Enel Chile - 20-F annual report 2020

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Enel Chile’s Simplified Organizational Structure⁽¹⁾

As of the date of this Report⁽²⁾

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GLOSSARY

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INTRODUCTION

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As used in this Report on Form 20-F (“Report”), first-person personal pronouns such as “we,” “us,” or “our,” as well as “Enel Chile” or the “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 controlled companies and associates is expressed in terms of our economic interest as of December 31, 2020.

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We are a Chilean company primarily engaged in 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 — The 2018 Reorganization”), we own 93.5% of Enel Generación Chile S.A. (“Enel Generation”), a Chilean electricity generation company with operations in Chile, and 99.1% of Enel Distribución Chile S.A. (“Enel Distribution”), a Chilean electricity distribution company which operates in the Santiago Metropolitan Region, and 99.1% of Enel Transmisión Chile S.A., through which we carry out sub-transmission activities.

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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 with operations in Chile, merged with us. As a result, we now wholly own and consolidate Enel Green Power Chile 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”.

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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.

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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.

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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 64.9% of us and is our ultimate controlling shareholder.

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PRESENTATION OF INFORMATION

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Financial Information

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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 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 to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month. As of December 31, 2020, one UF was equivalent to Ch$ 29,070.33. The U.S. dollar equivalent of one UF was US$ 40.89 as of December 31, 2020, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2020, of Ch$ 710.95 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 web page, is the weighted-average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Unless the context specifies otherwise, all amounts translated from Chilean pesos to U.S. dollars or vice versa, or from UF to Chilean pesos, have been made at the rates applicable as of December 31, 2020.

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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 under International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). All 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 interest in associated companies over which we exercise significant influence is included in our consolidated financial statements using the equity method. For detailed information regarding consolidated entities, jointly controlled entities, and associated companies, see Notes 2.4, 2.5, and 2.6 of the Notes to our consolidated financial statements.

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This Report contains translations of certain Chilean peso amounts into U.S. dollars at specified rates. Unless otherwise indicated, the U.S. dollar equivalent for information in Chilean pesos is based on the Observed Exchange Rate for December 31, 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 disclosed in this Report could have been or could be converted into U.S. dollars or Chilean pesos, at such rate or any other rate. See “Item 3. Key Information — A. Selected Financial Data — Exchange Rates.”

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Technical Terms

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References to “TW” are to terawatts (1012 watts or a trillion watts); references to “GW” and “GWh” are to gigawatts (109 watts or a billion watts) and gigawatt-hours, respectively; references to “MW” and “MWh” are to megawatts (106 watts or a million watts) and megawatt-hours, respectively; references to “kW” and “kWh” are to kilowatts (103 watts or a thousand watts) and kilowatt-hours, respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. References to “BTU” and “MBTU” are to British thermal unit and million British thermal units, respectively. A “BTU” is an energy unit equal to approximately 1,055 joules. References to “Hz” are to hertz, and references to “mtpa” are to metric tons per annum. Unless otherwise indicated, statistics provided in this Report concerning 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 present in this Report corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its 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 year like 2020, which is based instead on 8,784 hours. Statistics relating to installed capacity and production of the electricity industry do not include electricity of self-generators.

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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 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.

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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.

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Calculation of Economic Interest

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In this Report, references are made to the “economic interest” of Enel Chile in its related companies. We could have a direct and indirect interest in such companies. In circumstances in which we do not directly own an interest in an affiliated company, our economic interest in such ultimate affiliated company is calculated by multiplying the percentage of economic interest in a directly held affiliated company by the percentage of economic interest of any entity in the ownership chain of such affiliated company. For example, if we directly own a 6% equity stake in an affiliated 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%.

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Rounding

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Figures included in this Report have been rounded for ease of presentation. Due to rounding, the sums in tables do not always exactly equal the sums of the entries.

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FORWARD-LOOKING STATEMENTS

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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:

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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:

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 concerning 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 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.

Item 3.      Key Information

A.   Selected Financial Data.

The following selected consolidated financial data should be read in conjunction with our consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2020, and 2019, and for the three years ended December 31, 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, and for the years ended December 31, 2017, and 2016 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.

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The tables are expressed in millions, except for ratios, operating data, and data for shares and American Depositary Shares (“ADS”). For the reader’s convenience, all data presented in U.S. dollars in the following summary, as of and for the year ended December 31, 2020, has been converted at the U.S. dollar Observed Exchange Rate (dólar observado) for that date of Ch$ 710.95 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-average exchange rate of the previous business day’s transactions in the Formal Exchange Market. For more information concerning historical exchange rates, see “Item 3. Key Information — A. Selected Financial Data— Exchange Rates” below.

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

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Exchange Rates

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Fluctuations in the exchange rate between the Chilean peso and the U.S. dollar will affect the U.S. dollar equivalent of the 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 affect the price of our ADS and the conversion of cash dividends relating to the common shares represented by ADS from Chilean pesos to U.S. dollars. Also, to the extent that our significant financial liabilities are denominated in foreign currencies, fluctuations in the exchange rate may significantly impact our earnings.

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There 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 consists of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market includes entities that are not expressly permitted to operate in the Formal Exchange Market, such as 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 made on the Formal Exchange Market. Free market forces drive both the Formal and Informal Exchange Markets. Current regulations require that the Central Bank of Chile be informed of transactions that must be effected through the Formal Exchange Market.

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The U.S. dollar Observed Exchange Rate, which is reported by the Central Bank of Chile and published daily on its web page, is the weighted-average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Nevertheless, the Central Bank of Chile may intervene by buying or selling foreign currency on the Formal Exchange Market to attempt to maintain the Observed Exchange Rate within the desired range.

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The Informal Exchange Market reflects transactions carried out at an informal exchange rate. There are no limits imposed on the extent to which the exchange rate in the Informal Exchange Market can fluctuate above or below the U.S. dollar Observed Exchange Rate. Foreign currency for payments and distributions concerning the ADS may be

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purchased either in the Formal or the Informal Exchange Market, but such payments and distributions must be remitted through the Formal Exchange Market.

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The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. As of December 31, 2020, the U.S. dollar Observed Exchange Rate was Ch$ 710.95 per US$ 1.00. As of April 28, 2021, the U.S. dollar Observed Exchange Rate was Ch$ 700.15 per US$ 1.00.

