UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

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

OR

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

For the fiscal year ended December 31, 2020

OR

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

For the transition period from       to       

OR

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

Date of event requiring this shell company report,

Commission file number: 001-37723

ENEL CHILE S.A.

(Exact name of Registrant as specified in its charter)

ENEL CHILE S.A.

(Translation of Registrant’s name into English)

CHILE

(Jurisdiction of incorporation or organization)

Santa Rosa 76, Santiago, Chile

(Address of principal executive offices)

Nicolás Billikopf, phone: (56-9) 9343 5500, nicolas.billikopf@enel.com, Av. Santa Rosa 76, Piso 15, Comuna de Santiago, Santiago, Chile

(Name, Telephone, E-mail, and Address of Company Contact Person)

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

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
American Depositary Shares Representing Common Stock	ENIC	New York Stock Exchange
Common Stock, no par value *	*	New York Stock Exchange
US$ 1,000,000,000 4.875% Notes due June 12, 2028	ENIC28	New York Stock Exchange

 _____________________

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

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

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

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

Shares of Common Stock: 69,166,557,220

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒  Yes    ☐  No

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

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

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report    ⌧

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

	☒
U.S. GAAP ☐	International Financial Reporting Standards as issued by the International Accounting Standards Board ☒	Other ☐

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

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

Enel Chile’s Simplified Organizational Structure⁽¹⁾

As of the date of this Report⁽²⁾

(1) Only principal operating consolidated entities are presented here.

(2) As of January 1, 2021, Enel Transmission was spun off from Enel Distribution.

1

TABLE OF CONTENTS

		Page
GLOSSARY		3
INTRODUCTION		6
PRESENTATION OF INFORMATION		7
FORWARD-LOOKING STATEMENTS		9
PART I
Item 1.	Identity of Directors, Senior Management and Advisers	10
Item 2.	Offer Statistics and Expected Timetable	10
Item 3.	Key Information	10
Item 4.	Information on the Company	25
Item 4A.	Unresolved Staff Comments	60
Item 5.	Operating and Financial Review and Prospects	60
Item 6.	Directors, Senior Management and Employees	95
Item 7.	Major Shareholders and Related Party Transactions	103
Item 8.	Financial Information	106
Item 9.	The Offer and Listing	108
Item 10.	Additional Information	109
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	126
Item 12.	Description of Securities Other Than Equity Securities	130
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	132
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	132
Item 15.	Controls and Procedures	132
Item 16.	Reserved	133
Item 16A.	Audit Committee Financial Expert	133
Item 16B.	Code of Ethics	133
Item 16C.	Principal Accountant Fees and Services	134
Item 16D.	Exemptions from the Listing Standards for Audit Committees	135
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	135
Item 16F.	Change in Registrant’s Certifying Accountant	136
Item 16G.	Corporate Governance	136
Item 16H.	Mine Safety Disclosure	137
PART III
Item 17.	Financial Statements	138
Item 18.	Financial Statements	138
Item 19.	Exhibits	138

2

GLOSSARY

ADR	American Depositary Receipt	A certificate issued by our depositary that represents ADS, or American Depositary Shares.
ADS	American Depositary Share(s)	An equity interest in our company that is issued by Citibank, N.A., as the depositary, in respect of shares of our company held by the depositary. Each ADS represents 50 shares and ADS are traded on the New York Stock Exchange. In this Report, ADS is used in the singular and plural forms.
AES Gener	AES Gener S.A.	A Chilean generation company and one of our competitors in Chile.
AFP	Administradora de Fondos de Pensiones	A legal entity that manages a Chilean pension fund.
CDEC	Centro de Despacho Económico de Carga	The autonomous entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand in the SIC and SING that CEN replaced in November 2017.
Celta	Compañía Eléctrica Tarapacá S.A.	Celta was a former Chilean generation subsidiary of Enel Generation that operated plants in the SING and the SIC. Celta merged into GasAtacama in November 2016.
CEN	Coordinador Eléctrico Nacional	An autonomous entity in charge of coordinating the efficient operation of the SEN, dispatching generation units to satisfy demand, and known as the National Electricity Coordinator. It replaced the CDEC for both the SIC and SING in November 2017.
Chilean Stock Exchanges	Chilean Stock Exchanges	The two stock exchanges located in Chile: the Santiago Stock Exchange and the Electronic Stock Exchange.
CMF	Comisión para el Mercado Financiero	Chilean Financial Market Commission, the governmental authority that supervises the financial markets, formerly known as the Chilean Superintendence of Securities and Insurance, or SVS in its Spanish acronym.
CNE	Comisión Nacional de Energía	Chilean National Energy Commission, a governmental entity with responsibilities under the Chilean regulatory framework.
EGP Chile	Enel Green Power Chile S.A.	A subsidiary of Enel Chile engaged in non-conventional renewable electricity generation.

