, the existence of blackout periods for such transactions undertaken by directors, principal executives and other related parties, the existencepresence of mechanisms for the continuous disclosure of information that is of interest to the market and mechanismstools that provide protection forprotect confidential information. The Manual was released to the public in 2016 and it is posted on our website at www.enelchile.cl.www.enelchile.cl. The provisions of this Manual apply to theour board members of our Board, as well asand our executives and employees who have access to confidential information, and especially those who work in areas related to the securities markets.
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Our Boardboard of Directorsdirectors approved a procedure for relationships between Politically Exposed People (Procedimiento Personas Políticamente Expuestas y Conexas) and our Company, which established a specific regulation for their commercial and contractual relationships.
The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into the corporate reality.
In orderOur board of directors also approved the Code of Ethics and the ZTAC Plan to supplement the aforementioned corporate governance regulations, our Board of Directors approved a Code of Ethics and a ZTAC Plan at its first meeting held on February 29, 2016 and ratified such decision at its meeting held on March 23, 2016.regulations. The Code of Ethics is based on general principles such as impartiality, honesty, integrity, and other ethical standards of similarequal importance, all of which are expected from our employees. The ZTAC Plan reinforces the principles included in the Code of Ethics but with special emphasis onprinciples, emphasizing avoiding corruption in the form ofthrough bribes, preferential treatment, prohibition of political donations under all circumstances and other similar matters.
In order to comply with Law 20,393 enacted on December 2, 2009, which imposes criminal responsibility on legal entities for the crimesOur board of asset laundering, financing of terrorism and bribing of public officials, our Board of Directorsdirectors approved the Penal Risk Prevention Model at its first meeting held on February 29, 2016 and ratified such decision at its meeting held on March 23, 2016.the Enel Global Compliance Program. The Penal Risk Prevention Model satisfies the standards imposed by Chilean Law 20,393, which imposes criminal responsibility for legal entities for certain crimes, including money laundering, financing of terrorism, and bribery of public officials. The law encourages companies to adopt this model, whose implementation involves compliance with managerial and supervision duties. The adoption of the Penal Risk Prevention Model mitigates, and in some cases relieves, the effects of criminal responsibility even when a crime is committed.
At its meeting held on October 27, 2016, our Board approved “The In turn, the Enel Global Compliance Program is designed as a tool to reinforce the group’s commitment to the highest ethical, legal, and professional standards for Corporate Penal Liability”,enhancing and preserving the group’s reputation. It sets several preventive measures for corporate criminal liability.
We follow the Risk Management and Control System guidelines defined by Enel for the standards, procedures, and systems applied at different levels of our companies to identify, analyze, evaluate, manage, and communicate risks. Each of our companies defines its risk management, control, and management policy, which was incorporated intois reviewed and approved at the Penal Risk Prevention Model to reflect current standards and appointed Mr. Rafael Cutrignelli as our Penal Risk Prevention and Global Compliance Program for Corporate Penal Liability Officer, as requiredbeginning of each year by the Penal Risk Prevention Model. Mr. Cutrignelli also serves as Internal Audit Officer for both of Enel Américas and Enel Chile.
On February 29, 2016, ourits Board of Directors, also approved the Guidelines 231observing and ratified such decision at its meeting held on March 23, 2016.applying local requirements in terms of risk culture, specific procedures concerning certain risks, corporate functions, or group businesses. The Guidelines 231 is defined by Italian Legislative Decree 231, which was enacted on June 8, 2001. It establishes a compliance program that identifies the behaviors expected of related parties for the non-Italian subsidiaries of Enel. Given that our ultimate controlling shareholder, Enel, complies with Italian Legislative Decree 231, which establishes management responsibility for Italian companies as a consequence of certain crimes committed in Italy or abroad, in the name of or for the benefit of such entities, including those crimes described in Chilean Law 20,393, these guidelines set a group of measures, with standards of behavior expected from all employees, advisers, auditors, officials, directors as well as consultants, contractors, commercial partners, agentspolicies include limits and suppliers. Legislative Decree 231 includes various activities of a preventive natureindicators that are coherent withsubsequently monitored.
The Risk Control area is ISO 31000:2018 (G31000) certified and integralacts under the guidelines of these international standards. The primary objective is to identify internal and external risks preemptively and to analyze, evaluate, and quantify the requirementsprobability of their occurrence and compliance with Chilean Law 20,393, which deals withimpact on our companies. Each area manages risks using mitigation measures stipulated in action plans. In the criminal responsibilityrisk management phase, necessary actions determined by internal policies and procedures are considered. The strict observance of legal entities. These guidelines are supplementaryISO and OHSAS international standards and governmental regulations may require risk management actions to the standards included in the Code of Ethicsbe documented to guarantee good governance practices and the ZTAC Plan.ensure business continuity.
On November 29, 2012,In 2015, the CMF issued General Regulation 341, which established regulations for the disclosure of information with respectNCG 385 to theenhance transparency standards ofand introduce corporate governance compliance adoptedsocial responsibility practices by promoting, among other things, management diversity. All publicly held limited liability corporations and set the procedures, mechanisms and policies that are indicated in the Appendix to the regulation. The objective of this regulation isrequired to provide credible information to investors with respect to good corporate governance policies and practices adopted by publicly held limited liability corporations, which include us, and permit entities like stock exchanges to produce their own analyses to help the various market participants to understand and evaluate the commitment of companies. General Regulation 341 was substituted by General Regulation 385, issued by the CMF, on June 8, 2015. This regulation has similar objectives thanan annual basis, with answers to a survey related to the former General Regulation 341, but includes additional issues, byboard’s functions and composition; relationships between the way of separating each policy into several more detailed policies. Subjects such as non-discrimination, inclusioncompany, shareholders and sustainability are particularly importantpublic in this new regulation.general; third-party assessments; and internal control and risk management. The Appendix of General RegulationNCG 385 is divided into the following four sections with respect toconcerning which companies must report the corporate practices that have been adopted: (i) the functioning and composition of the board, (ii) relations between the company, shareholders and the general public, (iii) risk management and control, and (iv) assessment by a third party. Publicly held limited liability corporations should send the information with respect toconcerning corporate governance practices to the CMF, no later than March 31 of eachevery year, using the Appendix’s contents of the Appendix to this regulation as criteria. If none of them is adopted, the company must explain its reasons to the CMF. The information should refer to December 31 of the calendar year prior to its dispatch. At the same time,that just ended. Simultaneously, such information should also be at the public’s disposal on the company’s website and must be sent to the stock exchanges.
In 2018, the board of directors approved a policy dealing with environmental and biodiversity issues. Environmental, social, and corporate governance criteria (“ESG”) are integrated into our business model. In compliance with NCG 385, the board periodically receives reports by management to identify and assess of all risks associated with ESG and climate change issues, including compliance with board policies.
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Compliance with the New York Stock Exchange Listing Standards on Corporate Governance
The following is a summary ofsummarizes the significant differences between our corporate governance practices and those applicable to U.S. domestic issuers under the NYSE’s corporate governance rules of the NYSE.rules.
Independence and Functions of the Directors’Directors Committee (Audit Committee)
Chilean law requires that at least two thirdstwo-thirds of the Directors’Directors Committee be independent directors. AccordingThe CMF may, by a general norms’ regulation, set forth the requirements and conditions that must be met by board members to be independent directors. Notwithstanding the above, according to Article 50 bis of Law No.18,046,No. 18,046, a member would not be considered independent if, at any time, within the last 18 months he: (i) maintainedhad any relationship of a relevant nature and amount with the company, with other companies of the same group, with its controlling shareholder, or with the principal officers of any of them or has been a director, manager, administrator, or officer of any of them;them (being the CMF authorized to set forth the criteria of what will be deemed “relevant nature and amount”); (ii) maintainedhad a family relationship with any of the members described in (i) above; (iii) has been a director, manager, administrator or principal officer of a non-profit organization that has received contributions from (i) above; (iv) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of an entity that has provided consulting or legal services for a relevant consideration or external audit services to the persons listed in (i) above; and (v) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator, or principal officer of the principaltop competitors, suppliers, or customers. In case there are not sufficientenough independent directors on the Boardboard to serve on the Directors’Directors Committee, Chilean law determines that the independent director nominates the rest of the Directors Committee members of the Directors’ Committee among the remaining Boardboard members that do not meet the Chilean law independence requirements. Chilean law also requires that all publicly held limited liability stock corporations that have a market capitalization of at least UF 1,500,0001.5 million (Ch$ 41343.6 billion as of December 31, 2018)2020) and at least 12.5% of its voting shares are held by shareholders that individually control or own less than 10% of such shares, must have at least one independent director and a Directors’Directors Committee.
Under the NYSE corporate governance rules, all members of the Audit Committee must be independent. The Audit Committee of a U.S. company must perform the functions detailed in, and otherwise comply with, the requirements of NYSE Listed Company Manual Rules 303A.06 and 303A.07. As of July 31, 2005, non-U.S. companies have been required to comply with Rule 303A.06, but not with Rule 303A.07. We currently comply with the independence and the functional requirement of Rule 303A.06. Since our incorporation on March 1, 2016, we have complied with the independence and the functional requirement of Rule 303A.06.
Pursuant toUnder our bylaws, all Directors Committee members of the Directors’ Committee must satisfy the requirements of independence, as stipulated by the NYSE. The Directors’Directors Committee is composed ofcomprises three members of the Board andboard. It complies with Article 50 bis of Law No.18,046, as well as withNo. 18,046 and the criteria and requirements of independence prescribed by the Sarbanes-Oxley Act (“SOX”), the SEC, and the NYSE. As of the date of this Report date, the Directors’Directors Committee complies with the conditions of the Audit CommitteeCommittee’s conditions as required by the SOX, the SEC, and the NYSE corporate governance rules. As a result, we have a single Committee, the Directors’Directors Committee, which includes among its functions the duties performed by an Audit Committee.Committee among its functions.
Our Directors’Directors Committee performs the following functions:
● | reviews of financial statements and the reports of the external auditors before their submission for shareholders’ approval; |
● | presents proposals to the board of directors, who then undertake their recommendations to shareholders meetings, for the selection of external auditors and private rating agencies; |
● | reviews information related to our transactions with related parties and reports the opinion of the Directors Committee to the board of directors; |
● | proposes to the board of directors a general policy on conflicts of interests, as well as reviews the related-party policy; |
● | examines the compensation framework and plans for managers, executive officers, and employees; |
● | prepares an Annual Management Report, including recommendations to shareholders; |
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● | provides information to the board of directors about the convenience of recruiting external auditors to provide non-auditing services, when such services are not prohibited by law, depending on whether such services might affect the external auditors’ independence; |
● | oversees the work of external auditors; |
● | reviews and approves of the annual auditing plan by the external auditors; |
● | evaluates the qualifications, independence, and quality of the auditing services; |
● | elaborates policies regarding the employment of former members of the external auditing firm; |
● | reviews and discusses problems or disagreements between management and external auditors regarding the auditing process; |
● | establishes procedures for receiving and dealing with complaints regarding accounting, internal controls, and auditing matters; |
● | carries out other functions mandated to the Committee by the bylaws, our board of directors, or our shareholders. |
· review of financial statements and the reports of the external auditors prior to their submission for shareholders’ approval;
· present proposals to the Board of Directors, which will make its own proposals to shareholders’ meetings, for the selection of external auditors and private rating agencies;
· review of information related to our transactions with related parties and reports the opinion of the Directors’ Committee to the Board of Directors;
· the examination of the compensation framework and plans for managers, executive officers and employees;
· the preparation of an Annual Management Report, including its main recommendations to shareholders;
· provide information to the Board of Directors about the convenience of recruiting external auditors to provide non-auditing services, when such services are not prohibited by law, depending on whether such services might affect the external auditors’ independence;
· oversee the work of external auditors;
· review and approval of the annual auditing plan by the external auditors;
· evaluate the qualifications, independence and quality of the auditing services;
· elaborate on policies regarding employment of former members of the external auditing firm;
· review and discuss problems or disagreements between management and external auditors regarding the auditing process;
· establish procedures for receiving and dealing with complaints regarding accounting, internal control and auditing matters;
· any other function mandated to the Committee by the bylaws, our Board of Directors or our shareholders.
Corporate Governance Guidelines
The NYSE’s corporate governance rules require U.S.-listed companies to adopt and disclose corporate governance guidelines. Chilean law provides for this practice through the disclosure of the procedures related to the General ResolutionNCG 385 and the Manual. We have also adopted the Code of Ethics, and ourEthics. Our bylaws include provisions that govern the creation, composition, attributions, functions, and compensation of the Directors’Directors Committee described above, which includesincluding among its functions the duties performed by an Audit Committee.
D. Employees.
The following table sets forth the total number of our personnel permanent(permanent and temporary employees,employees) in Enel Chile and in our subsidiaries as of December 31, 2018, 2017,2020, 2019, and 2016:2018:
Company |
| 2018 |
| 2017 |
| 2016 |
|
Enel Generation |
| 678 |
| 753 |
| 790 |
|
Pehuenche |
| 2 |
| 2 |
| 2 |
|
Enel Chile(1) |
| 451 |
| 431 |
| 336 |
|
Enel Distribution (2) |
| 681 |
| 669 |
| 688 |
|
Servicios Informáticos e Inmobiliarios Ltda. |
| 0 |
| 0 |
| 103 |
|
GasAtacama(3) |
| 87 |
| 93 |
| 91 |
|
EGP Chile (4) |
| 163 |
| 0 |
| 0 |
|
Total Personnel (5) |
| 2,062 |
| 1,948 |
| 2,010 |
|
| | | | | | |
Company |
| 2020 |
| 2019 |
| 2018 |
Enel Distribution(1) | | 755 | | 733 | | 681 |
Enel Generation(2) | | 668 | | 700 | | 678 |
Enel Chile | | 494 | | 480 | | 451 |
EGP Chile(3) | | 285 | | 212 | | 163 |
Enel X | | 15 | | 6 | | — |
Pehuenche | | 2 | | 2 | | 2 |
GasAtacama(2) | | — | | — | | 87 |
Total Personnel(4) | | 2,219 | | 2,133 | | 2,062 |
(1) | Includes Enel Colina S.A. |
(2) | GasAtacama S.A. and GasAtacama merged into Enel Generation in October 2019. |
(3) | We have consolidated EGP Chile and its subsidiaries since April 2, 2018. |
(4) | The total number of temporary employees was not significant. |
(1) Includes Servicios Informáticos e Inmobiliarios Ltda., a former subsidiary that merge into us on September 1, 2017.