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Calculation of the appreciation or devaluation of the Chilean peso against the U.S. dollar in any given period is made by determining the percent change between the reciprocals of the Chilean peso equivalent of US$ 1.00 at the end of the preceding period and the end of the period for which the calculation is being made. For example, to calculate the appreciation of the year-end Chilean peso in 2020, one determines the percentage change between the reciprocal of Ch$ 748.74, the value of one U.S. dollar as of December 31, 2019, or 0.0013355, and the reciprocal of Ch$ 710.95, the value of one U.S. dollar as of December 31, 2020, or 0.0014066. In this example, the percentage change between the two periods is 5.3%, representing the 2020 year-end appreciation of the Chilean peso against the 2019 year-end U.S. dollar. A positive percentage change means that the Chilean peso appreciated against the U.S. dollar, while a negative percentage change means that the Chilean peso devaluated against the U.S. dollar.

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The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2016, through December 31, 2020, based on information published by the Central Bank of Chile.

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Source: Central Bank of Chile.

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

Our businesses depend heavily on hydrology and are affected by droughts, flooding, storms, ocean currents, and other inclement weather conditions.

Approximately 49% of our installed generation capacity in 2020 was hydroelectric. Accordingly, arid hydrological conditions could negatively 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, which has been the case for much of the period since 2007.

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Our subsidiary Enel Generation has entered into certain agreements with the Chilean government and local irrigators regarding water use for hydroelectric generation purposes during low water levels. However, if droughts persist, we may face increased pressure from the Chilean government or other third parties to restrict our water use further.

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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. Depending on our commercial obligations, we may need to buy electricity at higher spot prices to comply with our contractual supply obligations. 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 concerning 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.”

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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:

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A full recovery from the extended droughts that, since 2007, have been affecting the regions where most of our hydroelectric power plants are located may take many years, and new drought periods may recur in the future. Prolonged droughts may exacerbate the risks described above and have a further negative effect on our business, results of operations, and financial condition.

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Our distribution business is also affected by inclement weather. Extreme temperatures can increase demand significantly within a short period, which may strain our service and result in service disruptions 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 left without electricity. In July 2017, an 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 in Santiago since 1970 and left parts of the capital without electricity for more 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.

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We are subject to physical, operational, and financial risks related to climate change effects.

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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 studies’ findings. They may be affected by changes in weather patterns, including the potential impact of climate change.

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If our renewable energy production falls below anticipated levels, we may have to dispatch our back-up thermal power 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 be at prices higher than the contracted electricity sales. These impacts could increase our costs or result in losses and have a material adverse effect on our business, results of operations, and financial condition.

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We depend on distributions from our subsidiaries to meet our payment obligations.

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

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Contractual Constraints: Distribution restrictions included in certain credit agreements of our subsidiaries may prevent dividends and other distributions to shareholders if they do not comply with specified financial ratios. Our credit agreements typically prohibit any distribution in the event of ongoing default.

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

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

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We are involved in litigation proceedings.

We are involved in various litigation proceedings that 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 unfavorably affected if we are unsuccessful in defending lawsuits and proceedings against us. Please see Note 36.3 of the Notes to our consolidated financial statements for further information on litigation proceedings.

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Construction and operation of power plants may encounter significant delays, stoppages, cost overruns, and stakeholder opposition that may damage our reputation and impair 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. They may be subject to construction delays, strikes, accidents, and human error. Any such event could negatively affect our business, results of operations, and financial condition.

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Market conditions may change significantly between the approval and completion of a project, which, in some cases, may decrease a project’s profitability or render it impracticable. This circumstance has been the case with many of our past projects that were initially planned under very different market conditions, with higher energy prices and less competition. Deviations in market conditions, such as estimates of timing and expenditures, may lead to cost overruns and delays in project completion that widely exceed our initial forecasts. In turn, this may have a material adverse effect on our business, results of operations, and financial condition.

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We may develop new projects in locations that sometimes involve a challenging geographical topography, in some cases on mountain slopes with limited access. These factors may also lead to delays and cost overruns. For example, Cerro Pabellón, our 41 MW geothermal power plant, was built at 4,500 meters above sea level and is currently constructing a third unit that will increase its capacity by 28 MW. We may face challenges associated with high-altitude construction, such as health concerns, affecting the schedule, and associated investments. Additionally, given some projects’ locations, there may be archaeological risks. In 2018, the Superintendence of the Environment filed charges against our subsidiary Geotérmica del Norte S.A. for infractions related to the archaeological and operational components of the Cerro Pabellón project, could result in high fines.

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Our thermal power plants’ operation, especially those that are coal-fired, may affect our goodwill with stakeholders due to GHG emissions that could unfavorably affect the environment and nearby residents. Furthermore, outside stakeholders may influence the interests and perceptions of the local communities about the Company. If we fail to address all relevant stakeholders’ concerns, including environmental, social and governance criteria (“ESG”), we may face opposition, which could negatively affect our reputation, stall operations, or lead to litigation threats or actions. Our reputation is the foundation of our relationship with key stakeholders and other constituencies. If we do not effectively manage these sensitive issues, they could adversely affect our business, results of operations, and financial condition.

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Damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders, possibly leading to the abandonment of projects and operations. This damage could cause our share prices to drop and hinder our ability to attract and retain valuable employees. Any of these outcomes could result in an impairment of our goodwill with stakeholders.

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

In our generation business, we have exposure to fluctuations in certain commodity market prices that affect our long-term electricity sales contracts. These contracts commit us to material obligations as selling parties and contain prices indexed to different commodities, exchange rates, inflation, and the market price of electricity. Unfavorable changes to these indices would reduce the rates we charge under these 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 exposed to fluctuations in electricity prices. Since 2016, some customers who had freely chosen regulated tariffs have switched to the unregulated tariff regime due to 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 tariffs due to the former being based on contracts tendered in the past at higher prices. Lower market prices may reduce the number of customers who choose regulated tariffs as they choose an alternative energy provider. This situation would reduce our number of customers and adversely affect our business, results of operations, and financial condition.

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

Our primary facilities include power plants and distribution assets that are exposed to damage from catastrophic natural disasters, such as earthquakes and fires, human causes, as well as acts of vandalism, 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 not covered by our business interruption insurance. There may be lags between a significant 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.

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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.

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Any natural or human catastrophic disruption to our electricity assets in Chile could significantly affect our business, results of operations, and financial condition.

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We are subject to financing risks, such as those associated with funding our new projects and capital expenditures or refinancing existing obligations.