3

EGPL	Enel Green Power Latin America S.A.	Formerly a Chilean closely held limited liability stock corporation that owned Enel Green Power Chile Ltda. and that merged with us on April 2, 2018. As a result, we consolidate Enel Green Power Chile Ltda.
Enel	Enel S.p.A.	An Italian company with multinational operations in the power and gas markets, with a 64.9% ownership of Enel Chile as of December 31, 2020, and our ultimate parent company.
Enel Américas	Enel Américas S.A.	An affiliated Chilean publicly held limited liability stock corporation headquartered in Chile, with subsidiaries engaged primarily in the generation, transmission, and distribution of electricity in Argentina, Brazil, Colombia, and Peru, controlled by Enel.
Enel Chile	Enel Chile S.A.	Our company, a Chilean publicly held limited liability stock corporation, with subsidiaries engaged primarily in the generation and distribution of electricity in Chile. The registrant of this Report.
Enel Colina	Enel Colina S.A.	A subsidiary of Enel Distribution engaged in electricity distribution in Chile, formerly known as Empresa Eléctrica de Colina Ltda.
Enel Distribution	Enel Distribución Chile S.A.	A publicly held limited liability stock corporation and our electricity distribution subsidiary operating in the Santiago Metropolitan Region, formerly known as Chilectra S.A.
Enel Generation	Enel Generación Chile S.A.	A publicly held limited liability stock corporation and our electricity generation subsidiary in Chile, formerly known as Empresa Nacional de Electricidad S.A. and Endesa Chile.
Enel Transmission	Enel Transmisión Chile S.A.	A publicly held limited liability stock corporation engaged in electricity transformation and transmission.
Enel X Chile	Enel X Chile SpA	A Chilean closely held limited liability stock corporation and our wholly-owned subsidiary, engaged in providing services associated with new technologies, with a strategic focus on digitalization, innovation, and sustainability.
GasAtacama	GasAtacama Chile S.A.	Formerly a subsidiary of Enel Generation engaged in gas transportation and electricity generation in northern Chile. On October 1, 2019, GasAtacama merged into Enel Generation.
GasAtacama Holding	Inversiones GasAtacama Holding Ltda.	Formerly a holding company subsidiary of Enel Generation, which previously held GasAtacama. GasAtacama Holding merged into Celta during 2016, which later merged into GasAtacama.

4

Geotérmica del Norte	Geotérmica del Norte S.A.	A joint venture between our subsidiary EGP Chile and Empresa Nacional del Petróleo (ENAP), the state-owned Chilean oil company, engaged in the development, exploration, and exploitation of geothermal resources in Chile.
IFRS	International Financial Reporting Standards	International Financial Reporting Standards as issued by the International Accounting Standards Board (IASB).
LNG	Liquefied Natural Gas.	Liquefied natural gas, a fuel for our thermal power plants.
NCRE	Non-Conventional Renewable Energy	Energy sources continuously replenished by natural processes, such as wind, biomass, mini-hydro, geothermal, wave, solar, or tidal energy.
OSM	Ordinary Shareholders’ Meeting	Ordinary Shareholders’ Meeting
Pehuenche	Empresa Eléctrica Pehuenche S.A.	A Chilean publicly held limited liability stock corporation engaged in the electricity generation business, owner of three power stations in the Maule River basin, and a subsidiary of Enel Generation.
SAIDI	System Average Interruption Duration Index	Index of average duration of interruption in the power supply.
SAIFI	System Average Interruption Frequency Index	Index of average frequency of interruptions in the power supply.
SEF	Superintendencia de Electricidad y Combustible	Chilean Superintendence of Electricity and Fuels, the governmental authority that supervises the Chilean electricity industry.
SEN	Sistema Eléctrico Nacional	The National Electricity System is the Chilean national interconnected electricity system formed in November 2017 and constituted by the previous SIC and SING networks.
UF	Unidad de Fomento	Chilean inflation-indexed, Chilean peso-denominated monetary unit, equivalent to Ch$ 29,070.33 as of December 31, 2020.
VAD	Valor Agregado de Distribución	Value-added from distribution of electricity.