(2) Includes Luz Andes S.A. and Empresa Eléctrica de Colina S.A.
(3) Includes GasAtacama Argentina S.A.
(4) We have consolidated EGPThe Chilean Labor Code entitles all employees in Chile and its subsidiaries since April 2, 2018.
(5) The total number of temporary employees was not significant.
All Chilean employees who are dismissedfired for reasons other than misconduct are entitled by law to a severance indemnity payment. According to Chilean law,In most cases, contracted employees holding contracts of indefinite duration are entitled to a legal minimum severance indemnity payment of one-month’sone month’s salary for each year (or a six-month portion thereof)(and every fraction thereof beyond six months) worked, subject to a limit of a total payment of a maximum of 11 months’ pay forsalary.
Our employment contracts typically provide severance indemnity payments higher than those required by the Chilean Labor Code. In most cases, we respect seniority as the time that the employee first joined us or an affiliate. Therefore, employees hired after August 14, 1981. Severanceby one of our Chilean affiliates or predecessor companies maintain their seniority in the company and are treated contractually as if we had hired them. Under such employment contracts, severance indemnity payments tofor most of our employees hired prior to that date consist of one-month’sone month’s salary for each full year worked not(and every fraction thereof beyond six months), subject to anya maximum limitation.of 25 months. Under our collective bargaining agreements and other employment contracts not covered by such agreements, we are typically obligated to make severance indemnity
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payments to all covered employees in cases of voluntary resignation or death in specified amounts that increase according to seniority and mayoften exceed the amounts required under Chilean law.
We have the following collective bargaining agreements:
To the best of our knowledge, none of our directors or officers owns more than 0.1% of our shares or Item 7.Major Shareholders and
We have It is not practicable for us to determine the number of our As of
The following table sets forth
Enel, our ultimate controlling shareholder, is an
Article 146 of Law No. 18,046 (the “Chilean Corporations Article 147 of the Chilean Corporation Law (“Article 147”) requires that
If a transaction is not in compliance with Article Our internal procedure contemplates that all 104 lending to affiliates and TAB 1m plus
All these aforementioned intercompany cash flows help meet the working capital needs of
We
105 The 2018 Reorganization consolidated Enel’s conventional and non-conventional renewable energy businesses in Chile. Under Chilean As of the date of this Report, the
Not applicable.
See “Item 18. Financial Statements.” Legal Proceedings
Dividend Policy Our For dividends
Considering our financial results as of September 30, 2020, and the 2020 dividend policy presented to our shareholders at the OSM on April 29, 2020, the interim dividend of 15% of accumulated earnings as of such date was 106 not distributed. Our board of directors approved a dividend equivalent to Ch$ 3.0774017 per share of common stock against retained earnings from prior years to offset the impairment charge resulting from our subsidiary Enel Generation’s decarbonization process. The dividend was approved at the OSM held on April 28, 2021. For dividends
This dividend policy is conditional
Shareholders Dividends
For a discussion of Chilean withholding taxes and access to the formal currency market in Chile in connection with the payment of dividends and sales of
None. 107
Not applicable.
In Chile, our common stock is traded on the following stock
Equities, closed-end funds, fixed-income securities, short-term and money market securities, gold, U.S. dollars, and futures contracts for stock indices and U.S. dollars
In August 2016, the The SPCLXIGPA is calculated considering, among other things, the prices of the shares traded during at least 25% of the days of the year, with a total of annual transactions exceeding UF 10,000 (approximately US$ March. The number of shares per component of the index is updated quarterly after the close of the third Friday The SPCLXIPSA is calculated considering, among other things, the prices of the 30 shares with the highest trading volume during the previous six months, market trading on at least 90% of trading days, and a market capitalization above Ch$ 200 billion (US$ 281 million as of December 31, 2020). The SPCLXIPSA index is rebalanced every six months after the closing of the third Friday of March and September and is re-weighted quarterly after the close of the third Friday in June and December. On December Our common stock trades in the United States in the form of 108 As of The NYSE is open for trading Monday through Friday from 9:30 The following table contains information regarding the amount of total traded shares of common stock and the corresponding percentage traded per market during
Not applicable.
Not applicable.
Not applicable. Item 10. Additional Information
Not applicable.
Description of Share Capital Set forth below is certain information concerning our share capital and a General 109 Shareholders’ rights in Chilean companies are governed by the company’s bylaws (estatutos), which have the same purpose as the articles or the certificate of incorporation and the bylaws of a company incorporated in the United States and by the Chilean Corporations The CMF regulates the Chilean securities markets Public Register We are a publicly held stock corporation incorporated under the laws of Chile. We were incorporated by public deed issued on January 8, 2016, by the Santiago Notary Public, Mr. Iván Torrealba A., and registered on January 19, 2016, in the Commercial Register (Registro de Comercio del Conservador de Bienes Raíces y Comercio de Santiago) on pages 4288 No. 2570. Our registry in the Securities Registry of the CMF was approved by the CMF on April 13, 2016, under Reporting Requirements Regarding Acquisition or Sale of Shares Under Article 12 of the Securities Market Law and General Rule No. 269 of the CMF, certain information regarding transactions in shares of a publicly held stock corporation or in contracts or securities whose price or financial results depend on, or are conditioned in whole or in a significant part on the price of such shares, must be reported to the CMF and the Chilean Stock Exchanges. Since
110
Under Article 54 of the Securities Market Law and General Rule No. 104 enacted by the CMF, unless the tender offer regulation applies, any person who directly or indirectly intends to take control of a publicly held stock corporation must disclose this intent to the market at least ten business days in advance of the proposed change of control and, in any event, as soon as the negotiations for the change of control have taken place or reserved information of the publicly held stock corporation has been provided. Corporate Objectives and Purposes Article 4 of our bylaws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transformation, or sale of energy in Chile in any form, directly or through other companies, as well as to provide Board of Directors Our The compensation of the directors is established annually at the OSM. See “Item 6. Directors, Senior Management and Employees — B. Agreements entered into by us with related parties can only be executed when such agreements serve our interest, and their price, terms, and conditions are consistent with prevailing market conditions at the time of their approval and comply with all the requirements and procedures indicated in Article 147 of the Chilean Corporations Certain Powers of the Board of Directors
Our bylaws do not contain provisions relating to:
111
Certain Provisions Regarding Shareholder Rights As of the date of Our bylaws do not contain any provisions relating to:
Under Chilean law, the rights of our shareholders may only be modified by an amendment to the bylaws that complies with the requirements explained below under “Item 10. Additional Information — B. Memorandum and Articles of Association. — Shareholders’ Meetings and Voting Capitalization Under Chilean law, only the shareholders of a company acting at an ESM have the power to authorize a capital increase. When an investor subscribes shares, these are officially issued and registered under his When there are authorized and issued shares for which full payment has not been made within the period fixed by shareholders at the same ESM at which the subscription was authorized (which As of December 31, Preemptive Rights and Increases of Share Capital
112 Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders
An OSM must be held within the first four months following the end of our fiscal year. Our last OSM was held on April The OSM or ESM shall be held on the day stated in the notice and should remain in session until Under Chilean law, a quorum for a shareholders’ meeting is established by the presence, in person or by proxy, of shareholders representing at least a majority of the issued shares with voting rights of a company. If a quorum is not present at the first meeting, a reconvened meeting can
Regardless of the quorum present, a vote of at least two-thirds majority of the
113
Certain amendments to our bylaws require the affirmative vote of 75% of the outstanding shares with voting rights. Bylaw amendments for Chilean law does not require a publicly held stock corporation to provide its shareholders the same level and type of information required by the U.S. securities laws regarding The Chilean Corporations
114 interested parties had made, provided they are presented during the year or within 30-days after its ending; or
Similarly, the Chilean Corporations Only shareholders registered as such with us as of midnight on the fifth business day There are no limitations imposed by Chilean law or our bylaws on the right of nonresidents or foreigners to hold or vote shares of common stock. However, the registered holder of the shares of common stock represented by established by the Depositary for such purpose, the shares of common stock represented by the ADS may, in some situations, be voted in the manner directed by the Chairman of the Board, or by a person designated by the Chairman of the Board, subject to limitations Dividends and Liquidation Rights According to the Chilean Corporations
115 Dividends In the event of our liquidation, the shareholders would participate in the assets available in proportion to the number of paid-in shares held by them, after payment to all creditors. Approval of Financial Statements The Change of Control The Capital Markets Law establishes a comprehensive regulation related to tender offers. The law defines a tender offer as the offer to purchase shares of companies Acquisition of Shares No provision in our bylaws discriminates against any existing or prospective holder of shares Right of Dissenting Shareholders to Tender Their Shares The Chilean Corporations “Dissenting” shareholders are defined as those 116 The price paid to a dissenting shareholder of a publicly held stock corporation whose shares are quoted and actively traded on one of the Chilean stock exchanges is the weighted average of the sales prices for the shares as reported on the Chilean stock exchanges on which the shares are quoted for the Article 126 of the Chilean Corporations The resolutions that result in a shareholder’s right to withdraw include, among others, the following:
Investments by AFPs The Pension 117 investments. We are and have been Companies subject to Title XII
Registrations and Transfers Shares issued by us are registered with an administrative agent, which is DCV Registros S.A. This entity is also responsible for our
None.
The Central Bank of Chile is responsible for, among other things, monetary policies and exchange controls in Chile. Currently, applicable foreign exchange regulations are
The following is a summary of certain provisions of Chapter XIV of the Compendium that Except for compliance with tax regulations and some reporting requirements, currently there are no rules in Chile affecting repatriation rights, except that the remittance of foreign currency must be made through a Formal Exchange Market entity. However, the Central Bank of Chile has the authority to change such rules and impose exchange controls.
Chilean issuers may offer bonds E. Taxation. Chilean Tax Considerations The following discussion summarizes material Chilean income and withholding tax consequences to foreign holders 118 some of which may be subject to special rules. Holders of shares and The summary that follows is based on Chilean law, in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions authorities may change their rulings, regulations, and interpretations in the future. The discussion that follows is also based, in part, on representations of the As used in this Report, the term “foreign holder” means either:
Taxation of Shares and Taxation of Cash Dividends and Property Distributions Cash dividends paid
In February 2020, tax reform contemplating only a partially integrated tax regime was enacted. Under the current Chilean Income Tax Law, publicly held Under the cash basis regime (or 119 Tax Law in force at the The example below illustrates the effective Chilean withholding tax burden on a cash dividend received by a Foreign Holder, assuming a Chilean withholding tax base rate of 35%, an effective Chilean CIT rate of 27% (the CIT rate for
However, for purposes of the foregoing, the tax authority has not clarified whether the taxpayer residence will be the ADS holder’s address or the depository’s address. Taxation on sale or exchange of Gains obtained by a foreign holder from the sale or exchange of Taxation on sale or exchange of Shares The Chilean Income Tax Law includes a tax exemption on capital gains Shares are considered to have a “high presence” in the Chilean Stock Exchanges when (i) they have been traded for a certain number of days at or beyond a volume threshold specified under Chilean law and regulations or (ii) in case the issuer has retained a market maker, 120 have a high presence in the Chilean Stock Exchanges, and If the shares do not qualify for the exemption, capital gains on their sale or exchange of shares (as distinguished from sales or exchanges of The date of acquisition of the Taxation of Share Rights and ADS Rights For Chilean tax purposes and to the extent we issue any share rights or ADS rights, the receipt of share rights or ADS rights by a Foreign Holder of shares or Any gain on the sale, exchange, or transfer of any ADS rights by a Foreign Holder is not subject to taxes in Chile. Any gain on the sale, exchange, or transfer of the share rights by a Foreign Holder is subject to a 35% Chilean withholding tax. Other Chilean Taxes There is no gift, inheritance, or succession tax applicable to Material U.S. Federal Income Tax Considerations This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary, and proposed Treasury regulations, all as of the date of this Report. These authorities are subject to change, possibly with retroactive effect. This discussion assumes that the depositary’s activities are clearly and appropriately defined The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning, and disposing of shares or
121
Persons or entities described above, including partnerships holding shares or You will be a “U.S. Holder” for purposes of this discussion if you become a beneficial owner of our shares or
For U.S. federal income tax purposes, it is generally expected that a U.S. Holder of The U.S. Treasury has expressed concerns that parties to whom This discussion assumes that we will not be a passive foreign investment company, as described below. The discussion below does not address the effect of any U.S. state, local, estate, or gift tax law or non-U.S. tax law or tax considerations that arise from rules of general application to all taxpayers on a U.S. Holder of the shares or U.S. Holders should consult their tax own advisors 122 Taxation of Distributions The following discussion of cash dividends and other distributions is subject to the discussion below under “Passive Foreign Investment Company Rules.” Distributions received by a U.S. Holder on shares or Subject to certain exceptions for short-term and hedged positions, the discussion above regarding concerns expressed by the U.S. Treasury and the discussion below regarding rules intended to be promulgated by the U.S. Treasury, the U.S. dollar amount of dividends received by a In addition, based on our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for our time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any current, prior or future taxable year. Based on existing guidance, it is not entirely clear whether dividends received The amount of a dividend generally will be treated as foreign-source dividend income to a U.S. Holder for foreign tax credit purposes. As discussed in more detail below under “—Foreign Tax Credits,” it is not free from doubt whether Chilean withholding taxes imposed on distributions on shares or 123 Sale or Other Disposition of Shares or If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or In certain circumstances, Chilean taxes may be imposed upon the sale of shares (but not Foreign Subject to applicable limitations that may vary depending upon a U.S. Holder’s circumstances and subject to the discussion above regarding concerns expressed by the U.S. Treasury, you may be eligible to claim a credit against your U.S. tax liability for Chilean income taxes (or taxes imposed in lieu of an income tax) imposed in connection with distributions on and proceeds from the sale or other disposition of our shares or Passive Foreign Investment Company Rules We were not a “passive foreign investment company” or PFIC for U.S. federal income tax purposes for our 124 Required Disclosure with Respect to Foreign Financial Assets Certain U.S. Holders are required to report information relating to an interest in our shares or Information Reporting and Backup Withholding Payments of dividends and sales proceeds that are made within the United States or through certain U.S.- related financial intermediaries generally are subject to information reporting and to backup withholding unless: (i) the U.S. Holder is an exempt recipient or (ii) in the case of backup withholding, the beneficial owner provides a correct taxpayer identification number and certifies that the U.S. Holder is not subject to backup withholding. The amount of any backup withholding from a payment to a beneficial owner will be allowed as a credit against the beneficial owner’s U.S. federal income tax liability and may entitle the U.S. Holder to a refund, provided that the required information is furnished in a timely fashion to the U.S. Internal Revenue Service. Medicare Contribution Tax
U.S. Holders should consult their own tax advisors with respect to the particular consequences to them of owning or disposing of shares or
Not applicable.