As of December 31, 2020, our consolidated debt totaled Ch$ 2.9 trillion (including Ch$ 1.2 trillion with Enel Finance International N.V., a related company), and our most material debt obligation was the US$ 1.7 billion of SEC-registered bonds issued in the U.S. under the law of the State of New York.

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Our debt agreements are subject to several of the following provisions, including (1) financial covenants, (2) affirmative and negative covenants, (3) events of default, (4) mandatory prepayments for contractual breaches, (5) change of control clauses for material mergers and divestments, and (6) bankruptcy and insolvency proceeding covenants, among others.

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A significant portion of our financial indebtedness is subject to cross-default provisions, which have varying definitions, criteria, materiality thresholds, and applicability concerning subsidiaries that could result in cross-default. Our debt may also become immediately due and payable in cases involving bankruptcy or insolvency proceedings of a significant or material subsidiary. Likewise, some of our debtholders may decide to accelerate our debt in cross-default events dealing with significant or material subsidiaries, among other potential covenant defaults.

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We may be unable to refinance our debt or obtain such refinancing on terms acceptable to us. In the absence of such refinancing, we could be forced to liquidate assets at unfavorable prices to make payments due on our debt.

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Furthermore, we may be unable to sell our assets at opportune moments or sufficiently high prices to obtain proceeds that would enable us to make such payments.

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

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Our inability to finance new projects or capital expenditures, refinance our existing debt, or comply with our covenants could negatively affect our business, results of operations, and financial condition.

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If third-party electricity transmission facilities, gas pipeline infrastructure, or fuel supply contracts fail to provide us with adequate service, we may be unable to deliver the electricity we sell to our final customers.

We depend on transmission facilities owned and operated by other companies to deliver the electricity we sell. This dependence exposes us to several risks. If the transmission is disrupted, or its capacity is inadequate, we may be unable to sell and deliver our electricity. If a region’s power transmission infrastructure is inadequate, our recovery of sales costs and profits may be insufficient. If restrictive transmission price regulations are imposed, transmission companies we rely on may not have sufficient incentives to invest in expanding their infrastructure, which could unfavorably affect our results of operations and financial 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 subject to stoppages should material disruptions in the pipeline occur. Stoppages could force us to purchase electricity at spot market prices, which could be higher than the contracted fixed sale price to customers. This scenario could adversely affect our business, results of operations, and financial condition.

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We may not reach satisfactory collective bargaining agreements with our unionized employees or retain key employees in labor conflict cases.

A large percentage of our employees are members of unions with whom we have collective bargaining agreements that must be renewed regularly. For example, a labor union representing 148 workers went on 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, results of operations, and financial condition could be unfavorably affected by a failure to reach a collective bargaining agreement with any labor union or by a 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 cannot 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.

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We employ many highly specialized employees. Specific actions such as strikes, walkouts, or work stoppages by these employees could negatively affect our business, results of operations, financial condition, and reputation.

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

We review acquisition prospects that may increase our market 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 acquire suitable companies in the future. 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 business concerns.

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Integrating acquired businesses may be difficult, expensive, 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 on our business, results of operations, or financial condition.

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Interruption in 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. We use our IT Systems and infrastructure to create, collect, use, disclose, store, dispose of, and otherwise process sensitive information, including company and customer data and personal information regarding customers, employees and their dependents, contractors, shareholders, and others. IT Systems are critical to 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 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 information and communication among those parties has increased significantly since the implementation of smart meters and intelligent grids in Chile.

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Our generation, distribution facilities, IT Systems, and other infrastructure and 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 increased volume and sophistication of cybersecurity incidents from international activist organizations, nation-states, and individuals and are among the emerging risks identified in our planning process. Cybersecurity incidents could harm our businesses by limiting our generation and distribution 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-party service providers’ operations could also unfavorably affect our business.

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Our business requires the collection and retention of personally identifiable information of our customers, employees, and shareholders, who expect that we will adequately protect the privacy of such information. Cybersecurity breaches may expose us to a risk of loss or misuse of confidential and proprietary information. Significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially high costs to notify and protect the impacted persons. It could cause us to become subject to significant litigation, losses, liability, fines, or penalties, any of which could materially and adversely affect our results of operations and reputation with customers, shareholders, and regulators, among others. We may also be required to incur significant costs associated with governmental actions in response to such intrusions or strengthen our information and electronic control systems.

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The cybersecurity threat is dynamic, evolving, and increasing in sophistication, magnitude, and frequency. We may be unable to implement adequate preventive measures or accurately assess the likelihood of a cybersecurity incident. We are unable to quantify the potential impact of cybersecurity incidents on our business and reputation. These potential cybersecurity incidents and corresponding regulatory action could result in a material decrease in revenues and high additional costs, including penalties, third-party claims, repair costs, increased insurance expense, litigation costs, notification and remediation costs, security costs, and compliance costs.

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.

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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.

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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.

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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.

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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.

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We are subject to potential business and financial risks resulting from climate change legislation and regulation to limit GHG emissions.

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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.

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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.

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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.

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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 (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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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We are subject to the adverse effects of worldwide pandemics.

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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.

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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.

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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.

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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.

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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.

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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.

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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 subject 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.

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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 differs 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 our minority shareholders.

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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.

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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.

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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.

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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 have identified a material weakness in our internal control over financial reporting related to our general information technology controls, including the 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 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 considered 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 applicable securities laws, or (iii) cause investors to lose confidence in our financial reporting or financial statements, the occurrence of 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

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.” As of December 31, 2020, Enel beneficially owned 64.9% of our shares. Our shares are listed and traded on the Chilean Stock Exchanges under the trading symbol “ENELCHILE,” and our ADS are listed and traded on the NYSE under the trading symbol “ENIC.”

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Our contact information in Chile is:

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

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We are an electric utility company engaged in the generation, transmission, and distribution of electricity in Chile through our subsidiaries and affiliates. As of December 31, 2020, we had 7,200 MW of gross installed capacity and 2.0 million distribution customers. Of our total gross installed capacity, 66% corresponds to renewable energies, including 3,561 MW of hydroelectric power 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, 2020, we had consolidated assets amounting to Ch$ 7.9 trillion and operating revenues of Ch$ 2.6 trillion.

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We have been known as Enel Chile since the completion of the 2016 Reorganization 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 in the merger of Chilean Electric Tramway and Light Co. (founded in 1889) and Compañía Nacional de Fuerza Eléctrica (dating back to 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.). It became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A (“Chilectra” and presently 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.). As of December 31, 2020, Enel Chile owns 99.1% of Enel Distribution and 93.5% of Enel Generation.