5

INTRODUCTION

As used in this Report on Form 20-F (“Report”), first-person personal pronouns such as “we,” “us,” or “our,” as well as “Enel 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.

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.

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”.

We are a publicly held limited liability stock corporation organized on March 1, 2016, under the laws of the Republic of Chile as a result of a corporate reorganization completed in 2016 by the former Enersis S.A., which separated its Chilean businesses from its non-Chilean businesses.

On 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.

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.

6

PRESENTATION OF INFORMATION

Financial Information

In this Report, unless otherwise specified, references to “U.S. dollars” or “US$,” are to dollars of the United States of America (“United States”); references to “pesos” or “Ch$” are to Chilean pesos, the 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.

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.

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.”

Technical Terms

References to “TW” are to terawatts (1012 watts or a trillion watts); references to “GW” and “GWh” are to gigawatts (109 watts or a billion watts) and gigawatt-hours, respectively; references to “MW” and “MWh” are to megawatts (106 watts or a million watts) and megawatt-hours, respectively; references to “kW” and “kWh” are to kilowatts (103 watts or a thousand watts) and kilowatt-hours, respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. References to “BTU” and “MBTU” are to British thermal unit and million British thermal units, respectively. A “BTU” is an energy unit equal to approximately 1,055 joules. References to “Hz” are to hertz, and references to “mtpa” are to metric tons per annum. Unless otherwise indicated, statistics provided in this Report 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.

7

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.

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.

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

Calculation of Economic Interest

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%.

Rounding

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.

8

FORWARD-LOOKING STATEMENTS

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

● our capital investment program;

● trends affecting our financial condition or results of operations;

● our dividend policy;

● the future impact of competition and regulation;

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

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

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

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

● demographic developments, political events, social unrest, economic fluctuations, public health crises and pandemics, and interventionist measures by authorities in Chile;

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

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

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

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

● the factors discussed below under “Risk Factors.”

You should not place undue reliance on such statements, which speak only as of the date that they were made. Our independent registered public accounting firm has not examined or compiled the forward-looking statements and, accordingly, does not provide any assurance 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.

9

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.

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.

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

10

	As of and for the year ended December 31,
	2020(1)	2020	2019	2018	2017	2016
	(US$ millions)	(Ch$ millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income	3,637	2,585,402	2,770,834	2,457,161	2,522,978	2,541,567
Operating costs(2)	(3,685)	(2,619,658)	(2,244,780)	(1,786,557)	(1,944,348)	(1,973,778)
Operating income (loss)	(48)	(34,255)	526,055	670,605	578,631	567,789
Financial results(3)	(158)	(112,435)	(150,893)	(110,875)	(22,415)	(20,483)
Other non-operating income	13	9,489	1,793	3,410	113,241	121,490
Share of profit (loss) of associates and joint ventures accounted for using the equity method	5	3,509	366	3,190	(2,697)	7,878
Income (loss) before income taxes	(188)	(133,692)	377,321	566,330	666,760	676,674
Income taxes	114	81,305	(61,228)	(153,483)	(143,342)	(111,403)
Net income	(74)	(52,387)	316,093	412,848	523,418	565,271
Net income attributable to the parent Company	(72)	(50,860)	296,154	361,710	349,383	384,160
Net income attributable to non-controlling interests	(2)	(1,527)	19,940	51,138	174,035	181,111
Total basic and diluted earnings per average number of shares (Ch$/US$ per share)	(0.001)	(0.74)	4.28	5.66	7.12	7.83
Total basic and diluted earnings per average number of ADS (Ch$/US$ per ADS)	(0.052)	(36.77)	214.09	282.97	355.84	391.26
Cash dividends per share (Ch$/US$ per share)(4)	0.006	4.23	3.14	2.99	3.23	2.09
Cash dividends per ADS (Ch$/US$ per ADS)(4)	0.297	211.50	157.00	149.50	161.50	104.65
Weighted average number of shares of common stock (millions)	69,167	69,167	69,167	63,913	49,093	49,093
Consolidated Statement of Financial Position Data
Total assets	11,118	7,904,472	7,857,988	7,488,020	5,694,773	5,398,711
Non-current liabilities	4,592	3,264,717	3,069,405	2,596,392	1,090,995	1,178,471
Equity attributable to the parent company	4,715	3,351,916	3,484,698	3,421,229	2,983,384	2,763,391
Equity attributable to non-controlling interests	341	242,359	262,586	252,935	803,578	699,602
Total equity	5,056	3,594,274	3,747,284	3,674,164	3,786,962	3,462,994
Capital stock	5,460	3,882,103	3,882,103	3,954,491	2,229,109	2,229,109
Other Consolidated Financial Data
Capital expenditures (CAPEX)(5)	780	554,314	321,079	300,539	266,030	222,386
Depreciation, amortization and impairment losses(6)	1,326	942,931	527,437	220,750	160,622	197,587