Not applicable.
We are subject to the information requirements of the Exchange Act, except that as a foreign issuer, we are not subject to SEC proxy rules (other than general anti-fraud rules) or the short-swing profit disclosure rules of the Exchange Act. information we file with or furnish to the SEC are available electronically on the SEC’s website, which can be accessed at http://www.sec.gov and on our website www.enelchile.cl. Copies of such material may also be inspected at the offices of the New York Stock Exchange, at 11 Wall Street, New York, New York 10005, on which our ADS are listed.
For information on our principal subsidiaries, see “Item 4. Information on the Company — C. Organizational Structure — Principal Subsidiaries and 125 Item 11.Quantitative and Qualitative Disclosures About Market Risk We are exposed to risks arising from Commodity Price Risk In our electricity generation business segment, we are exposed to market risks
Considering the operating conditions faced As of December 31, 2021. As of December 31,
We Interest Rate and Foreign Currency Risk As of December 31, 126
As of December 31, 127 financing and withholding taxes on interest payments related to financing obtained outside the country of domicile of each company.
Interest Rate Risk Our policy aims to minimize the average cost of debt and reduce the volatility of our financial results. Depending on our estimates and the debt structure, we sometimes manage interest rate risk As of December 31, 128 As of December 31,
As of December 31,
Foreign Currency Risk Our policy seeks to maintain a balance between the As of December 31,
129
As of December 31,
statements for further detail. (d) Safe Harbor The information in this “Item 11. Quantitative and Qualitative Disclosures About Market Risk,” contains information that may constitute forward-looking statements. See “Forward-Looking Statements” in the Introduction of this Report for safe harbor provisions. Item
Not applicable.
Not applicable.
Not applicable.
Depositary Fees and Charges Our ADS program’s
130
The Depositary collects fees for delivery and surrender of Depositary Payments for Fiscal Year The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 131 PART II Item 13.Defaults, Dividend Arrearages and Delinquencies None. Item 14.Material Modifications to the Rights of Security Holders and Use of Proceeds None. Item 15.Controls and Procedures
We carried out an evaluation under the supervision and with the participation of our senior management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, our disclosure controls and procedures are designed to provide reasonable assurance of achieving their control objectives. Based upon our evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that, as a result of the
Management is responsible for establishing and maintaining
Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that the controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.
The Company’s management, with
132 deficiencies also affected the effectiveness of The material weakness did not result in any identified misstatements to the Company’s consolidated financial statements and there were no changes to previously released financial results. Our independent registered public accounting firm, KPMG Auditores Consultores SpA, who audited the consolidated financial statements included in this Annual Report on Form 20-F, issued an adverse opinion on the effectiveness of the Company’s internal control over financial reporting, which is on pages F-3 and F-4 of this Annual Report on Form 20-F. (c) Management’s Remediation Plan We are committed to making further progress in our remediation efforts during 2021. In order to remediate the material weakness described above, we have been implementing and will continue to implement actions to revise and enhance our GITCs to ensure, for the
Except as noted above with respect to the implementation of the
Item 16.Reserved Item 16A.Audit Committee Financial Expert As of December 31, Our standards of ethical conduct are governed The Manual, adopted by our 133 by directors, management, principal executives, employees, and other related parties; the existence of mechanisms for the continuous disclosure of information that is of interest to the market; and In addition to the corporate governance rules described above, our The board of directors approved the Diversity Policy A copy of these documents is available on our webpage at www.enelchile.cl as well as upon request, free of charge, by writing or calling us at: Enel Chile S.A. Investor Relations Department Av. Santa Rosa 76, Piso 15 Comuna de Santiago, Santiago, Chile (56-2)
Item 16C. Principal Accountant Fees and Services In 2020, our shareholders appointed KPMG Auditores Consultores SpA (“KPMG”) as the Company’s new independent registered public accounting firm to replace EY Audit SpA (“EY”). The following table provides information on the aggregate fees for approved services billed by our independent registered accounting firm
All The amounts included in the table above and the related footnotes have been classified in accordance with SEC guidance.
Directors Committee Pre-Approval Policies and Procedures Our shareholders appoint our external auditors The The Fees payable in connection with recurring audit services are pre-approved as part of our annual budget. Fees payable in connection with non-recurring audit services, once The pre-approval policy established by the
The Item 16D.Exemptions from the Listing Standards for Audit Committees Not applicable. Item 16E.Purchases of Equity Securities by the Issuer and Affiliated Purchasers The following table sets forth, for each calendar month in 2020, the total number of shares of common stock purchased by the Company, or on the Company’s behalf, or by any affiliated purchaser, including Enel, the average price paid per share, and the number of shares purchased under a publicly announced plan or program. 135 Purchases of Equity Securities
As a result of the transactions described above, Enel increased its beneficial ownership in us from 61.9% as of December 31, 2019, to 64.9% as of December 31, 2020.
Item 16F.Change in Registrant’s Certifying Accountant There has been no change in independent accountants for the Company during the two most recent fiscal years or any subsequent interim period except as previously reported in the Company’s Annual Report on Form 20-F for the fiscal year ended December 31, 2019. There have been no disagreements required to be disclosed in Item 16F (b).
136 PART III Not Applicable. Enel Chile Index to the Audited Consolidated Financial Statements
We will furnish to the Securities and Exchange Commission, upon request, copies of any 138 SIGNATURES The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
139
Report of Independent Registered Public Accounting Firm To the Enel Chile S.A.: Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on We conducted our
KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved. F-1 Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Unbilled revenue As discussed in Notes 3q and 28 to the consolidated financial statements, revenue from sales to customers includes estimates of energy provided and not billed as of December 31, 2020, amounting to ThCh$434,442,879 related to the distribution and generation entities in Chile. These estimates are made based on the quantity of energy consumed by customers during the period, at the prices stipulated in the electricity tariffs in accordance with the current regulation or, if applicable, contractual arrangements with customers. We identified the revenue recognition of energy provided and not invoiced as a critical audit matter due to the auditor judgment required to assess the complexity of the non-standardized determination of energy consumed by customers and the calculation of price formulas established in the contracts and regulations. In addition, auditor judgment was required to assess the adequacy of the nature and extent of the audit evidence obtained. The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the unbilled revenue process for the generation entities. This included controls related to: the price used for estimation of unbilled sales to customers inputs used to estimate the quantity of energy consumed by customers, such as energy purchased from the Company and the customer´s historical consumption information, including the energy consumption by customers in the previous month the comparison between the estimate of unbilled revenue at the end of the month versus the actual volume of energy subsequently measured and billed to customers (back-testing) for the generation entities. We compared the volume used in the estimate of unbilled revenue at the end of the year versus the actual volume of energy subsequently measured and billed to customers (back-testing) or to external data provided by the local regulator, as applicable. We reassessed a sample of the price used to calculate the unbilled sales to customers based on current contracts and decrees issued by the local regulator. We evaluated the reconciliation of the sales ledger to the actual sales report as of year end. In addition, we assessed the sufficiency of the nature and extent of the audit evidence obtained, as well as the Company’s disclosures of this matter in Note 28 to the consolidated financial statements. /s/ KPMG KPMG Auditores Consultores SpA We have served as the Company’s auditor since Santiago, Chile April 29,
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Report of Independent Registered Public Accounting Firm To the Enel Chile S.A.: Opinion on Internal Control We have audited Enel Chile S.A. and
Treadway Commission. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. The Company did not establish effective general information technology controls, specifically program change controls, that support the consistent operation of the Company’s information technology (IT) operating system, database, and IT application layers of technology over the electricity distribution business revenue process. These deficiencies also affected the effectiveness of business process automated controls, manual controls with an automated component, and the database of the reports that were used to execute certain automated and manual controls. The material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2020 consolidated financial statements, and this report does not affect our report on those consolidated financial statements. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved. F-3 We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may /s/ KPMG KPMG Auditores Consultores SpA Santiago, Chile April 29, 2021 KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved. F-4 .
Report of Independent Registered Public Accounting Firm To the Shareholders and the Board of Directors of Enel Chile S.A. Opinion on the Financial Statements We have audited the accompanying consolidated statement of financial position of Enel Chile S.A. and subsidiaries (the Company) as of December 31, 2019, the related consolidated statements of comprehensive income, shareholders' equity and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. F-5
Goodwill Impairment Test Description of the Matter As of December 31, 2019, the Company’s consolidated financial statements present goodwill in the amount of Ch$917.35 billion. As discussed in Note 3 c) to the consolidated financial statements, goodwill is tested for impairment at least annually at the reporting unit level. The Company’s goodwill is initially assigned to its reporting units as of the acquisition date using a relative fair value allocation. The impairment tests require management to use significant assumptions to determine the fair value of the related reporting unit. Those assumptions are described in Note 3 e) to the Company´s consolidated financial statements, and include market evolution, future price estimations, discount rates and the consideration of risks specific to the relevant cash generating unit.
Auditing the Company´s goodwill impairment test is complex due to the significant estimation uncertainties involved in determining the fair values of the reporting units. Those fair value estimates are sensitive to changes in significant assumptions such as discount rate and projected cash flows that are affected by future market or economic conditions. How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the goodwill impairment test. For example, we tested controls over the significant assumptions, such as discount rate and projected cash flows, used in the valuation process. To test the fair values of the reporting units, our audit procedures included, among others, evaluating the methodologies used by the Company with the assistance of our valuation specialists; testing the significant assumptions used to develop the prospective financial information; comparing those significant assumptions to historical results of the Company's business; benchmarking those assumptions against market participant data within the same industry and performing an independent calculation of the discount rate considering market information about the cost of capital from comparable energy companies. We also evaluated the Company’s disclosure of this matter in Note 15 to the consolidated financial statements. Effect of the 2019 Price Stabilization Law Description of the Matter As described in Notes 4 b) and 11 to the consolidated financial statements, the Company recognized revenues in the amount of Ch$182.07 billion and a corresponding payable to suppliers for energy purchases in the amount of Ch$53.94billion, as a result of a new law came into force corresponding to the price stabilization mechanism (PEC in Spanish), which caused delays in the billing process of the price adjustments and requires the use of significant assumptions and judgment by management to assess the financial and accounting effects. Auditing the amounts related to the effects of the PEC is complex due to the significant effort to evaluate the effects of the tariff decrees and sales contracts as well as the judgment used to determine the present value of the unbilled revenue due to the entry into force of the PEC law. F-6
How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the effects of the PEC. For example, we tested controls over the prices obtained from the sales contracts and tariff decrees related to the significant assumptions, such as discount rate and estimated recovery date used to calculate the unbilled revenue and supplier accrual associated with the PEC. To test the amounts resulting from the effects of the PEC by recalculating the prices of sales contracts; comparing significant inputs used by management, such as the future price of coal, gas, oil, forward US Dollar exchange rates, as well as the Consumer Price Index (CPI) with the tariff decrees issued by the regulator; comparing the energy price used in the sales contracts with the price obtained from the regulator; recalculating the estimation of unbilled energy already provided to customers, and involving our valuation specialist to assist in the evaluating the discount rate used by the Company to compute the present value of future price adjustments related to customers subject to the PEC. We also evaluated the financial statements disclosures included in the Notes 4 b) and 9.