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The 2018 Reorganization

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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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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 was completed and effective on April 2, 2018.

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As a result of the 2018 Reorganization, we increased our economic interest in Enel Generation from 60% to 93.5%, and EGP Chile is wholly owned. We continue to own 99.1% of Enel Distribution.

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We currently consolidate our Chilean conventional electricity generation business under Enel Generation, our Chilean electricity distribution business under Enel Distribution, our Chilean electricity transmission business under Enel Transmission, and our Chilean NCRE generation business under EGP Chile. Enel remains our parent company and majority shareholder, owning 64.9% of our Company as of December 31, 2020, and the date of this Report.

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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.

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Enel Generation

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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 a gross installed capacity of 158 MW, 128MW, and 350 MW, respectively.

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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 National Energy Commission (“CNE” in its 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 Bocamina II are December 31, 2023, and December 31, 2040, respectively. Nevertheless, we 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, acting through Enel Generation, will become the first electricity company in Chile to complete its decarbonization process.

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To simplify our corporate structure, we have continued to reduce the number of our companies over the last several years:

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Enel Distribution

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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.

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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.

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Enel Green Power Chile (EGP Chile)

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To simplify the organizational structure, we reorganized EGP Chile to reduce the number of companies within the EGP Chile group, including the following steps:

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Capital Investments, Capital Expenditures, and Divestitures

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We coordinate our overall financing strategy, including the terms and conditions of loans and intercompany advances entered into by our subsidiaries, 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. In the distribution business, we will continue investing to allow the connection of new customers, increase our service quality, and introduce 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 when the cash flows are needed.

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Our investment plan is flexible and adapts to changing circumstances by assigning different priorities to each project according to profitability, strategic fit, and sustainability. 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 technological developments, such as smart meters, while keeping the environment in mind.

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For the 2021-2023 period, we expect to make capital expenditures of Ch$ 1.67 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. Please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Development” for further detail regarding these projects.

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The table below sets forth the expected capital expenditures for the 2021-2023 period and the capital expenditures incurred in 2020, 2019, and 2018:

While our planned investments go beyond the three years highlighted in this table, we report three years to align with Enel’s three-year industrial plan disclosed in December 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.

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Capital Expenditures in 2020, 2019, and 2018

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In the last three years, our capital expenditures were principally related to the Campos 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 existing power plants. These projects aim to add 1,043 MW of installed capacity to our generation mix.

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In 2020, our investments in the distribution business focused on facilitating new customer connections, reinforcing feeders mainly to increase our service quality, increasing the capacity of our substations, and automating our systems through the installation of control remote devices and smart meters for residential customers.

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In 2020, our generation business investments focused primarily on the Campos del Sol I and II solar projects, the Domeyko solar project, the Los Cóndores hydroelectric project, and the Renaico II wind farms. Please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Construction” for further detail on our projects.

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In our distribution business, we plan to continue to expand our services, control energy losses, and increase our quality of service 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.

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We reserve a portion of our capital expenditures for maintenance and the assurance of our facilities’ quality and operational standards. Projects in progress will be financed with resources provided by external financing as well as internally generated funds.

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We are a publicly held limited liability stock corporation that operates in Chile. Our core business is electricity, generation, transmission, and distribution. We conduct our business through Enel Generation, Enel Transmission, Enel Distribution, and their 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.

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We also participate in other activities that are not core businesses and represent less than 1% of our 2020 revenues. We do not report them as a separate business segment in this Report or in our consolidated financial statements.

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The table below presents our revenues:

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For further financial information related to our revenues, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 28 of the Notes to our consolidated financial statements.

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Electricity Generation Business Segment

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We hold a 93.5% economic interest in Enel Generation, which accounted for 32% of the National Electricity System’s (“SEN” in its Spanish acronym) total electricity sales in 2020. As of December 31, 2020, we accounted for 28% of SEN’s total generation capacity, measured by the installed capacity. Hydroelectric, thermal, solar, wind, and geothermal power represent 49.5%, 34.1%, 6.9%, 8.9%, and 0.7% of our total installed capacity in Chile.

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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.

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

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

ELECTRICITY DATA

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It is common in the electricity industry to divide the business into hydroelectric, thermoelectric, and other generation types because each has significantly different variable costs. Thermoelectric generation requires fuel purchase, which generally leads to higher variable costs than hydroelectric generation from reservoirs or rivers, which typically has immaterial variable costs. Of our total consolidated generation in 2020, 50.2% was from hydroelectric sources, 33.4% was from thermal sources, and 16.4% was from solar and wind energy.

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

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GENERATION BY TYPE OF ENERGY (GWh)

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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)

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Dividing sales by customer type in terms of regulated and unregulated customers helps manage and understand the business. We sell electricity to regulated customers, through distribution companies, and to unregulated customers directly. The sales to distribution companies to supply their regulated customers, that is, residential, commercial, or others, are classified as regulated sales and subject to government-regulated electricity tariffs. Generation companies’ sales to distribution companies to supply their unregulated customers are classified as unregulated sales and governed by contracts at freely negotiated prices and terms. We sell directly to large commercial and industrial customers and other generators. The sales to generators are classified as unregulated sales and generally governed by contracts with freely negotiated prices and terms. Finally, pool market sales occur either when SEN dispatches generation companies in excess of their contractual obligations and therefore must sell their surplus electricity in the pool market or when the generators’ electricity dispatched is less than their contractual commitments with customers. Therefore, they must purchase the deficit in the pool market. These purchase and sale transactions among electricity generation companies are typically made in the pool market at the spot price and do not require a contractual agreement.

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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.

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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, when they are expected to melt, hydrological levels, and the capacity of critical 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

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water users, and including pass-through cost clauses in contracts with customers to cover the cost of the spot market purchases.

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In 2022, distribution company contracts awarded in the August 2016 auction will come into effect. Therefore, the tariffs of our regulated contracts will decrease by 6% due 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 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.

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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, 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. These prices are 6.8% higher than the average price.