(1) Solely for the reader’s convenience, Chilean peso amounts have been converted into U.S. dollars at the exchange rate of Ch$ 710.95 per U.S. dollar, as of December 31, 2020.

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

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

(4) For 2016, a payout ratio of 50% was used based on annual consolidated net income for our 2016 annual consolidated net income filed with the Financial Market Commission (“CMF” in its Spanish acronym), based on ten months of results starting as of our incorporation on March 1, 2016, and therefore differs from the twelve-month net income included in this Report.

11

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

(6) Please refer to Note 31 of the Notes to our consolidated financial statements for further detail.

	As of and for the year ended December 31,
	2020	2019	2018	2017	2016
OPERATING DATA OF SUBSIDIARIES
Enel Distribution
Electricity sold (GWh)	16,481	17,135	16,782	16,438	15,924
Number of customers (thousands)	2,008	1,972	1,925	1,882	1,826
Total energy losses (%)(1)	5.2	5.0	5.0	5.1	5.3
Enel Generation
Installed capacity (MW)	6,001	6,114	6,274	6,351	6,351
Generation (GWh)	15,913	17,548	17,373	17,073	17,564
EGP Chile(2)
Installed capacity (MW)	1,200	1,189	1,189	—	—
Generation (GWh)	3,418	3,493	2,673	—	—

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

(2) EGP Chile has been consolidated since April 2018.

Exchange Rates

Fluctuations in the exchange rate between the Chilean peso and the U.S. dollar will affect the U.S. dollar equivalent of the 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.

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.

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.

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.

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.

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.

	Ch$ per US$(1)
	Period End	Appreciation (Devaluation)
	(in Ch$)	(in %)
Year ended December 31,
2020	710.95	5.3
2019	748.74	(7.2)
2018	694.77	(11.5)
2017	614.75	8.9
2016	669.47	6.1

Source: Central Bank of Chile.

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

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.

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.

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.”

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

● Our thermal power plants require water for cooling, and droughts in extreme situations may reduce water availability and increase transportation costs. As a result, we have had to purchase water for our San Isidro

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power plant from agricultural areas that are also experiencing water shortages. These water purchases may increase our operating costs and may require us to negotiate with the local communities.

● Thermal power plants generate emissions such as nitrogen oxide (NO), carbon dioxide (CO₂), carbon monoxide (CO), sulfur dioxide (SO₂), and particulate matter into the atmosphere. Therefore, greater use of thermal power plants during droughts generally increases the risk of producing greater greenhouse gas (GHG) emissions.

A full recovery from the 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.

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.

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

The electricity generated by our solar and wind generation facilities is highly dependent on climate factors other than hydrology, including suitable solar and wind conditions, which, even under normal operating circumstances, can vary greatly. Climate change may also have long-term effects on wind patterns and the amount of solar energy received at a particular solar facility, reducing electricity generated by the facilities. Although we base our business decisions on solar and wind studies for each renewable energy facility, actual conditions may not conform to these studies’ findings. They may be affected by changes in weather patterns, including the potential impact of climate change.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

In mid-October 2019, widespread street demonstrations and protests erupted in Santiago and quickly spread throughout Chile. These actions became commonplace and, at times, were accompanied by looting, arson, and vandalism. Violent confrontations between protesters and the police and armed forces resulted in a significant loss of human lives and serious injuries. Accumulated damage to public and private property amounted to billions of dollars. Damage to Chile’s economy, prospects for growth, perception of risk, and immediate repercussions in unemployment and productivity loss were also significant. Our corporate headquarters in Santiago suffered a severe arson attack on October 18, 2019, resulting in the dislocation of our management and headquarters employees for an extended period. An electricity substation belonging to an unrelated company in the northern city of Copiapó was set on fire on November 28, 2019. Chilean public authorities have voiced their concern for the country’s strategic electricity infrastructure, including power stations, transmission lines, and distribution substations.