F-7 ENEL CHILE S.A. Consolidated Statements of Financial Position As of December 31, (In thousands of Chilean pesos
The accompanying notes are an integral part of these consolidated financial statements. F-8 ENEL CHILE S.A. Consolidated Statements of Financial Position (continued) As of December 31, (In thousands of Chilean pesos
The accompanying notes are an integral part of these consolidated financial statements. F-9 ENEL CHILE S.A. Consolidated Statements of Comprehensive Income, by Nature For the years ended December 31, (In thousands of Chilean pesos
(*) Includes Argentina’s hyperinflationary effect (see Note 7). The accompanying notes are an integral part of these consolidated financial statements. F-10 ENEL CHILE S.A. Consolidated Statements of Comprehensive Income, by Nature (continued) For the years ended December 31, (In thousands of Chilean pesos
The accompanying notes are an integral part of these consolidated financial statements. F-11 ENEL CHILE S.A. Consolidated Statements of Changes in Equity For the years ended December 31, (In thousands of Chilean pesos
(1) See Note 27.1 (2) See Note 27.3 (3) See Note 27.5 (4) See Note 27.6 (5) Considers a charge in results for ThCh$3,411,631 due to application of IFRS 9 and a credit to retained earnings for ThCh$664,470 due to application of IAS The accompanying notes are an integral part of these consolidated financial statements F-12 ENEL CHILE S.A. Consolidated Statements of Cash Flows, Direct For the years ended December 31,
The accompanying notes are an integral part of these consolidated financial F-13
F-14
F-15
F-16 ENEL CHILE S.A. AND NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, (In thousands of Chilean pesos Enel Chile S.A. (hereinafter the “Parent Company” or the “Company”) and its subsidiaries comprise the Enel Chile Group (hereinafter the “Group”). The Company is a publicly traded corporation with registered address and head office located at Avenida Santa Rosa, No. 76, in Santiago, Chile. Since April 13, 2016, Enel Chile is a subsidiary of Enel S.p.A. (hereinafter “Enel”), an entity that has direct and indirect ownership interests of 64.93%. The Company was initially incorporated by public deed dated January 22, 2016 and came into legal existence on March 1, 2016 under the name of Enersis Chile S.A. The Company changed its name to Enel Chile S.A. effective October 4, 2016, when the 76.536.353 5. As of December 31,
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2018 and their related notes. These consolidated financial statements
Appendix 1 – Detail of
The IASB issued the Conceptual Framework The IASB has also issued a separate accompanying document, F-18 The Conceptual Framework (Revised)
IFRS 3 Business Combinations was amended by the IASB in October 2018, to clarify the definition of a business, in order to help entities, The amendment also adds guidance and illustrative examples to assess whether a substantial process has been acquired and introduces an optional fair value concentration test. The amendment
In October 2018, the IASB amended IAS 1 Presentation of Financial Statements and IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors, IFRSs. Information is material if omitting, misstating or obscuring it could reasonably be expected to influence the decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity. The amendments became effective beginning on January 1, 2020, with prospective application, with no impact generated in the Group’s consolidated financial statements. Amendments to IFRS 9, IAS 39 and IFRS 7 – Interest rate benchmark reform (Phase 1) On September 26, 2019, the IASB issued amendments to IFRS 9 Financial Instruments, and IAS 39 Financial Instruments: Recognition and Measurement, and IFRS 7 Financial Instruments: Disclosures, in response to the reform that gradually eliminates benchmark interest rates, such as interbank offered rates (IBORs). The amendments provide temporary reliefs which enable hedge accounting to continue during the period of uncertainty before the replacement of an existing interest rate benchmark with an alternative nearly risk-free interest rate (an RFR). These amendments became effective beginning on January 1, 2020. The amendments to IFRS 9 include a number of reliefs, which apply to all hedging relationships that are directly affected by the interest rate benchmark reform. A hedging relationship is affected if the reform gives rise to uncertainties about the timing and/or amount of benchmark-based cash flows of the hedged item or the hedging instrument. The first three reliefs provide for: - The assessment of whether a forecast transaction (or component thereof) is highly probable. - Assessing when to reclassify the amount in the cash flow hedge reserve to profit and loss. - The assessment of the economic relationship between the hedged item and the hedging instrument. F-19 For each of these reliefs, it is assumed that the benchmark on which the hedged cash flows are based (whether or not contractually specified) and/or, for relief three, the benchmark on which the cash flows of the hedging instrument are based, are not altered as a result of the reform. A fourth relief provides that, for a benchmark component of interest rate risk that is affected by the reform, the requirement that the risk component is separately identifiable needs be met only at the inception of the hedging relationship. The exceptions will continue to be applied indefinitely in the absence of any of the events described in the amendments. Upon the designation of a group of items as a hedged item or a combination of financial instruments, as a hedging instrument, the exceptions will cease being applied separately to each individual item or financial instrument, when there is no longer uncertainty arising from the interest rate benchmark reform. At the end of 2020, the Group has hedging relationships in force in which the interest rate has been designated as the hedged risk, specifically the London Interbank Offered Rate (LIBOR). These hedging relationships, classified as cash flow hedges, have been directly affected by the uncertainty arising from the interest rate benchmark reform. In order to evaluate the economic relationship between the hedged items and the hedging instruments, in accordance with the exceptions established by the standard, the Group has assumed that LIBOR, the benchmark interest rate on which the hedged risks are based, has not been altered as a result of the reform. The Group has contacted financial institutions in the domestic and international market, as well as with the counterparties of the current operations, in order to evaluate the best alternatives for the continuity of the contracts and their hedging relationship. As of December 31, 2020, the nominal amount of hedging instruments, for hedging relationships to which the exceptions established in IFRS 9 have been applied, is US$400 million (ThCh$284,380,000).
As of the date of issuance of these consolidated financial statements, the following accounting pronouncements had been issued by the IASB, but their application was not mandatory:
F-20 Amendments to IFRS 16 “COVID-19-Related Rent Concessions” As a result of the COVID-19 pandemic, lessees in many countries have been granted rent payment concessions, such as grace periods and delaying of lease payments for a period of time, sometimes followed by an increase in the payment in future periods. Within this context, on May 28, 2020, the IASB issued amendments to IFRS 16 Leases, in order to provide a practical expedient for lessees, through which they can opt for not evaluating whether the rent concession is a modification of the lease. Lessees that elect this option, will account for such rent concessions as a variable payment. The practical expedient is only applicable
The amendments are applicable to annual periods beginning on June 1, 2020. Early application is permitted. These amendments must be applied retroactively, recognizing the accumulated effect from initial application as an adjustment in the beginning balance of retained earnings (or other equity component, as applicable) at the beginning of the annual period in which the amendment is applied for the first time. Management estimates that the application of these amendments will not have an impact on the Group's consolidated financial statements. Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16: Interest Rate Benchmark Reform (Phase 2) On August 27, 2020, the IASB issued the Interest Rate Benchmark Reform (Phase 2) which supplements the amendments to IFRS 9, IAS 39 and IFRS 7 issued in 2019, and additionally incorporates amendments to IFRS 4 and IFRS 16. This final phase of the project focuses on the effects on the financial statements when a company replaces the previous interest rate benchmark with an alternative interest rate benchmark as a result of the reform. The amendments refer to:
These amendments are effective for annual periods beginning on Amendments to IFRS 3 “References to the Conceptual Framework” On May 14, 2020, the IASB issued a package of limited-scope amendments, including amendments to IFRS 3 Business Combinations. The amendments update references to the Conceptual Framework issued in 2018, in order to F-21 determine an asset or a liability in a business combination. In addition, the IASB added a new exception to IFRS 3 for liabilities and contingent liabilities, which specifies that, for certain types of liabilities and contingent liabilities, an entity that applies IFRS 3 must refer to IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”, or IFRIC 21 “Levies”, instead of the 2018 Conceptual Framework. Without this exception, an entity would have recognized certain liabilities in a business combination that would not be recognized in accordance with IAS 37. The amendments are applicable prospectively to business combinations with acquisition dates beginning on the first annual period beginning on January 1, 2022. Early application is permitted. Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements. Amendments to IAS 16 “Proceeds before Intended Use” As part of the package of limited-scope amendments issued in May 2020, the IASB issued amendments to IAS 16 Property, Plant and Equipment, which prohibit a company from deducting from the cost of property, plant and equipment amounts received from selling items produced while the company is preparing the asset for its intended use. Instead, the company will recognize such sales proceeds and related costs in profit or loss for the period. The amendments also clarify that an entity is “testing whether an asset operates correctly” when it evaluates the technical and physical performance of the asset. These amendments are applicable to annual reporting periods beginning on January 1, 2022. Early application is permitted. The amendments will be applied retroactively, but only from the beginning of the first period presented in the financial statements in which the entity applies the amendments for the first time. The accumulated effect of initial application of the amendments will be recognized as an adjustment to the opening balance of retained earnings (or other equity components as applicable) at the beginning of the first reported period. Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements. Amendments to IAS 37 “Onerous Contracts: Cost of Fulfilling a Contract” The third standard amended by the IASB in the package of limited-scope amendments issued in May 2020 was IAS 37 Provisions, Contingent Liabilities and Contingent Assets. The amendments specify which costs a company should include when evaluating whether a contract is onerous. In this sense, the amendments clarify that the direct cost of fulfilling a contract comprises both the incremental costs of fulfilling this contract (for example, direct labor and materials), as well as the allocation of other costs that are directly related to compliance with the contracts (for example, an allocation of the depreciation charge for an item of property, plant and equipment used to fulfill the contract). These amendments are applicable for reported annual periods beginning on January 1, 2022. Early application is allowed. Companies must apply these amendments to contracts for which all obligations have still not been fulfilled at the beginning of the reported annual period in which the amendments are applied for the first time. They do not require restatement of comparative information. The accumulated effect of initially applying the amendments will be recognized as an adjustment to the opening balance of retained earnings (or another equity component as applicable) on the date of initial application. Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements. F-22 Annual Improvements to IFRS: 2018-2020 Cycle On May 14, 2020, the IASB issued a number of minor amendments to IFRSs, in order to clarify or correct minor issues or overcome possible inconsistencies in the requirements of certain standards. The amendments with potential impact on the Group are the following:
These improvements are applicable to reported annual periods beginning on January 1, 2022. Early application is allowed. Entities must apply these amendments to financial liabilities that are modified or exchanged at the beginning of the reported annual period, in which the amendments are applied for the first time.
Management believes that the application of these improvements will not generate an impact on the consolidated financial statements of the Group. Amendments to IAS 1 “Classification of Liabilities as Current and Non-Current” On January 23, 2020, the IASB issued limited-scope amendments to IAS 1 Presentation of Financial Statements, in order to clarify how to classify debt and other liabilities as current or non-current. The amendments clarify that a liability is classified as non-current if the entity has, at the end of the reporting period, the substantial right to defer settlement of the liability during at least 12 months. The classification is not affected by the expectations of the entity or by events after the reporting date. The amendments include clarification of the classification requirements for debt that a company could settle converting it to equity. The amendments only affect the presentation of liabilities as current and non-current in the statement of financial position, not the amount and timing of their recognition, or the related disclosures. However, they could lead to companies reclassifying certain current liabilities to non-current and vice versa. This could affect compliance with covenants in the debt agreements of companies. These amendments are applicable retroactively beginning on January 1, 2023. In response to the Covid-19 pandemic, in July 2020 the IASB extended its mandatory effective date established initially for January 1, 2022, by a year in order to provide companies more time to implement any change in classification resulting from these amendments. Early application is permitted. Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements.
The Company’s Board of Directors is responsible for the information contained in these consolidated financial statements and expressly states that all IFRS principles and standards, have been fully implemented. In preparing the consolidated financial statements, certain judgments and estimates made by the Group’s Management have been used to quantify some of the assets, liabilities, revenue, expenses and commitments recognized. F-23 The most
The estimates refer basically to:
In relation to the COVID-19 pandemic, the degree of uncertainty generated in the macroeconomic and financial environment in which the Group operates, could affect the valuations and estimates made by Management to determine the F-24 use their judgment and make estimates were the following: i) measurement of expected credit losses financial assets; ii) determination of impairment losses
assumptions. Although these judgments and estimates have been based on the best information available Subsidiaries are defined as those entities controlled either, directly or indirectly by Enel Chile. Control is exercised if, and only if, the following conditions are met: the Company has i) power over the subsidiary; ii) exposure or rights to variable returns from these entities; and iii) the ability to use its power to influence the amount of these returns. Subsidiaries are defined as those entities controlled either, directly or indirectly by Enel amount of these returns. The Group will reassess whether or not it controls a subsidiary if facts and circumstances indicate that there are changes to one or more of the control elements Subsidiaries are consolidated as described in Note 2.7. The
(*) On January 1, 2021, the merger by incorporation of Almeyda Solar SpA into Enel Green Power Chile S.A. took place, where the latter company became the legal successor company. (**) On January 1, 2021, the spin-off by Enel Distribución Chile S.A was formalized which resulted in the incorporation of a new company, Enel Transmisión Chile S.A., to which the assets and liabilities associated with the electric power transmission segment were assigned and also distributing to all the shareholders of Enel Distribución Chile S.A., a number of Enel Transmisión Chile S.A. shares equal to the their interest in the spin-off company. This process was performed to comply with the requirements related to the exclusive turn of distribution, according to the latest modifications to Decree with Force of Law No. 4/2016 issued by the Ministry of Economy, Development and Reconstruction, which established the consolidated, coordinated and systematized text of Decree with Force of Law No. 1-1982 issued by the Ministry of Mining, General Law of Electric Services. F-25
(***) 2.4.1Changes in the scope of consolidation as of December 31, 2020.
Associates are those entities over which Enel Chile, either directly or indirectly, exercises significant influence. Significant influence is the power to participate in the decisions related to the financial and In assessing significant influence, the Group takes into account the existence and effect of currently exercisable voting rights or convertible rights at the end of each reporting period, including currently exercisable voting rights held by the Company or other entities. In general, significant influence is presumed to be present in those cases in which the Group has more than 20% of the voting power of the investee Associates are accounted for F-26 The detail of the companies that qualify as associates is the following:
Joint arrangements are defined as those entities in which the Group exercises control under an agreement with other shareholders and jointly with them, Depending on the rights and obligations of the participants, joint agreements are classified as:
In determining the type of joint arrangement in which it is involved, the The detail of Companies classified as Joint Ventures is as follows:
Currently,
The subsidiaries are consolidated and all their assets, liabilities, revenues, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations The The Group records business combinations using the acquisition method when all the activities and assets acquired meet the definition of a business and control is transferred to the Group. To be considered a business, a set of activities and assets acquired must include at least one input and a substantive process applied to it that, together, contribute F-27 significantly to the ability to create output. IFRS 3 provides the option of applying a “concentration test” that allows a simplified assessment of whether a set of acquired activities and assets is not a business. The concentration test is met if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets. The operations of
For each business combination, of the acquiree, with the latter being the methodology that the Group has systematically applied to its business combinations. If the fair value of all assets acquired and liabilities assumed at the acquisition date has not been completed, the Group reports the provisional values accounted for in the business combination. During the measurement period, which shall not exceed one year from the acquisition date, the provisional values recognized will be adjusted retrospectively as if the accounting for the business combination had been completed at the acquisition date, and also additional assets or liabilities will be recognized to reflect new information obtained about events and circumstances that existed on the acquisition date, but which were unknown to For business combinations achieved in stages, the
Any difference between assets and liabilities contributed to the consolidation and the consideration paid is recorded directly in F-28 2.8. Functional currency The Any information presented in Ch$ has been rounded to the closest thousand (ThCh$) or million (MCh$), unless indicated otherwise. 2.9. Conversion of financial statements denominated in foreign currency Conversion of the financial statements of the Group companies that have functional currencies different than Ch$, and do not operate in hyperinflationary economies, is carried out as follows:
The financial statements of subsidiaries whose functional currency is that of a hyperinflationary economy, are first adjusted for inflation, recording any gain or loss in the net monetary position in profit or loss. Subsequently, all items (assets, liabilities, equity items, expenses and revenue) are converted at the exchange rate prevailing at the closing date of the most recent statement of financial position. Argentine Hyperinflation Beginning on July 2018, the Argentine economy has been considered to be hyperinflationary in accordance with the criteria established in IAS 29 “Financial Reporting in Hyperinflationary Economies”. This determination was made on the basis of a number of qualitative and quantitative criteria, especially the presence of accumulated inflation in excess of 100% during the three previous years. In accordance with IAS 29, the financial statements of investees in Argentina have been restated retrospectively, applying the general price index at historical cost, in order to reflect changes in the purchasing power of the Argentine peso, as of the closing date of these consolidated financial statements. The general price indexes used at the end of the reporting periods are as follows:
The effects of the application of this standard on these consolidated financial statements are detailed in Note 34. F-29 POLICIES The main accounting policies used in preparing the accompanying consolidated financial statements are the following:
Property, plant and equipment are generally measured with at acquisition cost, net of accumulated depreciation and any impairment losses
Assets under for
Expansion, modernization or improvement costs that represent an increase in productivity, capacity or efficiency or a The replacement or overhaul of entire components that increase the asset’s useful life or economic capacity are recorded as an increase in cost Expenditures for periodic maintenance Property, plant and equipment, net of its residual value, is depreciated by distributing the cost of the different items that comprise it on a straight-line basis over its estimated useful life, which is the period during which the Group expects to use the assets. Useful life estimates and residual values are reviewed on an annual basis and if appropriate adjusted prospectively. In addition, the Group recognizes right-of-use assets for leases relating to property, plant and equipment in accordance with the criteria established in Note 3.f. F-30 The following
Land is not depreciated since it has an indefinite useful An item of property, plant and equipment is written off when sold or otherwise disposed of, or when no future economic benefits are expected to be obtained from its use, sale or other disposal. Gains or losses “Investment property” basically includes Investment property is measured at acquisition cost, net of accumulated depreciation and any impairment losses An investment property is derecognized on disposal, or when no future economic benefits are expected from use or disposal. Gains or losses The fair value of investment property is F-31 Goodwill arising from business combinations and reflected Goodwill arising from acquisition of companies with functional currencies other than the
d) Intangible assets other than goodwill Intangible assets are initially recognized at their acquisition cost or production cost, and are subsequently measured at their cost, net of their accumulated amortization and impairment losses Intangible assets are amortized on a lives amounted to ThCh$14,605,574 and ThCh$16,455,724, respectively, mainly related to easements and water rights. An intangible asset is derecognized Gains or losses arising from asset. The criteria for recognizing d.1) Research and development expenses The Group recognizes the costs incurred in a project’s development phase as intangible assets in the statement of financial position as long as the project’s technical feasibility and future economic benefits have been demonstrated. Research costs are recorded as an expense in the consolidated statement of comprehensive income in the period in which they are incurred.