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Energy purchases and transportation costs are the principal 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. Our thermal generation increases during relatively low rainfall periods, typically resulting in higher fuel costs. Under dry conditions, the electricity we have contractually agreed to provide may exceed the electricity we generate, requiring us to purchase electricity in the pool market at spot prices to satisfy our contractual obligations. The cost of these purchases at spot prices may, under certain circumstances, exceed the price at which we sell electricity under contracts and, therefore, may result in a loss. We attempt to minimize the effect of poor hydrological conditions on our operations in any given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated electricity production in a dry year. To 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 critical reservoirs. Besides limiting contracted sales, we may adopt other strategies, including installing temporary thermal power, negotiating lower consumption levels with unregulated customers, negotiating with other water users, and pass-through cost clauses in contracts with customers.

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Seasonality

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

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

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When there is more precipitation, hydroelectric generating facilities can accumulate additional water for generation. Our reservoirs’ increased level allows us to generate more electricity with hydroelectric power plants during months when marginal electricity costs are lower.

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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 reduce water accumulated in reservoirs, thereby curtailing our hydroelectric generation capacity. To mitigate hydrological risk associated with our contractual obligations with our customers, hydroelectric generation may be substituted with thermal sources (natural gas, liquefied natural gas (“LNG”) coal, or diesel) and energy purchases on the spot market. These actions could result in higher costs.

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Operations

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We own and operate 48 generation power plants in Chile through our subsidiaries, Enel Generation, EGP Chile, and Pehuenche. Of these generation power plants, 18 are hydroelectric, with a total installed capacity of 3,561 MW, representing 49.5% of our total installed capacity in Chile. There are ten thermal generation power plants, including one geothermal power plant, that operate with gas, coal, or oil, with a total installed capacity of 2,502 MW, representing 34.7% of our total installed capacity in Chile. There are nine wind-powered generation power plants with an aggregate installed capacity of 642 MW, representing 8.9% of our total installed capacity in Chile. There are ten solar-powered generation power plants with an aggregate installed capacity of 496 MW, representing 6.9% of our total installed capacity in Chile.

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

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Our total gross electricity generation in Chile accounted for 28.5% of total gross electricity generation in Chile in 2020.

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

ELECTRICITY GENERATION BY COMPANY (GWh)

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The following table sets forth the electricity generation by type:

ELECTRICITY GENERATION BY TYPE (GWh)

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Water Resource Use Agreements

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Water resource use agreements refer to a user's right to utilize water from a particular source, such as a river, stream, pond, or groundwater. In times of favorable hydrological conditions, water agreements are generally not complicated or contentious. However, with poor hydrological conditions, water agreements protect our right to use water

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resources for hydroelectric generation. The following agreements allow us to use water more efficiently and avoid additional litigation with the local community and farmers.

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We have three current agreements signed with the Chilean Hydraulic Works Directorate (“DOH”). The agreements are related to water consumption from Maule Lagoon and Laja Lake, both located in southcentral Chile in areas where irrigation is more demanding, generally from September to April. Enel Generation signed the agreements regarding the use of water from Maule Lagoon and Laja Lake on September 9, 1947, and October 24, 1958, respectively. On November 16, 2017, Enel Generation signed an agreement to operate and recover water resources from Laja Lake, complementing the previous agreement signed with DOH in 1958.

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In May 2020, Enel Generation and our subsidiary Pehuenche signed an agreement with Colbún S.A., the electric utility company that owns Colbún Reservoir, and some irrigation associations in the Maule basin. The agreement aims to consolidate the generation rights extracted from Maule Lagoon under the agreement signed in 1947 with the Colbún Reservoir to allow these irrigation associations to use them during the 2020/2021 irrigation season.

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In October 2020, our subsidiary Pehuenche, Colbún S.A., and the irrigators of the Maule Lagoon Vigilance Board signed an agreement to optimize the use of water during periods of drought. The agreement, which expires on August 31, 2025, facilitates water accumulation in the Colbún Reservoir in the spring for use in the summer, the peak irrigation period.

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Thermal Generation

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Our thermal electricity generation facilities use mostly LNG, coal, and, to a lesser extent, diesel. To satisfy our natural gas requirements, we signed a long-term LNG supply contract that establishes maximum quantities and prices. We also have long-term gas transportation agreements with pipeline companies. Our gas-fired efficient power plants can operate using either natural gas or diesel. In particular, San Isidro and Quintero power plants operate using LNG from the Quintero LNG Terminal.

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The LNG supply is based on long-term agreements with Quintero LNG Terminal for regasification services and Shell for supply. Our LNG sale and purchase agreement with Shell is in force through 2030 and is indexed to the Henry Hub/Brent commodity prices. Electrogas S.A. is our current gas transportation provider. In 2020, Enel Generation used 742 million cubic meters of LNG from Quintero LNG Terminal for its generation and commercialization requirements.

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Regarding the supply of natural gas, a milestone was achieved during the last quarter of 2018. In an environment of cooperation and promotion of energy integration by governments and private actors in Argentina and Chile, and after eleven years of interrupted gas supply, it was possible to reactivate the import of natural gas from Argentina. In 2020, Enel Generation imported 377 million cubic meters of natural 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 system energy prices during the year.

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In 2020, the Terminal Use Agreement signed with GNL Mejillones allowed the unloading of LNG shipments at that terminal. This agreement permitted the renewal of gas sales agreements with important mining and industrial customers, making Enel Generation the principal industrial gas trader in the north of Chile, in addition to having this gas available to Enel Generation thermal units connected to the northern gas pipelines (Taltal and GasAtacama).

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Concerning the commercialization of LNG by truck, 70 million cubic meters were delivered in 2020, a 17% increase compared to 2019. In 2020, new agreements were reached to allow the increased supply of natural gas for distribution for the coming years.

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The Bocamina power plant consumed 840 thousand tons of coal in 2020, equivalent to 1.9 TWh of energy generated by Bocamina II and 0.4 TWh generated by Bocamina I. We closed Bocamina I in December 2020 and expect to shut down Bocamina II by May 2022 as part of our decarbonization strategy.

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Generation from NCRE sources

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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 before 2007, to 20% for those signed starting in July 2013. Our Canela wind farms and Ojos de Agua mini-hydroelectric plant, and most of EGP Chile’s power plants (except the Pullinque and Pilamiquén power plants), qualify as NCRE facilities.

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Electricity sales and generation

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SEN’s electricity sales increased 0.2% during 2020 compared to 2019.

The following table sets forth SEN’s electricity sales:

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ELECTRICITY SALES IN SEN (GWh)

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Our electricity sales reached 22,960 GWh in 2020, 23,513 GWh in 2019, and 24,369 GWh in 2018, which represented a 32.0%, 32.8%, and 34.2% market share, respectively. The energy purchases to comply with our contractual obligations to third parties increased by 46.8% in 2020, compared to 2019, primarily due to lower hydro and coal electricity generation from closing the Tarapacá plant.