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

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Some aspects of the Chilean electricity law have been subject to significant regulatory changes, and any such changes may unfavorably affect our future operations and profitability. For example, in the context of the social crisis that began in October 2019, the government established a transitional mechanism for stabilizing customers’ electricity prices under the regulated price system. The mechanism eliminates the price increase of 9.2% that would have been applied to regulated customers as of July 2019 and defers the price increase for the sale of electricity under contracts between generation and distribution companies that start before 2021. A price stabilization funding program was implemented by the National Energy Commission (“CNE” in its Spanish acronym) and is effectively financed by companies in the generation industry, including our subsidiary Enel Generation, through accounts receivable that are generated by the differences between the contractual rates and the stabilized rates, which are expected to enable the generation companies to recover the lost revenues by December 31, 2027. We have suffered and expect to continue to suffer a financial loss due to this revenue deferral because generation companies are being asked to finance such deferral until billing differences begin to accrue financial remuneration in 2026. Please see Note 9 of the Notes to our consolidated financial statements for further information. Other Chilean electricity sector regulations may also affect our generation companies’ ability to collect revenues sufficient to cover their operating costs and adversely affect our future profitability.

In December 2019, the Ministry of Energy’s Law No. 21,194 lowered the profitability of distribution companies and modified the electricity distribution tariff process. Among other things, the new law reduced the rate for calculating annual investment costs from 10% to a percentage calculated by the CNE every four years (which will be a yearly after-tax rate of between 6% and 8%) and established that the after-tax rate of return for each distribution company must be between three percentage points below and two percentage points above the rate calculated by the CNE. The Chilean Congress is currently discussing an electricity distribution tariff reform (“ley larga”), which, if approved, may reduce our future profitability. Tariffs remained fixed in 2020 under law 21,185, which creates a temporary electricity price stabilization mechanism for customers subject to tariff regulation. However, we expect a new tariff decree by December 2021 for the 2020-2024 period, retroactive to November 2020. We expect tariffs to be lower due to the new 6% after-tax discount rate.

Our operating subsidiaries are also subject to environmental regulations that, among other things, require us to perform environmental impact studies on future projects and obtain construction and operating permits from local and national regulators. Governmental authorities may withhold or delay the approval of these permits until the completion of environmental impact studies. Therefore, their processing time may be longer than expected. Environmental regulations for existing and future generation capacity have become stricter and require increased capital investments. Any delay in meeting the required emission standards may constitute a violation of the environmental regulations. Failure to certify monitoring systems’ original implementation and ongoing emission standard requirements may result in significant penalties and sanctions or legal claims for damages. We expect that more restrictive emission limits will be established in the future. We are also subject to an annual “green tax” based on our GHG emissions in the previous year. Such taxes may increase in the future and discourage thermal electricity generation.

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

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

Future climate change legislation and regulation restricting or regulating GHG emissions could increase our operating costs and have a material adverse effect on our business, results of operations, and financial condition. The adoption and implementation of any international treaty, legislation, or regulation imposing new or additional reporting obligations or limiting emissions of GHGs from our operations could require us to incur additional costs to comply with such requirements and possibly require the reduction or limitation of GHG emissions associated with our operations. These higher compliance standards may involve additional costs to operate and maintain our equipment and facilities,

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install emission controls, or pay taxes and fees relating to GHG emissions, which could have a material adverse effect on our business, results of operations, and financial condition.

Our business faces risks from promoting decarbonization efforts both on a global and national scale.

In June 2019, the Chilean government announced its plan to phase out coal entirely from its energy mix by 2040 and achieve carbon neutrality by 2050. Our subsidiaries, Enel Generation and GasAtacama signed an agreement with the Chilean Ministry of Energy defining the process for the closures of our coal-fired power plants: Tarapacá (158 MW), Bocamina I (128 MW), and Bocamina II (350 MW). We closed the Tarapacá plant in December 2019 and the Bocamina I plant in December 2020, both ahead of schedule. We expect to close the Bocamina II plant by May 2022, well ahead of the scheduled deadline of December 31, 2040.