Computer software is amortized (on average) over four years. Certain easements and water rights have indefinite useful lives and are therefore F-32 e) Impairment of non-financial assets During the Notwithstanding the preceding paragraph, The criteria used to identify the CGUs are based, in line with Management’s strategic and operating vision, within the specific characteristics of the business, the operating rules and regulations of the market in which the Group operates and corporate organization. Recoverable amount is the higher of fair value less costs of disposal and value in use, which is defined as the present value of the estimated future cash flows. In order to calculate the recoverable amount of Property, plant, and equipment, as well as of goodwill and intangible assets, at the level of each CGUs the Group uses value in use criteria in practically all cases. To estimate value in use, the Group prepares future pre-tax cash flow In general, these projections cover the next
Future cash flows are discounted to calculate their present value at a pre-tax rate that covers the cost of capital for the business activity and the geographic area in which it is being carried out. The time value of money and risk premiums generally used among analysts for the business activity and the geographic zone are taken into account to calculate the pre-tax rate. The The Company’s approach to allocate value to each key assumption used to project cash flows, considers:
F-33
Past experience has demonstrated the reliability of the Company’s forecasts, which allows it to base key assumptions on historical information. During 2020, the deviations observed with respect to the projections used to perform impairment testing as of December 31, 2019, were not significant and cash flows generated in 2020 remained in a reasonable variance range compared to those expected for that period, with the exception of the effects generated by the COVID-19 pandemic. Despite the degree of uncertainty of the evolution of the macroeconomic environment in the short term, as a result of COVID-19, Management has evaluated the recovery scenarios and has determined that there is no evidence of impairment in the Group's CGUs, which would make it necessary to estimate their value in use. If the recoverable amount of the CGU is less than the net carrying amount of the asset, the amount of each one, limited to Impairment losses recognized in prior periods for an asset other than goodwill are reversed, if and only if, there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If this is the case, the carrying amount of the asset is increased to its recoverable amount In order to determine whether an arrangement is, or contains, a lease,
F-34 The Group initially recognizes right-of-use assets at cost. The cost of right-of-.use assets comprises: (i) the amount Subsequently, the right-of-use asset is measured at cost, adjusted by any re measurement of the lease Lease liabilities are initially measured at the present value of the lease payments, discounted at the Company's incremental borrowing rate, if the interest rate implicit in the lease cannot be readily determined. The incremental borrowing rate is the interest rate that the company would have to pay to borrow over a similar term, and with similar security, the funds necessary to obtain an asset of similar value to the right-of-use asset in a similar economic environment. The Group determines its incremental borrowing rate using observable data (such as market interest rates) or by making specific estimates when observable rates are not available (e.g., for subsidiaries that do not engage in financing transactions) or when they must be adjusted to reflect the terms and conditions of the lease (e.g., when the leases are not in the subsidiary's functional currency). Lease payments included in the measurement of liabilities comprise: i) fixed payments, less any lease incentive receivable; ii) variable lease payments that depend on an index or a rate; iii) residual value guarantees if it is reasonably certain that the Group will exercise that option; iv) the exercise price of a purchase option, if the Group is it is reasonably certain to exercise that option; and v) penalties for terminating the lease, if any. After the commencement date, the lease liability increases to reflect the accrual of interest and is reduced by the lease payments made. In addition, the Short-term leases of one year or less or leases of low value assets are exempt from the application of the recognition criteria described above, with the payments associated with the lease recorded as an expense on a straight-line basis over the term of the lease. Right-of-use assets and lease liabilities are presented separately from other assets and liabilities, respectively, in the consolidated statement of financial position. f.2) Lessor When the Group acts as a lessor, it classifies at the commencement of the agreement whether the lease is an operating or finance lease, based on the substance of the transaction. Leases in which all the risks and rewards incidental to ownership of an underlying asset are substantially transferred are classified as finance leases. All other leases are classified as operating leases. For finance leases, at the commencement date, the Company recognizes in its statement of financial position the assets held under finance leases and presents them as an account receivable, for an amount equal to the net investment in the lease, calculated as the sum of the present value of the lease payments and the present value of any accrued residual value, discounted at the interest rate implicit in the lease. Subsequently, finance income is recognized over the term of the lease, based on a model that reflects a constant rate of return on the net financial investment made in the lease. For operating leases, lease payments are recognized as F-35 obtaining an operating lease are added to the carrying amount of the underlying asset and are recognized as expense throughout the lease period, applying the same basis as for rental income. Financial instruments are contracts that give rise to both a financial asset in one entity and a financial liability or equity instrument in another entity. g.1) Financial assets other than derivatives The Group classifies its non-derivative financial assets, whether permanent or temporary, excluding investments accounted for using the equity method
Financial assets that meet the conditions established in IFRS 9, to be valued at amortized cost in the Group are: cash equivalents, accounts receivable fair value, less repayments of principal, plus uncollected accrued interest, calculated using the effective interest The effective interest
These Changes in fair value, net of their tax effect, are recorded in the consolidated statement of comprehensive income: Other comprehensive income, until period except for investments in equity instruments where the accumulated balance in other comprehensive income is never reclassified to profit or loss. In the event that the fair value is lower than the acquisition cost, if there is objective evidence that the asset has suffered an impairment that F-36
This category includes the trading portfolio of the financial assets that have been allocated as such upon their initial recognition and which are
g.2) Cash and cash equivalents This item within the consolidated statement of financial position includes cash and bank balances, time deposits, and other highly liquid investments (with original maturity of less than or equal to 90 days) that are readily convertible g.3) Impairment of financial assets
Expected credit loss is the difference between the contractual cash flows that are due in accordance with the contract and all the cash flows that are expected to be received (i.e. all cash shortfalls), discounted at the original effective interest rate. It is determined considering: i) the probability of default (PD, Probability of Default); ii) loss given default (LGD, Loss Given Default), and iii) exposure at default (EAD, Exposure at Default).
●General approach: applied to financial assets other than trade accounts receivable, contractual assets or lease receivables. This approach is based on the evaluation of significant increases in the credit risk of financial assets, from the date of initial recognition. If on the reporting date of the financial statements the credit risk has not increased significantly, the impairment losses are measured
In general, the measurement of expected credit losses for financial assets other than trade accounts receivable, contractual assets or lease receivables, are performed separately. ●Simplified approach:The Group applies a simplified approach for trade receivables, contract assets and lease receivables so that the impairment provision is always recognized
To measure the expected credit losses collectively, the Group considers the following assumptions: F-37
On the basis of the benchmark market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for Based on specific evaluations performed by Management, the prospective adjustment can be applied considering qualitative and quantitative information to reflect possible future events and macroeconomic scenarios, which may affect the risk of the portfolio or the financial instrument. g.4) Financial liabilities other than derivatives
Lease liabilities are initially measured at the present value of future lease payments, determined in accordance with the criteria described in Note 3.f. In the particular case that a liability is the hedged item in a fair value hedge, as an exception, such liability is measured at its fair value for the portion of the hedged risk. In order to calculate the fair value of debt, both when it is recorded in the statement of financial position and for fair value disclosure purposes as shown in Note g.5) Derivative financial instruments and hedge accounting Derivatives held by the Group are transactions entered into to hedge interest and/or exchange rate risk, intended to eliminate or significantly reduce these risks in the underlying transactions being hedged. Derivatives are recorded at fair value at the end of each reporting period as follows: if their fair value is positive, they are recorded within “Other financial assets” F-38 liabilities”. For derivatives on commodities, Changes in fair value are accounting established by IFRS are met, including that the hedge
statement of income. As a general rule, long-term commodity purchases or sales agreements are recognized in the statement of financial position at their fair value at the end of each reporting period, recognizing any differences in value directly in profit or loss, except for, when all of the following conditions are met:
The long-term commodity purchase or sale agreements maintained by the Group, which are mainly for electricity, fuel, and other supplies, meet the conditions described above. The Group also evaluates the existence of derivatives embedded in contracts or financial instruments to determine if their characteristics and risk are closely related to the host contract, provided that when taken as a whole they are not being accounted for at fair value. If they are not closely related, they are recorded separately and changes in value are accounted for directly in the statement of comprehensive income. F-39 g.6) Derecognition of financial assets and liabilities Financial assets are derecognized when:
Financial liabilities are derecognized when they are g.7) Offsetting of financial assets and financial liabilities The Group offsets financial assets and liabilities and the net amount is presented in the statement of financial position only when:
g.8) Financial guarantee contracts The financial guarantee contracts, defined as the guarantees issued by the Group to third parties, are initially measured at their fair value, adjusted for transaction costs that are directly attributable to the issuance of the guarantee.
h) measurement The fair value of an asset or liability is defined as the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market, namely, the market with the greatest volume and level of activity for that asset or liability. In the absence of a principal market, it is assumed that the transaction is carried out in the most advantageous market available to the F-40 entity, namely, the market that maximizes the amount that would be received to sell the asset or minimizes the amount that would be paid to transfer the liability. In estimating fair value, the Group uses valuation techniques that are appropriate for the circumstances and for which there is sufficient data to perform the measurement where it maximizes the use of relevant observable data and minimizes the use of unobservable data. Given the hierarchy explained below, data used in the valuation techniques, assets and liabilities measured at fair value can be classified at the following levels:
The Group takes into account the characteristics of the asset or liability when measuring fair value, in particular:
Financial assets and financial
The Group’s interests in joint ventures and associates are recognized using the equity method of accounting. Under the equity method of accounting, an investment in an associate or joint venture is initially recognized at cost. As of the acquisition date, the investment is recognized in the statement of financial position based on the share of F-41 The financial statements of associates or joint ventures are prepared for the same reporting period as the Group. When necessary, adjustments are made to align the accounting policies with those of the Group. Goodwill from the associate or joint venture is included in the carrying amount of the investment. It is not amortized but is subject to impairment testing as part of the overall investment carrying amount when there are indicators of impairment. Dividends received from these investments are deducted from the carrying amount of the investment, and any profit or loss obtained from them to which the Group is entitled based on its ownership interest is recognized under “Share of profit (loss) of associates accounted for using the equity The companies classified as Inventories are measured at their weighted average acquisition cost or the net realizable value, whichever is lower. The net realizable value is the estimated selling price in the ordinary course of business less the The cost of inventories includes all costs of purchase and all necessary costs incurred in bringing the inventories to their present location and rebates. k) Non-current assets (or disposal Non-current assets, including property, plant and equipment; intangible assets; investments accounted for using the equity method of accounting and joint ventures and disposal groups (a group of assets
For the above be committed to the sale or distribution and actions to complete the transaction must have been initiated and should be expected to be completed within one year from the date of classification. Actions required to complete the sale or distribution plan should indicate that it is unlikely that significant changes to the plan
Depreciation and amortization on these assets cease when they meet the criteria to be classified as non-current assets held for sale or held for distribution to owners. Assets that are no longer classified as held for sale or held for distribution to owners, or are no longer part of a disposal group, are measured at the lower of their carrying amounts before being classified as held for sale or held for distribution, less any F-42 classified as held for sale or held for distribution to owners and their recoverable amount at the date of Non-current assets held for sale and the components of the disposal groups classified as held for sale or held for distribution to owners are presented in the consolidated statement of financial position as a single line item within assets owners”. The Group classifies as discontinued operations those components of the Group that either have been disposed of, or are classified as held for sale and:
Treasury shares are Gains and losses from the disposal of treasury shares are recognized directly in Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation. The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material). The unwinding of the discount is recognized as finance cost. Incremental legal Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of resources embodying economic benefits will be required to settle the obligation, the provision is reversed. A contingent liability does not result in the recognition of a provision. Legal costs expected to be incurred in defending a legal claim are expensed as F-43 m.1) Provisions for post-employment benefits and similar obligations
internal provision. For defined benefit plans, the companies record the related expense for these commitments following the accrual criteria over the service life of the employees through timely actuarial studies performed as of the reporting date calculated applying the projected credit unit method. The cost of The defined benefit plan obligations in the statement of financial position represent the present value of the accrued obligations, Actuarial gains and losses arising n) Translation of balances in foreign currency Transactions Likewise, at the end of each reporting period, The Group has established a policy to hedge the portion of revenue from its consolidated entities that is directly linked to variations in the U.S. dollar, through obtaining financing in such currency. Exchange differences related to this debt, which is regarded as the hedging instrument in cash flow hedge transactions, are recognized, net of taxes, in other comprehensive income and are accumulated in an equity reserve and
o) Classification of balances as current and non-current In these consolidated statements of financial position, assets and liabilities expected to be recovered or settled within twelve months are presented as current assets and liabilities expected to be recovered or settled in more than twelve months are presented as non-current items. Deferred income tax assets and liabilities are classified as non-current. When the Group Income tax expense for the period is determined as the sum of current taxes from each of the Group’s subsidiaries and results from applying the tax rate to the taxable income for the period, after F-44 Deferred tax assets are recognized for all deductible temporary differences, tax losses and unused tax credits to the extent that it is probable that sufficient future taxable profits exist to recover the deductible temporary differences and
With respect to deductible temporary differences associated with investments in subsidiaries, associates and joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profits will be available against which the temporary differences can be utilized. Deferred tax liabilities are recognized for all temporary differences, except for those derived from the initial recognition of goodwill and those that arose from investments in subsidiaries, associates and joint ventures in which the Group can control their reversal and where it is probable that they will not be reversed in the foreseeable future. Current tax and changes in deferred tax assets or liabilities are recorded in profit or loss, other comprehensive income or total equity in Any tax deductions that can be applied to current tax liabilities are credited to earnings within the line item “Income tax expenses”, except when At the end of each reporting period, the Group reviews the deferred Deferred tax assets and deferred tax liabilities are offset in the consolidated statement of financial position if the Group has a legally enforceable right to set off current tax assets against current tax liabilities, and only when the deferred taxes relate to income taxes levied by the same q) Revenue and expense recognition Revenue is recognized when (or as) the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which The Group analyzes and takes into consideration all the relevant facts and circumstances for revenue recognition, applying the five step The following are the criteria for revenue recognition by type of good or service provided by the Group:
F-45 or at the marginal cost of energy and power, depending on whether they are unregulated customers, regulated customers or energy trading in the spot market are involved, respectively.