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The following table sets forth our electricity generation and purchases:

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ELECTRICITY GENERATION AND PURCHASES (GWh)

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

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

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In 2020, 2019, and 2018, we had 384, 315, and 294 customers, respectively. This significant increase in 2020 is mainly due to the increase in the number of unregulated customers. Regulated customers of a certain size may elect to become unregulated customers to benefit from the current market situation, which offers lower prices than would be paid as regulated customers. In 2020 our customers included 24 regulated customers and 360 unregulated customers.

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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.

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Our generation contracts with unregulated customers are generally on a long-term basis and typically range from five to fifteen years. These 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

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regarding power sources and equipment, which may be provided at special rates and 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 agreement, we can reject purchases and have no obligation to supply electricity to our unregulated customers. Disputes are typically subject to binding arbitration between the parties, with limited exceptions.

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For the year ended December 31, 2020, our principal distribution customers were (in alphabetical order): Enel Distribution. Grupo CGE, Grupo Chilquinta, and Grupo Saesa.

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

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Electricity generation companies compete based mainly on price, technical experience, and reliability. We have lower marginal production costs than companies whose installed capacity is primarily 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 to comply with our contractual obligations.

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Electricity Distribution Business Segment

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Through our subsidiary Enel Distribution, in which we have a 99.1% economic interest, we are one of the largest electricity distribution companies in Chile based on the number of regulated customers, distribution assets, and energy sales.

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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 Chile’s capital, is the country’s most densely populated area and has a high concentration of industries, industrial parks, and office facilities. As of December 31, 2020, we distributed electricity to over 2 million customers. Energy losses were 5.2% in 2020, 5.0% in 2019, and 5.0% in 2018.

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For the year ended December 31, 2020, residential, commercial, industrial, and other customers, who are primarily municipalities, represented 30.4%, 27.9%, 10.2%, and 31.4%, respectively, of our total energy sales of 16,481 GWh, which is a decrease of 3.8% in compared to the same period in 2019.

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The following table sets forth our principal operating data for each of the periods indicated:

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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.

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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.

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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 97.3%, compared to 99.4% during the same period in 2019.

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For the supply to regulated distribution customers, Enel Distribution has entered into contracts with the following generation companies: Enel Generation, AES Gener S.A., Colbún S.A., and other companies.

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For the supply to unregulated distribution customers, Enel Distribution has contracts with the following generation companies: Empresa Eléctrica Guacolda S.A., Hidroeléctrica La Higuera S.A., Hidroeléctrica La Confluencia S.A., Pacific Hydro Chile S.A., and Enel Generation.

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Seasonality

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Seasonal changes in energy 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, it does not have an effect on our profitability since the cost of electricity purchased is passed on to end-users through tariffs that are set for multi-year periods. However, in the case of regulated customers, an increase in tariffs due to rate adjustments may not happen immediately, which could affect our profitability in the short term.

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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 different participants in the Chilean electricity market:

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The Chilean electricity sector is physically divided into three main networks: SEN and two smaller isolated networks (Aysén and Magallanes). SEN extends from Arica in northern Chile to Chiloé in southern Chile. CEN (Coordinador Eléctrico Nacional), a centralized dispatch center, coordinates SEN’s operations.

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

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

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CEN coordinates electricity generation 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.

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Transmission companies own lines and substations with a voltage higher 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 non-discriminatory conditions.

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Distribution companies supply electricity to end customers using electricity infrastructure lower than 23 kV. The distribution segment is a natural monopoly subject to special industry regulations as well, including antitrust

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legislation. The electricity network is open access, and distribution tariffs are regulated. Distribution companies must provide electricity to regulated customers within their concession area and at regulated prices. They may sell to unregulated customers through contracts at freely negotiated prices.

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Customers are classified as “regulated” or “unregulated” according to their demand. Some customers may 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.”

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2. Electricity Law and Authorities

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

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Since its inception, private sector companies have developed the Chilean electricity industry; however, nationalization by the government was conducted 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.

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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 regulations included in Decreto Supremo D.S. No. 327/1998.

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The Ministry of Energy is the leading authority in the energy industry. It elaborates and coordinates plans, policies, and standards for the sector’s proper operation and the development of the industry in Chile.

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

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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. SEF inspects and oversees compliance with the law, rules, regulations, and technical norms applicable to the generation, transmission, and distribution of electricity, as well as liquid fuels and gas.

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The Energy Sustainability Agency was created in 2018 to promote energy efficiency and replaced the Energy Efficiency Agency.

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Additionally, the law provides for a “Panel of Experts,” whose primary responsibility is to act as a court, issuing enforceable resolutions in disputes related to subjects referred to by DFL 4 and other electricity-related laws. This panel comprises 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).

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

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CEN’s main activities include:

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CEN performs the calculation of market balances (energy injections and withdrawals), determines the transfers among generation companies, and calculates the hourly marginal cost, the price at which energy transfers are made in the spot market. CEN does not, however, calculate the rates of generation capacity. The CNE calculates such prices.

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Limits on Integration and Concentration

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The antitrust legislation established in DFL 211 (modified in 2016 by Law No. 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.

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Companies can participate in different market segments (generation, distribution, transmission) to the extent that they are appropriately separated, both from an accounting and corporate perspective, according to the requirements established in DFL 4, Law No. 20,018, the antitrust law DL 211, and Law No. 21,194. Companies must also comply with the conditions set in Resolution No. 667/2002, discussed below.

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The transmission sector is subject to the most significant restrictions, mainly because of its open access requirements. DFL 4 establishes that companies that own the National Transmission System (“STN” in its Spanish acronym) may not engage in activities within the generation or distribution segment.

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Owners of the STN must be 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.

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According to the Electricity Law, there are no restrictions on market concentration for generation and distribution activities. However, Chilean antitrust authorities have imposed specific measures to increase transparency associated with our subsidiaries and us through Resolution No. 667/2002 issued by the TDLC.

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Resolution No. 667/2002 states that:

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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

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required by this law, our transmission and our distribution business lines are now owned and operated by separate companies, Enel Transmission and Enel Distribution, respectively.

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The Water Utility Services Law sets restrictions on the overlapping of different utility concessions in the same area. 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. For example, an electricity distribution company and a water utility company that belong to the same owner cannot operate in the same concession area.