In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance
The Group excludes the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue
In addition, the Group evaluates the existence of incremental costs of obtaining a contract and costs directly related to the fulfillment of a contract. These costs are recognized as an asset, if their recovery is expected, and amortized in a manner consistent with the transfer of the related goods or services. As of December 31, 2020 and 2019, the Group has not incurred costs to obtain or perform a contract which meet the conditions for their capitalization. The costs incurred to obtain a contract are substantially commission payments for F-46 sales that, although are incremental costs, relate to short-term contracts or performance obligations that are met at a certain time, therefore, the Group has decided to recognize these costs as an expense when they occur. Interest Basic earnings per share are calculated by dividing net income attributable to shareholders of the Parent Company by the weighted average number of ordinary shares of outstanding during the period, excluding the average number of shares of the Basic earnings per share for continuing and discontinued operations are calculated by dividing net income from continuing and discontinued operations attributable to shareholders of the Group. Diluted Article No. 79 of As it is practically impossible to achieve a unanimous agreement given
Share issuance costs, only when they represent incremental expenses directly attributable to the transaction, are recognized directly in net equity as a deduction from “Share premiums,” net of any applicable taxes. If the share premium account has a zero balance or if the costs described exceed the balance, they are recognized in “Other Share issuance and placement expenses directly related to a probable future transaction are recorded as prepaid expenses in the statement of financial position. These expenses are recorded in equity upon issuance and placement of the shares, or in profit or loss when the condition changes and the transaction is no longer expected to occur. F-47 The statement of cash flows reflects changes in cash and cash equivalents that took place during the period, determined with the direct method. It uses the following
4. SECTOR REGULATION AND ELECTRICITY SYSTEM
The Chilean electricity sector is regulated by the General Law of
Within the Ministry of Energy is the regulatory body of the electricity sector (the National Energy Commission) and the oversight entity (the Superintendency of Electricity and Fuels). The Ministry also The National Additionally, the legislation considers a Panel of Experts, composed of expert professionals whose key job is to decide on any discrepancies produced in terms of the matters established in the Electricity Law and in the application of other laws on energy, through binding rulings. The Law establishes a National Electric Coordinator, an independent body of public law, responsible for the operation and coordination of the Chilean electricity system, whose main From a physical F-48 2,400
The Chilean electricity industry can be divided into three main activities: Generation, Transmission and Distribution. The electricity Due to their essential
are valued. On the other hand, the CNE determines the prices of Capacity. Consumers are classified according to the size of their demand system.
In Chile, In principle, The Generation companies must A generation company may have the following types of customers:
F-49
In Chile, the capacity Non-Conventional Renewable Energies Law No. 20,257 The transmission Interconnected Systems. The transmission The planning of the National Transmission and Zonal Transmission The expansions of both systems The remuneration of new works corresponds to the resulting value
Segment The distribution Distribution companies operate under a
F-50
network. Regarding the supply for users subject to price regulation, the not under contract. The On December 21, 2019, the Ministry of Energy published Law No. 21,194 (Short Law) which reduces the Profitability of Distribution Companies and modifies the Electricity Distribution rate process. To determine the AVD, the CNE classifies companies with similar distribution Subsequently, the rates are structured and the Additionally, The Chilean distribution Laws 2019 - 2020
On November 2, 2019, the Ministry of Energy published Law No. 21.185, which creates a Transitory Mechanism to Stabilize Electricity Prices for Customers Subject to Rate Regulation. Through this Law, between July 1, 2019 and December 31, 2020, the prices to be transferred to regulated customers are the price levels defined for the first half of 2019 (Decree 20T/2018) to be referred to as “Stabilized Price to Regulated Customers” (PEC). Between January 1, 2021 and until the end of the stabilization mechanism, prices shall be those defined in the semiannual price-setting processes referred to in article 158 of the Electricity Law, but may not be higher than the adjusted PEC according to the Consumer Price Index as of January 1, 2021, based on the same date (adjusted PEC). Any billing differences that arise will generate an account receivable in favor of the generators, up to a limit of MUS$ 1,350 until 2023. The balance must be recovered by December 31, 2027. The technical provisions on this mechanism are established in Exempt Resolution No. 72/2020, of the National Energy Commission, and its modifications. F-51
On December 21, 2019, the Ministry of Energy published Law No. 21,194, which reduces the Profitability of Distribution Companies and modifies the Electricity Distribution rate process. This Law eliminates the proportion of two-thirds for the AVD study performed by the CNE and one-third for the AVD study done by distribution companies, replacing it with a single study ordered by the CNE. On the other hand, it modifies the renewal rate for the calculation of annual investment costs from an annual real rate of 10% to a rate calculated by the CNE every four years, which shall be an annual rate that may be no less than 6% and no greater than 8% after taxes. The economic profitability rate after taxes for distribution companies must not differ by more than two points higher or three points lower than the rate defined by the CNE. Additionally, distribution companies must have an exclusive line of business as of January 2021.
On June 9, 2020, Exempt Resolution No. 176 was published in the Official Gazette. This resolution determines the scope of the Exclusive Line of Business and Separate Accounting obligations, for the provision of public electricity distribution service in accordance with Law No.21,194. According to this Resolution and its modifications, the distribution companies acting as public service concessions companies and operating in the National Electricity System must be constituted exclusively as distribution companies and may only perform economic activities aimed at providing public distribution services, in accordance with the requirements established by Law and current regulations. The requirements contained in said Resolution shall be applied starting January 1, 2021. Notwithstanding the above, those operations that by nature cannot be performed prior to this date must be reported and justified to the CNE, including a planning schedule and the compliance periods for the respective requirements, which under no circumstances may exceed January 1, 2022.
On August 8, 2020, the Law on Utility Services was passed. This law considers extraordinary measures to support the most vulnerable customers, although Enel Distribución Chile had already been applying most of these measures. These measures include the suspension of the electricity supply disconnection due to default and the possibility of signing agreements to pay off electricity debt in installments, in both cases, for a group of vulnerable customers. The suspended disconnection benefit was for a duration of 90 days following publication of the Law, and debts accumulated by customers covered by this measure must be paid within a maximum of 12 installments from the end of the grace period. On December 29, 2020, Law No. 21,301 was ratified and extended the terms defined in Law No. 21,249, establishing a benefit duration of 270 days following ratification of this new Law, as opposed to the initial 90 days. Likewise, the number of installments was modified to a maximum of 36, instead of the previously defined maximum of 12 installments.
On January 21, 2021, the Law on Electro-Dependent Individuals was passed to address home healthcare patients whose health treatment requires them to be physically connected permanently or temporarily to a medical device that operates on electricity. The law establishes that concessions companies must keep a record of electro-dependent individuals residing in their respective concessions zones, who have a certificate from their attending physician to accredit such condition, indicating the medical device they require for treatment and its characteristics. F-52 On the other hand, concessions companies must implement any technical solutions to help mitigate the effects of interruptions to the electricity supply, and prioritize reestablishing service to the residence of electro-dependent individuals. Moreover, they must incorporate a mechanism between the home’s central connection system and the medical devices to measure the consumption, at the company’s expense, and this measurement must be discounted from the home's monthly total consumption. This law will go into effect once the respective regulations have been issued, within six months from the publication of the law. (vi)Electricity Portability Bill On September 9, 2020, a bill was filed at the Chamber of Representatives for the purpose of modifying the General
By
By CNE 2021 Regulatory Plan By way of Exempt Resolution No. Regulations Published in
Regulations on the
Regulation Standard 4. On March 5, 2020, the
F-53
Modification to the Regulations on Sufficiency Capacity.On December Additionally, it establishes a calculation methodology to recognize the sufficiency capacity for hydroelectric plants with storage capacity. Expansion of Transmission 2017 Transmission Expansion In On January 9, 2019, the Ministry of Energy published Exempt Decree No. 4/2019, which establishes the New Works on the National and Zonal Transmission Systems to begin their bid process during the following twelve months. 2018 Transmission Expansion Plan
On August 10, 2019, the Ministry of Energy published Exempt Decree No. 198/2019, which establishes the Expansion Works to the National and Zonal Transmission Systems to begin their bid process during the following twelve months, corresponding to the 2018 expansion plan. 2019 Transmission Expansion Plan In compliance with the process phases stipulated by law, the Ministry of Energy published Exempt Decree No. 185/2020 on October 2, 2020, which establishes the New Works on the National and Zonal Transmission Systems to begin their bid process or area studies, as applicable, during the following twelve months, according to the 2019 expansion plan. On September 14, 2020, the Ministry of Energy published Exempt Decree No. 171/2020, which establishes the Expansion Works to the National and Zonal Transmission Systems to begin their bid process during the following twelve months, corresponding to the 2019 expansion plan. 2020 Transmission Expansion Plan In accordance with article 91 of Law 20,936/2016, which establishes the Transmission Planning F-54 c. Tariff Revisions and Supply Processes c.1 Distribution Price-Setting 2016 - 2020 The price-setting process for the 2016-2020 period culminated on August 24, 2017 with the
On September 28, 2018, the Ministry of Energy On July 26, 2019, through Ordinary Official Letter No. 15699/2019, the SEF instructed a plan of
The
On F-55 On
On October 23, 2019, the Ministry of Energy published Decree No. On April 7, 2020, the
On c.2 Distribution Price Setting 2020-2024 Through Exempt Resolution No. 24 of January 21, 2020, the CNE published the Preliminary Technical Terms and Conditions for calculating the components of the Added Value of Distribution for the 2020-2024 period, and the Cost Study on electricity supply-related services, initiating the distribution price setting process for the corresponding four-year period. In compliance with the process phases established by law, the interested parties made observations on the terms and conditions and submitted discrepancies to the Panel of Experts. Then, on June 11, 2020, the CNE published the Final Technical Terms and Conditions in Exempt Resolution No. 195. On July 17, 2020, Exempt Resolution No. 256 constituted the Cost Studies Committee established in article 183 bis of the General Law of Electricity Services. Through Exempt Resolutions No. 336 and 366 of September 1, 2020 and September 24, 2020, respectively, updates were incorporated to Exempt Resolution No. 256 regarding the primary and alternate representatives. On August On November 17, 2020, Progress Report No. 1 of the study was submitted, and Exempt Resolution No. 4 of January 4, 2021 extended the deadlines for Progress Report No. 2 and the Final Report to February 8, 2021 and March 8, 2021, respectively. c.3 Price Setting for Distribution-Related Services On July 24, 2018, the Ministry of Energy published Decree No. 13T/2018 in the Official Gazette,
F-56 c.4 Zonal Transmission Price Setting On October 5, 2018, the
In this context, for the purposes of the 244. In
Finally, for the purposes of In In compliance with the phases considered by Law, the With respect to the
Under the new bids law,
47.60/MWh, and incorporating new participants into the market. The most successful bidder in the 2015/01 process was Enel Generación Chile, which was awarded F-57
The 2017/01 As in the previous process, the most successful bidder was Enel Generación Chile, which was awarded A future bid process (2021/01) is considered for the supply period between 2026 and 2040, for an annual volume of 2,310 GWh. The deadline for the presentation of bids is May 28, 2021.
Corporate Considering the high priority given to renewable energies in the S.A. Enel Chile and Enel Generación Chile are entities registered with the Financial Market Commission Commission. EGPL was an indirect subsidiary of Enel S.p.A., The
Enel Chile
Enel Chile undertook a capital increase (the “Capital increase”) in order to
F-58
Shareholders. Finally, on March 25, 2018, This merger was accounted for in accordance with the accounting criteria established in Note 2.7.5 and generated a charge to Other miscellaneous reserves under Enel Chile's equity, in the amount of ThCh$407,354,462 (see Note 27.5.c.v.).
F-59
Time deposits have a maturity of three months or less from their date of acquisition and accrue the market interest for this type of short-term investment. Other fixed-income
F-60
ASSETS The detail of other financial assets as of December 31,
F-61
F-62 9. TRADE AND OTHER
a.1) Increase in trade and other receivables: The main increase as of December 31, On November 2, 2019, the Ministry of Energy published Law No. 21,185, which creates a Transitory Mechanism to Stabilize Electricity Prices for Customers Subject to Rate Regulation. By this Law, between July 1, 2019 and Between January 1, 2021 and up to the end of the stabilization mechanism, prices shall be those defined in the semiannual price-setting processes mentioned in article 158 of the Electricity Law, but may not be higher than the adjusted PEC according to the Consumer Price Index from January 1, 2021, based on the same date (adjusted PEC). The differences produced between the billing period while applying the stabilization mechanism, and the theoretical billing, considering the price that would have been applied according to the conditions of the respective contracts with the Electricity Distribution companies, will generate an account receivable in favor of the Electricity Generation companies, up to a maximum of US$1,350 million until 2023. All billing differences will be recorded in USD and will not accrue financial remuneration until December 31, 2025. The balance must be recovered by December 31, 2027 at the latest. F-63 The application of this Law generates a greater delay in the billing and collection of sales generated in the Company´s Electricity Generation segment, with the corresponding financial and accounting impact this situation generates. In the case of the Company´s Electricity Distribution segment, the financial and accounting effects are neutralized (pass-through principle). On September 14, 2020, the National Energy Commission published Exempt Resolution No. 340, which modified the technical provisions for the implementation of the Rate Stabilization Law. This Resolution clarified that the payment to each supplier “must be allocated to the payment of Balances chronologically, paying from the oldest to the newest Balances,” and not on a weighted basis over the total balances pending payment, as the industry practice had been until that date. In addition, this Resolution established that the payment of Balances shall be performed using the USD exchange rate observed on the business day following publication of the Coordinator's Balance Payment Chart, instead of the average USD exchange rate during the billing month, as established up to that moment. As a result of the abovementioned situations, and after eliminating transactions between related companies, the accounting effects recorded by the Group are summarized as follows:
The aforementioned trade and non-trade concepts, while included in the model to determine impairment losses (see Note 3.g.3), have no greater impact at the close of December a.2) Transfer of collection rights from On December 28, 2020, Enel Distribución Chile and Inter-American Investment Corporation entered into a framework agreement by which Enel Distribución Chile, from time to time, may transfer the collection rights it owns and derived from part of F-64 As indicated above, Enel Distribución Chile can continue to
a.3) Others There are no restrictions on the disposal of these types of accounts receivable in a significant amount. The Group For amounts, terms and conditions
As of December 31, 2020 and 2019, future collections on financial lease receivables are the following.
The decrease of ThCh$62,319,952 in accounts payable compared to December 31, 2019, is mainly due to the sale of electric bus lease agreements on August 19, 2020 by the Company’s subsidiary Enel X Chile to its associate Enel AMPCl Ebus Chile SpA. As of December 31,
F-65
(*) As of December 31, 2020, the impairment losses of trade receivables amounted to ThCh$15,167,707, representing a 51% increase over the loss of ThCh$10,047,000 recorded at December 31, 2019. This increase is mainly due to the effects of COVID-19 on the economy, a deterioration in the payment capacity of a segment of customers, a prolonged lockdown with its effects on different commercial and industrial activities, and the inability to disconnect residential customers pursuant to Law No. 21,249, the Law on Utility Services, whose terms were extended by Law No. 21,301, among other factors. See more information in Note 4.b.iv “Sector Regulation – and Electricity System Operations – Regulatory Matters,” Note 31 Write-offs
F-66
PARTIES Related party transactions are performed at current market conditions. Transactions between companies comprising the Group Note. As of the date of these consolidated financial statements, there are no entities. The controlling Enel Chile S.A. provides administrative services to its subsidiaries, through a centralized cash contract used to finance cash deficits or consolidate cash surpluses. These accounts may have a debtor or creditor balance and are prepayable, short-term accounts with a variable interest rate that represents market conditions. To reflect these market conditions, the interest rates are reviewed periodically through an update procedure approved by the Boards of Directors of the respective companies.
F-67 10.1 Balances and transactions with related parties The balances of accounts receivable and payable a) Receivables from related parties
F-68 b) Accounts payable to related parties
(*)See F-69 c)Significant transactions and effects on
F-70
The current Board of Directors F-71 a) There are no outstanding
b) Compensation for directors In accordance with Article 33 of Law
According to the provisions of the bylaws, the remuneration of the Chairman of the Board will be twice that of a Director. In the event a Director of Enel Chile S.A participates in more than one Board of Directors of domestic or foreign subsidiaries and / or affiliated, or acts as director or consultant for other domestic or foreign companies or legal entities in which Enel Chile S.A. has direct or indirect interest, he/she may receive remuneration only in one of said Board of Directors or Management Boards. The executive officers of Enel Chile S.A. and/or its domestic or foreign subsidiaries or affiliates will not receive remunerations or per diem allowances if acting as directors in any of Enel Chile S.A.’s domestic or foreign subsidiaries, affiliates or investee in any way. However, said remunerations or per diem allowances may be received by the executive officers as long as they are previously and expressly authorized as advances of their variable portion of remuneration by the corresponding companies with which they are associated through an employment contract. Directors’ Committee: Each member will be paid a monthly compensation, one part a fixed monthly fee and another part dependent on meetings attended. This compensation is broken down as follows: - UF 72 as a fixed monthly fee, in any event, and - UF 26.4 as a per diem for each Board meeting attended, all with a maximum of
F-72 The following tables show details of the compensation paid to the members of the Board of Directors of the Company for the
c) Guarantees given by the Company in favor of the directors No guarantees have been given 10.3 Compensation of key management personnel Enel Chile's key personnel as of December 31, 2020 is comprised of the
- Pedro Urzúa Frei, Institutional Relations Manager
- Andrés Pinto Bontá, Security Manager - Ángel Barrios Romo, Digital Solutions Manager
remunerations. Compensation
No guarantees have been given to key management personnel.
There are no payment plans granted to the Directors or key management personnel based on the share price of the 11. INVENTORIES The detail of inventories as of December 31,
There are no inventories For the years ended December 31, F-74 corresponding to 2020 includes ThCh$ 21,246,157 and ThCh$ 328,626 for the adjustment of impairment of coal inventories and of diesel oil, respectively, related to the process of closure operations of the Bocamina II power plant (see Note 16.c.iv).
F-75
F-76
None of
F-77 14. INTANGIBLE ASSETS OTHER THAN The balances of this caption as of December 31, 2020 and 2019 are presented below:
The following table presents intangible assets other than Goodwill as of December 31,
F-78
2018. According to the
15. GOODWILL The following table
According to the Group The origin of the goodwill is detailed below:
On F-79
On May 11, 1999, Enersis S.A. (currently Enel Américas S.A.) acquired an additional 35% ownership interest in
On October 1, 2019, Gasatacama Chile S.A. merged with Enel Generación Chile S.A.,
On April 22, 2014, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired
On July 12, 2002, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired 2.51% of the shares of Empresa Eléctrica Pangue S.A. On May 2, 2012, Empresa Eléctrica Pangue S.A. merged with Compañía Eléctrica San Isidro S.A., with the latter
On August 11, 2005, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired On September 1, 2013, Compañía Eléctrica San Isidro S.A. On November 1, 2013, Endesa Eco S.A.
On March 26, 2013, Enel Green Power Chile S.A. On August 6, 2001, Enel Green Power Chile
F-80 16. PROPERTY, PLANT AND EQUIPMENT The following table
F-81 The
Additional information on property, plant and equipment, net a) Main investments
In the In the F-82
Following the accounting criteria described in Note 3.a), only those investments made in the abovementioned generation projects qualify as assets suitable for capitalizing interest. As a whole, these projects represent cumulative cash disbursements in the amount of ThCh$780,827,755 and ThCh$543,844,674, as of December 31, 2020 and 2019. b) Capitalized b.1) Capitalized financial expenses
The increase in interest capitalization evidenced during 2020 is mainly explained by a greater development of non-conventional renewable energy projects and by a greater continuity in the development of the Los Cóndores project. Note that, with respect to the Los Cóndores project, given the difficulties inherent to a project of this magnitude and the impacts related to COVID-19, which implied some suspensions in the execution of the same during the last year, an update of the project schedule was provided by Enel Generación Chile in an essential fact dated July 27, 2020, estimating that it will be completed in the last quarter of 2023. b.2) Capitalized The capitalized cost for personnel expenses directly related directly to constructions in progress amounted to ThCh$ The increase in the capitalization of interest and personnel expenses compared to 2019 is mainly due to a greater development of non-conventional renewable energy projects. c) Other information
Additionally, the Group has civil liability insurance policies for third-party claims up to a limit of €500 million (ThCh$436,650,000) when these claims are due to the rupture of any dams owned by the Company or its Subsidiaries, and Environmental Civil Liability to cover environmental damage claims up to €20 million F-83 (ThCh$17,466,000). The premiums associated with these policies are recorded proportionally to each company in the caption prepaid expenses.
Development during 2019 On June 4, 2019, the Company’s subsidiaries Enel Generación Chile and Gasatacama Chile entered into an agreement by which both companies, in line with their own sustainability strategy and strategic plan, and the Ministry of Energy, regulated how they would proceed to progressively eliminate the Tarapacá, Bocamina I and Bocamina II coal-fired generation units (hereinafter, Tarapacá, Bocamina I and Bocamina II). The agreement is subject to the condition precedent that the regulations on capacity transfers between generation companies go into force, which establishes, among other things, the essential conditions to ensure non-discriminatory treatment among the generators and to define the State of Strategic Reserve. By virtue of the above, Enel Generación Chile and Gasatacama Chile would formally and irrevocably agree to the final withdrawal of Bocamina 1 and Tarapacá, respectively, from the National Electricity System, establishing their deadlines at May 31, 2020 for Tarapacá, and December 31, 2023 for Bocamina I. The Group stated its intention to accelerate the withdrawal of Tarapacá and Bocamina I, promoting the termination of their operations, all fully coordinated with the Authority. Within this context, on June 17, 2019, Gasatacama Chile submitted a request to the National Energy Commission (hereinafter CNE) to perform the final withdrawal, disconnection, and termination of operations of Tarapacá at an earlier date, i.e., by December 31, 2019. On July 26, 2019, by Exempt Resolution No. 450 and in accordance with the provisions of article 72 -18 of the General Law of Electricity Services, the CNE authorized the final withdrawal, disconnection, and termination of operations of Tarapacá from December 31, 2019. The management of the Tarapacá and Bocamina I assets will be carried out separately, and these assets will not form part of the Cash-Generating Unit formed by the rest of the plants owned by the Enel Generación Chile Group, whose economic management is performed in an integrated manner. Due to the abovementioned and as a result of impairment testing on an individual basis, in 2019 the Group recognized impairment losses in the amount of ThCh$197,188,542 and ThCh $82,831,721 to adjust the carrying amount of the capitalized investment in Tarapacá and Bocamina I, respectively, to their recoverable amount. The resulting recoverable amount, after the recorded impairment, corresponds to the value of the lands held in Tarapacá and Bocamina I, in the amount of ThCh$1,613,803 and ThCh$ 6,362,581, respectively. With respect to Bocamina II, Enel Generación Chile set a goal for its early withdrawal by December 31, 2040, at the latest. All of the above was subject to the authorization established in the General Law of Electricity Services. The financial effects would depend on the factors involved in the electricity market behavior, such as fuel prices, hydrological conditions, the growth of electricity demand, and international inflation indexes, which could not be determined at the close of 2019. Notwithstanding the above, the useful lives of the Bocamina II assets were adjusted such that in any case, the depreciation would be calculated for any useful lives beyond December 31, 2040. This measure implied the recognition of a higher depreciation of ThCh$ 4,083,855 during 2019. Development during 2020: On May 27, 2020, the Board of Directors of Enel Generación Chile approved, subject to the corresponding CNE authorizations, the early withdrawal of Bocamina I and Bocamina II, establishing deadlines for such withdrawals on December 31, 2020 and May 31, 2022, respectively. The corresponding request was communicated to the CNE that same day. F-84 This decision shows the Company's commitment to fight against climate change and also considered the deep changes being experienced by the Industry, including the constant and increasing penetration of renewable energies and the reduction in commodities prices, making gas-powered production more competitive, which would give greater flexibility to the system's operations in comparison to coal-fired production. On July 3, 2020, the CNE issued Exempt Resolution No. 237 authorizing the final withdrawal, disconnection, and termination of operations of Bocamina I from December 31, 2020. Regarding Bocamina II, the Group also intended to accelerate its early closure, promoting the discontinuation of its operations in strict coordination with the Authority. In this context, on July 23, 2020, the CNE issued Exempt Resolution No. 266 authorizing the final withdrawal, disconnection, and termination of operations of Bocamina II as of May 31, 2022. As occurred in 2019 with Tarapacá and Bocamina I, Bocamina II’s management assets will be managed separately and, accordingly, these assets will not form part of the Cash-Generating Unit consisting of the rest of the plants owned by the Enel Generación Chile Group, whose economic management continues to be carried out in a centralized manner. Consequently, and as a result of impairment testing on an individual basis, in 2020 the Group recorded an impairment loss of ThCh$697,856,387 to adjust the carrying amount of the capitalized investment in Bocamina II to its recoverable value (See Note 31). The resulting recoverable value, after the impairment recorded, corresponds to the value of the land associated with this plant, which as of December 31, 2020 was ThCh$2,014,684. These situations have effects on deferred taxes, which are disclosed in Note 19.b.
The investment property breakdown and activity during 2020 and 2019 are detailed as follows:
During 2020 and 2019, no real estate property has been sold. F-85
As of December 31, 2020, and 2019, the fair value of the investment was ThCh$8,484,901 and ThCh$7,880,432 respectively. This value was determined according to independent appraisals. The input data used in this valuation are considered to be Level 3 for the purposes of the fair value hierarchy. The fair value hierarchy for investment properties is the following:
See Note 3.h. The revenue and expenses derived from investment properties for the years ended December 31, 2020, 2019 and 2018,
2020 and 2019. The Group has engaged insurance policies to cover Right-of-use assets for the year ended December 31, 2020 and 2019, are detailed as follows:
F-86 As of December 31, 2020 and 2019, the main right-of-use assets and lease liabilities are detailed as follows: -These come primarily from a contract for Electricity Transmission Lines and Facilities (Ralco-Charrúa 2X220 KV), entered into by Enel Generación Chile S.A. and Transelec S.A. This contract has a duration of 20 years and accrues interest at an annual rate of 6.5%. -In addition, as a consequence of the application of IFRS 16 (see Note 3.f), the Group
amount of ThCh$28,814,142. The
a) Short-term and low-value leases The consolidated income As of December 31, 2020 and 2019, future payments derived from those contracts are detailed as follows:
F-87 19. INCOME TAX AND DEFERRED TAXES a) Income taxes The components of income tax for the years 2020, 2019 and 2018 are detailed as follows:
The following table
The main temporary differences are described below. F-88 b) Deferred taxes The
F-89
(1) See Note 16, c), iv). Recovery of deferred tax assets will depend on whether sufficient
31,2019). The Group Tax audits by nature are often complex and can require several years to complete.