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3. Generation Segment

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The generation segment is comprised of companies that own electricity generation power plants. They operate under market 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 power plants’ operation. The surplus or deficit between a generation company’s electricity sales and production is sold or purchased, as the case may be, to other generators at the spot market price.

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Non-Conventional Renewable Energy (“NCRE”) has been promoted in Chile since 2008. NCRE refers to electricity from wind, solar, geothermal, biomass, ocean (movement of tides, waves, currents, and the ocean’s thermal gradient), and mini-hydropower plants with a capacity under 20 MW. Law No. 20,698 (2013) established a mandatory 20% share of NCRE source as a percentage of total contracted energy sales by 2025 but grandfathered contracts signed between 2007 and 2013, which have a 10% target by 2024.

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Dispatch, Customers, and Pricing

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Generation companies may sell to distribution companies, unregulated end customers, or 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 set hourly by CEN, based on the lowest production cost of the last kWh dispatched.

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CEN operates the electricity system with an approach that minimizes costs while monitoring the quality of the generation and transmission companies’ service. To reduce operating costs, CEN 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 is 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 with their production determined by CEN.

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

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Each generator receives a capacity payment set by CEN based on the generation capacity of each power plant and the available primary resource. It depends primarily on the facility’s availability, the type of power plant technology, and the resources used to generate electricity. It considers the maximum capacity a generator may supply to the system at certain peak hours, considering statistical information, accounting for maintenance time and arid conditions for hydroelectric power plants. However, it does not consider the power plants’ contribution to the security of the entire system.

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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 that considers the weighted-average rates of their current supply contracts for regulated customers. The node price is adjusted in three instances: (1) every six months, in January and July of each year, based on local and international indices; (2) upon the entry of a new supply contract with any distribution company; and (3) upon indexation of a supply contract by more than 10%.

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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.

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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.

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Rationing

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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.

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Generation companies may also be required to pay fines to the regulatory authorities and compensate electricity customers affected by shortages of electricity. Penalties 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, they 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.

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Water Rights

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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 associated with the water rights. The maximum license fees that may be recovered are those paid during the eight years before the start-up date.

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

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

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

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In January 2019, Chile’s president modified this amendment to state that water rights have an unlimited duration. As of the date of this Report, the Chilean Congress is still discussing the amendment.

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4. Transmission Segment

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Transmission systems are comprised of the electricity lines and substations with a voltage or tension higher than 23 kV that are connected from generators’ production points to the centers of consumption or distribution.

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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 non-discriminatory conditions.

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Law No. 20,936, published in July 2016, established a new regulatory framework for all electricity transmission systems in Chile, redefining the system into the following segments: national, development poles, zonal, dedicated, and international.

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National and zonal transmission systems planning is a centralized and regulated process conducted by CEN that annually issues an expansion plan to be approved by the CNE.

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Both systems’ expansion is granted through an open tender process that distinguishes new installations from the enlargement of existing facilities. The tenders conducted for new installations give the winner ownership of the installation to be built. The extension of existing facilities, on the other hand, belongs to the owner of the original facility, who is obliged to tender the construction of the required extension.

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The remuneration of existing national and zonal transmission installations is determined by a tariff-setting process conducted every four years. This process determines the annual transmission value that considers efficient operation and maintenance costs and a yearly valuation of investments based on a discount rate determined by the authorities every four years (minimum 7% after-tax) and the installations’ useful life.

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The remuneration of extensions of existing facilities is the value resulting from the respective bid of such extensions for the first 20 years of operations. Beginning with year 21, such extension is considered an existing installation and compensated accordingly.

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The regulation currently in force states that transmission remuneration is the sum of tariff revenue and the usage charge revenue received for the transmission system, defined as $/kWh by the CNE. Revenues are calculated on a semi-annual basis.

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In 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

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Law No. 20,936 introduced changes to the transmission tariff-setting process. In the transition to the new law, the existing zonal transmission tariff-setting process has been continued, as stated by transitory Article No. 20 of Law No. 20,936. The tariff-setting process for the 2018-2019 period concluded in October 2018 and has been applied retroactively since January 1, 2018.

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In 2020, national and zonal transmission pricing studies were carried out for the 2020-2023 period. As of the date of this Report, observations on both studies were submitted, and the next step in the process is the publication of the technical report by the CNE.

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5. Distribution Segment

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The distribution segment comprises electricity infrastructure with a voltage lower than 23 kV to supply electricity to end customers. Electricity distribution is considered a natural monopoly. Therefore, companies operate under a public utility concession regime, with service obligations and regulated tariffs for supplying regulated customers.

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Customers are classified according to their demand as regulated or unregulated. Regulated customers are those with a connected capacity of up to 5,000 kW. Unregulated customers are those with a connected capacity of 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. Customers must remain in the selected category for at least four years.

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Customers subject to the unregulated price regime may negotiate their electricity supply with any supplier; 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 has permitted customers with a connected capacity of up to 300 kW to sell their surpluses.

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The Chilean Ministry of Energy grants distribution concessions for undefined periods and the right to use public areas for building distribution lines. Distribution companies have an obligation to supply electricity to all customers who request service within their concession area. A concession may be declared expired if the quality of service does not meet specific minimum standards.

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Regarding the supply of electricity to regulated customers, DFL 4 establishes that distribution companies must have an amount of electricity permanently 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 conducted at least five years in advance from the expected effective date of the energy supply contract, which has a 20-year term. In case of unforeseen deviations in the projections of demand, the regulator has the authority to carry out short-term tenders. There is also a regulated mechanism to remunerate supply not covered by a contract if this were to take place.

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The latest tender was conducted 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 wholly sourced from NCRE. In November 2020, the CNE announced a new bidding process for 2,310 GWh/year to be tendered from 2026 to 2040. The deadline for the submission of bids is May 19, 2021. Please see “Item 4. Information on the Company — B. Business Overview” for further detail on the outcome of tenders.

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Distribution Tariffs

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

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Law No. 21,194 established new limits on returns on investments for distribution companies. Tariffs charged by distribution companies to regulated end customers are set every four years. Tariffs are determined by the sum of the cost of electricity purchased by the distribution company, a transmission charge, and the value-added from distribution of electricity (“VAD”), allowing distribution companies to recover their investment and operating costs, including a legally mandated return on investment. The transmission charge reflects the price paid for electricity transmission and transformation. The law also requires that distribution companies may not operate in other sectors or industries as of 2021.