2019. Given the range of possible interpretations of tax standards, the results of any future inspections carried out by F-90 The effects of deferred
The following table
F-91
The
(*) See Note 23.2.a (**)See Note 23.2.b
The detail of current and non-current interest-bearing borrowings as of December 31,
Bank
F-92
Fair value measurement and hierarchy The fair value of current and non-current bank borrowings as of December 31, F-93 Identification of bank borrowings by company
The detail of Unsecured Liabilities by currency and maturity as of December 31, Summary of
F-94 Individual identification of Unsecured liabilities by debtor.
As of December 31, Fair value measurement and hierarchy The fair value of the current and non-current secured and unsecured liabilities as of December 31,
The debt denominated in U.S. F-95 The following table details changes in “Reserve for cash flow hedges” as of December 31,
20.5 Other information As of December 31,
flows. The following tables are the estimates of undiscounted flows by type of financial debt:
F-96 As of December 31, 2020 and 2019, the balance of lease liabilities is as follows:
21.1. Individualization of Lease Liabilities
F-97
F-98
21.2. Undiscounted debt cash flows. Undiscounted debt cash flows are detailed as follows:
F-99 POLICY The To comply with this, each company has its own specific Control Management and Risk Management policy, which is reviewed and approved at the beginning of each year by the Enel Chile Board of Directors, observing and applying all local requirements in terms of the risk culture. The Company seeks protection against all risks that 37 sub-categories. The
Changes in interest rates affect the fair value of assets and liabilities bearing fixed interest rates, as well as, the expected future cash flows of assets and liabilities subject to floating interest rates. The objective of managing interest rate risk exposure is to achieve a balance in the debt structure to minimize the cost of debt with reduced volatility in profit or loss. The comparative structure of the Group's financial debt,
Depending on the Risk control through specific processes and indicators allows companies to limit possible adverse financial impacts and, at the same time, optimize the debt structure with an adequate degree of flexibility. In this sense, the volatility that Exchange rate risks involve basically the following transactions:
In order to mitigate foreign currency risk, the The hedging instruments currently being used to comply with the policy are currency swaps and forward exchange contracts. During the
The Group has a risk exposure to price fluctuations in certain commodities, basically due to:
Considering the operating conditions faced by the power generation market, As of December 31, 2020, there were current transactions for 1,782 kBbl from Brent to be settled in 2021 and 16.8 Tbtu from Henry Hub to be settled in 2021. As of December 31,
Depending on the Group’s permanently updated operating conditions, Thanks to the mitigation strategies implemented, the Group was able to minimize the effects of basic product price volatility on the results of the fourth quarter of 2020. The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets. The projected needs mentioned above include maturities of financial debt net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial 23). As of December 31, F-101 2019, the Group The Group closely monitors its credit risk. Trade receivables: The credit risk for receivables from the Group’s commercial activity has historically been very low, due to the In the Company’s electricity low. In the Regarding the Financial assets: Cash surpluses are invested in the highest-rated local and foreign financial entities (with risk rating equivalent to investment grade where possible) with thresholds established for each entity.
are selected for making investments. Investments may be It is noted that the downturn in the macroeconomic scenario due to COVID-19 had no significant impact on counterparties’ credit quality. The Group measures the Value at Risk (VaR) of its debt positions and financial derivatives, in order to monitor the risk assumed by the The portfolio of positions included for
The VaR determined represents the potential variation in value of the portfolio of positions described above in
F-102 The calculation of VaR is based on generating possible future scenarios (at one quarter) of market values The Taking into consideration the This
23.1 Financial instruments classified by type and category
F-103
The
The risk management policy of the Group uses primarily interest rate and foreign exchange rate derivatives to hedge its exposure to interest rate and foreign currency risks. The
F-104
As of December 31,
As of December 31,
These derivative instruments correspond to forward contracts entered into by the Group, whose purpose is to hedge the exchange rate risk related to future obligations arising from civil works contracts linked to the F-105 construction of the Los Cóndores Plant. Although these hedges have an economic substance, they do not qualify for hedge accounting because they do not strictly comply with the hedge accounting requirements established in IFRS 9 Financial Instruments.
The following
The contractual maturities of hedging and non-hedging derivatives hierarchies Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the The following table presents financial assets and liabilities measured at fair value as of December 31,
F-106
24. NON-CURRENT PAYABLES The detail of Trade and Other Current Payables as of December 31,
The
The expected
26.
Defined benefit plans:
a) The post-employment obligations associated with
(1) See Note 34 c) The balance and changes in post-employment defined benefit obligations as of
The Group makes no contributions to funds for financing the payment of these benefits.
As of December 31,
As of December 31,
F-110
F-111
27.1.1. Subscribed and paid capital and number of shares The issued capital of Enel Chile
On April 29, 2019, these shares were legally deducted from the number of shares issued, as they had not been sold within one year from the date of acquisition, in accordance with the provisions of Article 27 of the Corporations Law No. 18,046.
During the
Company. Any shareholder existing at the
The reorganization F-112
(1) The total amount (2) The payment made by the minority shareholders of Enel Chile was (3) The valuation of the capital increase due to the merger was ThCh$1,071,727,279. (4) The total amount paid for the
F-113 27.3 Foreign currency translation reserves
27.4 Restrictions on subsidiaries transferring funds to the Our subsidiary Enel
F-114
F-115
27.6 Non-controlling Interests The detail of non-controlling interests as of December 31, 2020, 2019 and 2018, is as follows:
F-116 28. REVENUE AND OTHER OPERATING INCOME The detail of
(1)As of December 31, 2020, a total of ThCh$434,442,879 is included in total revenue, corresponding to estimated and unbilled sales, which are related to estimations made of energy sold in the month of December 2020, including PEC and node prices. As of December 31, 2019 and 2018, the amounts correspond to ThCh$310,301,370 and ThCh$209,288,934, respectively. (2)For the year ended December 31, (3)For the year ended December 31, F-117 services of ThCh $21,407,325 (ThCh$18,975,909 and ThCh$19,629,502 as of December 31, 2019 and 2018, respectively) and other of ThCh$ (4)In February 2019, Anglo American Sur S.A. notified Enel Generación Chile of its decision to terminate early three electricity supply contracts, which both parties had signed in 2016. As stipulated in the termination clauses of the respective contracts, the notice of early termination granted Enel Generación Chile the right to receive termination compensation, consisting of a cash payment by Anglo American Sur S.A., which would be determined according to a predefined calculation mechanism. It is important to note that between the date of notice of the early termination and the date of effective termination of the contracts, there were no performance obligations pending delivery by Enel Generación Chile, as the original contracts established the start of supply in January 2021. Therefore, following the accounting criteria described in Note 3.q), income of ThCh$121,117,605 was recognized.
On June 21, 2019, Enel Generación Chile made a non-recourse assignment of the cash flows of this agreement. Consequently, the cash inflow resulted in the derecognition of the account receivable from Anglo American Sur S.A. existing at that date. (5) For the year ended December 31, 29. RAW MATERIALS AND CONSUMABLES USED The detail of raw materials and consumables used presented in profit or loss for the years ended December 31,
30. EMPLOYEE BENEFITS
F-118 31. DEPRECIATION, AMORTIZATION AND IMPAIRMENT
(*) Relates to the process to closure the operations of Bocamina II for ThCh$697,856,387 mainly, see Note 16, paragraph c), iv).
(*) See explanation in Note 16 e) paragraph vi). F-119
F-120 The origins of the effects on results for the application of adjustment units and foreign exchange gains (losses) are as follows:
F-121
35. INFORMATION BY SEGMENT
The Group’s activities operate under a matrix management structure with dual and cross management responsibilities (based on The Group adopted a “bottom-up” approach to determine its reportable segments. The Generation and Transmission and the Distribution reportable segments have been defined based on IFRS 8.9 and on the criteria described in IFRS 8.12. Generation Distribution Business: The Distribution
Each of the operating segments generates separate financial information, which is aggregated into one combined set of information for the Generation Business, and another set of combined information for the Distribution Business at the reportable segment level. In addition, in order to assist the decision maker process, the Planning & Control Department at the
The Company’s chief operating decision maker The information disclosed in the following tables is based on the financial information of the companies forming each segment. The accounting policies used to determine the segment information are the same as those used in the preparation of the Group’s consolidated financial statements.
F-122 35.2 Generation
The F-123
The Holding, Eliminations and Others column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services. F-124 36. GUARANTEES WITH THIRD guarantees As of December 31,
36.3 Lawsuits and Arbitration Proceedings As of the date of these consolidated financial statements, the most relevant litigation involving the Company and its subsidiaries are as follows:
F-125
F-126
F-127
F-128
F-129 In relation to the litigation proceedings described above, the Group has established provisions for
1.Cross Default Some of the financial debt contracts Enel
any amount
F-130 50% of the 283,294,982. The bank Enel Distribución Chile's uncommitted credit lines stipulate that cross default may be triggered by a default of the Issuer's own individual debt in any obligation contracted in favor of any creditor. Upon the occurrence of the event of default, the bank will communicate to Enel Distribución Chile about the termination of the credit line. As of December 31, 2020, these credit lines were not disbursed. 2. Financial covenants Financial covenants are contractual commitments with respect to minimum or maximum financial ratios that contract. The Enel Generación
H Series
F-131
M Series
-Consolidated Equity: Idem H Series. -Finance Expense Hedge Ratio: Idem H Series. The
As of December 31, Consolidated Indebtedness Level. The
the expiration of the remedial periods established therein, among other conditions. As of December 31, 36.5. COVID-19 contingency
To address this international public health emergency due to COVID-19, on March 18, 2020, President Sebastián Piñera decreed a State of Constitutional Exception of Catastrophe, establishing containment measures, specifically designed to restrict the free movement of people, which include curfews, mandatory selective quarantines, prohibition of mass meetings, temporary closure of companies and businesses, among other measures. Accordingly, the Company’s subsidiary Enel Distribución Chile announced it would adopt certain preventive measures, such as the suspension of meter readings and focusing field activities on essential operations for supply continuity. It also announced extraordinary measures to support the most vulnerable households, such as not disconnecting energy services due to customers being in payment default and offering payment installment plans, with no down payment or interest for customers in debt to the Company. Additionally, the Group issued guidelines to guarantee compliance with the measures introduced by the Chilean government and has taken a number of actions to adopt the most appropriate procedures to prevent and/or F-132 mitigate the effects of COVID-19 contagion among employees, while guaranteeing business continuity. This has been made possible mainly due to: The use of telework for all employees whose jobs can be performed remotely (75% of the staff). This work mode was introduced in the Group a few years ago, which thanks to digitalization investments, allows work to be performed remotely with the same level of efficiency and effectiveness; Digitalization of processes and infrastructure, which ensure the normal operation of the Company’s generation assets, continuity of the electrical service, and remote management of all activities related to the market and customer relations. All the Company's efforts continue to focus on guaranteeing the correct and safe operation of the Company’s businesses, while safeguarding the health and safety of the Company’s people. On August 5, 2020, Law No. 21,249 on Basic Utilities Services was enacted. This law includes extraordinary measures to support the most vulnerable customers, although Enel Distribución Chile had already been applying most of these measures. These measures include not disconnecting energy services due to customers being in payment default and the possibility of signing agreements to pay off electricity debt in installments, in both cases, for a group of vulnerable customers. The benefit associated with not disconnecting energy services due to customers being in payment default was effective for 90 days following the enactment of the Law, and debts accumulated by customers covered by this measure must be paid within a maximum of 12 installments from the end of the grace period. Subsequently, on December 29, 2020, Law No. 21,301 was enacted, which extended the terms defined in Law No. 21,249, setting the duration of the benefit to 270 days following the enactment of this new Law instead of the initial 90 days. Also, the number of installments was modified to a maximum of 36 instead of the 12 maximum installments previously defined. In relation to the degree of uncertainty generated in the macroeconomic and financial environments in which the Group operates and their effects on the Company's income as of December 31, 2020, these are fundamentally related to an increase in the impairment loss on trade receivables (see Notes 2.3, 3.g.3, 9.d and 26.2). Enel Chile's personnel, as of December 31,
F-133 The following Group companies have received sanctions from administrative authorities:
As of December 31,
As of December 31,
As of December 31, 2020, the Coquimbo Regional Health Ministry
for keeping waste in an unauthorized area, which is pending resolution. As of
By means of Exempt Resolution No.
pending resolution. In relation to the sanctions described above, the Group has established provisions for ThCh$ F-134 Environmental expenses for the years ended December
F-135
F-136
F-137 40. ON SUBSIDIARIES, SUMMARIZED As of December 31,
F-138
Additionally, on January 29, 2021, Enel Generación Chile and Enel Green Power Chile entered into an agreement with Chile Electricity PEC SpA subject to foreign legislation, referred to as Sale and Purchase Agreement (the “Sale Agreement”) for the The sales and transfers of As indicated before, Enel Generación Chile and
These loans are rated SDG-linked financing that aims to support economic activity linked to the environment and socially sustainable activities, promoting the debtor to contribute to certain UN Sustainable Development Goals.
F-139
The members of our new Board of Directors are as follows: • Mr. Herman Chadwick Piñera (Chairman) • Ms. Monica Girardi • Ms. Isabella Alessio • Mr. Salvatore Bernabei • Mr. Fernán Gazmuri Plaza • Mr. Pablo Cabrera Gaete • Mr. Luis Gonzalo Palacios Vásquez Between January 1, 2021 and the date of
F-140 APPENDIX 1 CURRENCY This appendix forms an integral part of the The detail of assets and liabilities denominated in foreign currency is as follows:
F-141
F-142
APPENDIX 2 ADDITIONAL INFORMATION 2012 This appendix is part of Note 9, “Trade and Other Receivables,” and forms an integral part of the consolidated financial statements of Enel Chile.
-By aging of trade and other accounts receivable:
F-143
F-144 APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES: This appendix is part of Note 9, “Trade and Other Receivables,” and forms an integral part of these consolidated financial
Since not all of our commercial databases in our Group’s
F-145
F-146 APPENDIX 2.2 TOLL This appendix forms an integral part of
F-147 APPENDIX 3 SUPPLIERS This appendix is part of Note 24, “Current and Non-Current Payables,” and forms an integral part of
F-148 |