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The VAD is based on a so-called “efficient model company” within a typical distribution area (“TDA”). It considers the cost of building and operating the company at the minimum price, fulfilling the company’s quality and safety standards within that TDA. Therefore, the CNE classifies all distribution companies according to their TDA and subsequently selects one distribution company from each TDA to estimate its cost as an efficient model company. Cost estimates include fixed expenses, average energy and capacity losses, standard investment costs, and operation and maintenance costs. The annual investment costs are calculated considering the replacement cost of installations, useful life, and a rate of return that the CNE calculates every four years.

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The CNE determines the VAD of each TDA. With the resulting VAD, preliminary tariffs are tested to ensure an industry aggregate rate of return between 6% and 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.

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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 higher return to distribution companies that are more efficient than the model company.

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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 applying this mechanism are progressively absorbed by the remaining customers subject to regulated prices, under the mentioned average, except for those residential users whose monthly average consumption of energy in the prior calendar year is less than or equal to 200 kWh.

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Additionally, Chilean law provides that transitory subsidies can be granted if the residential customer tariff increases by 5% or more within six months. The state confers this subsidy, and its application is a power of the government, and the last one was granted in 2009.

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The tariff-setting process for 2016-2020 concluded in August 2017 and had been effective, retroactively, since November 4, 2016. On December 18, 2017, the CNE published a resolution that set the Technical Standard of Quality of Service for Distribution Systems, establishing higher technical and commercial standards. Included in these new standards are electricity supply reliability indicators, such as the System Average Interruption Frequency Index (SAIFI), which measures the average number of times a customer’s supply is interrupted in a year, and the System Average Interruption Duration Index (SAIDI), which measures the total number of minutes, on average, that a customer is without electricity in a year, among others. This resolution also refers to product quality, metering, monitoring and controlling, and commercial service quality. In this context, in September 2018, there was an extraordinary tariff update process, which is non-retroactive and will be in effect until the 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 tariffs for 2020 remained fixed under Law No. 21,185, which creates a temporary electricity price stabilization mechanism for customers subject to tariff regulation.

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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.

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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.

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Distribution companies may be required to compensate end customers in 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.” Also, distribution companies are subject to SEF provisions, including articles 15 and 16 of Law No. 18,410, in which different infractions are listed and classified according to their severity and associated fines.

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Distribution-Related Services

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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 every four years, along with the VAD calculation.

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

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6. Environmental Regulation

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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.

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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 environmental 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 Chile’s environmental and institutional framework. This law requires companies to conduct an environmental impact study and a declaration of future generation or transmission projects.

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In January 2010, Law No. 19,300 was modified by Law No. 20,417 and introduced changes to the environmental assessment process and 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” in its Spanish acronym).

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The Ministry of the Environment is in charge of managing, protecting, and applying environmental policies. Its mission is to lead sustainable development by implementing efficient public procedures and regulations and promoting good practices that improve citizen environmental education. The Ministry works to restore air quality in urban centers, management of natural resources and biodiversity, proper final disposal of solid waste, climate change and protection of water resources, and environmental education and citizen participation.

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

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

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All thermal power plants of Enel Generation have established methodologies to measure emissions and pay related taxes in line with the Chilean Superintendence of Environment requirements.

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

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7. Raw Materials

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

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Principal Subsidiaries and Affiliates

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We are part of an electricity group controlled by Enel S.p.A, an Italian company and our controlling shareholder that beneficially owned 64.9% of our shares as of December 31, 2020. Enel is an Italian utility company with multinational operations whose principal business is the production, distribution, and sale of electricity, focusing primarily on Europe and Latin America. Enel operates in 32 countries across five continents and produces energy through a managed installed capacity of 87 GW, including more than 47 GW of renewable sources, making Enel one of the world’s largest private renewables operators. Enel is among the largest network operators, distributing electricity to more than 74 million end users. With almost 70 million customers worldwide, Enel has one of the most extensive customer bases among European competitors. Enel’s shares are listed on the Mercato Telematico Azionario organized and managed by Borsa Italiana S.p.A.

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Enel Chile’s Simplified Organizational Structure⁽¹⁾

As of the date of this Report⁽²⁾

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We consolidated the companies listed in the following table as of December 31, 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.

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Generation Business

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Enel Generation

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Enel Generation is an electric utility company engaged, directly and through our subsidiaries and affiliates, in the generation businesses in Chile. As of December 31, 2020, it had 6,001 MW of gross installed capacity, with 28 generation facilities and a total of 109 generation units. Of its total gross installed capacity, 57.8% consists of hydroelectric power plants and includes, among others, Ralco with 690 MW, Pehuenche with 570 MW, El Toro with 450 MW, Rapel with 377 MW, and Antuco with 321 MW. Approximately 86% of our gross thermoelectric installed capacity is gas/fuel oil power plants (2,104 MW), and the remaining is coal-fired steam power plants (350 MW). Our economic interest in Enel Generation was 93.5% as of December 31, 2020, and as of the date of this Report.

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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.

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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, acting through Enel Generation, will become the first electricity company in Chile to complete its decarbonization process.

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EGP Chile

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EGP Chile is an electric utility company engaged in renewable generation business and a leader in Chile’s renewable energy market with a mixed portfolio of wind (564 MW), solar (496 MW), small hydroelectric (92 MW), and geothermal (48 MW) power. We hold a 99.9% economic interest in EGP Chile. 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.

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Geotérmica del Norte

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Geotérmica del Norte (GDN) is a joint venture between our subsidiary EGP Chile and Empresa 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, the first of its kind in Chile, and is currently developing the geothermal extension project that will add 28 MW of installed capacity to the Cerro Pabellón power plant. It also has production rights to geothermal concessions in Chile. Our economic interest in GDN is 84.6%.

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Distribution Business

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Enel Distribution

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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 over two million customers. Our economic interest in Enel Distribution is 99.1%.

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Transmission 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 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.

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Our property, plant, and equipment is concentrated in electricity generation and distribution assets in Chile.

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We conduct our generation business through Enel Generation, EGP Chile, and their subsidiaries, which together own 48 generation power plants, all located in Chile, of which 18 are hydroelectric 3,561MW installed capacity), ten are thermal, including geothermal (2,502 MW installed capacity), ten are solar (496 MW installed capacity), and nine are wind-powered (642 MW installed capacity).

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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.

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The following table identifies the power plants that we own, all located in Chile, at the end of each year, organized by company and technology:

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Property, Plant, and Equipment of Generation Companies