Even though the Chilean government’s plan to achieve decarbonization may overlap with our sustainability strategy, the governmental targets’ actual implementation may exert considerable pressure on us and our ability to satisfy our contractual obligations with other cleaner sources. In turn, this may increase our expenses, decrease our profitability, and limit our ability to satisfy electricity demand fully.

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

The Chilean Water Authority (Dirección General de Aguas) grants us water rights for water supply from rivers and lakes near our production facilities. Currently, these water rights are (i) for unlimited duration, (ii) absolute and unconditional property rights, and (iii) not subject to further challenge. Chilean generation companies must pay an annual license fee for unused water rights. New hydroelectric facilities are required to obtain water rights, and the conditions of such water rights may affect the design, timing, or profitability of a project.

Also, the new Chilean constitution being drafted may change existing rights, including rights to exploit natural resources and water and property rights, any of which could adversely affect our business, results of operations, and financial condition.

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

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

Our electricity businesses are subject to regulatory fines for any breach of current regulations, including failures to supply energy. Local regulatory entities supervise our generation subsidiaries. They may be subject to fines or penalties when the regulator determines that the company is responsible for the operational failures that affect the system’s regular energy supply, including coordination issues. Regulations establish a compensation fee to end customers when energy is interrupted more than the standard allowed time due to events or failures affecting transmission facilities.

In 2020, the Superintendence of Electricity and Fuels (“SEF”) fined Enel Distribution 22,000 UTM (Ch$ 1.1 billion) for breaches in quality standards of supply. On December 3, 2020, Enel Distribution filed an appeal of the SEF fine, which is still pending as of the date of this Report. Please refer to Note 38 of the Notes to our consolidated financial statements for further information on fines. Additionally, in 2020, SEF fined Enel Distribution 40,000 UTM (Ch$ 2 billion) for failure to comply with technical quality standards. Enel Distribution filed an appeal on November 13, 2020, and a final decision is still pending.

Risk Related to Chile and Other Global Risks

Fluctuations in the Chilean economy, economic interventionist measures by governmental authorities, political and financial events, or other crises in Chile and other countries may affect our results of operations, financial condition, liquidity, and the value of our securities.

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All our operations are in Chile. Accordingly, our revenues are affected by the performance of the Chilean economy. Chile is also vulnerable to external shocks, such as financial and political events, that could cause significant economic difficulties and affect economic growth. If Chile experiences lower than expected economic growth or a recession, our customers will likely demand less electricity. Some of our customers may experience difficulties paying their electric bills, possibly increasing our uncollectible accounts.

We are exposed to economic and political volatility, including civil unrest in Chile due to the challenges arising from changes in economic conditions, regulatory policies, laws governing foreign trade, manufacturing, development, and investments, and various crises and uncertainties. These factors, either individually or in the aggregate, could severely impact Chilean economic growth and our business, results of operations, and financial condition. Starting in October 2019, Chile began to experience social turmoil throughout the country. Increasingly violent student and civil protests brought about widespread and severe tensions, indiscriminate violence and vandalism, significant public and private sector property damage, and disruption to institutions, commerce, general safety, civilian welfare, and peace. In response, the government launched various political, social, and economic reforms, including a guaranteed minimum wage, an increase in government-subsidized pensions, stabilization of electricity costs, a higher tax bracket for high-income earners, new health insurance programs, a pay cut for the members of the Chilean Congress and certain civil servants, and authorizing current withdrawals from individually funded private-sector pension accounts that usually only permit withdrawals in retirement.

In this context, the Chilean government held a national referendum in October 2020 to decide whether to create a new Chilean constitution and whether a popularly elected assembly or a combination of current legislators and a popularly elected assembly would draft the new constitution. Nearly 80% of voters approved the referendum for a new constitution and opted to have a popularly elected assembly draft the new constitution. Any new constitution could alter the Chilean political situation, affect the Chilean economy and its business outlook. A new constitution may also change existing rights, including rights to exploit natural resources, and water and property rights, any of which could adversely affect our business, results of operations, and financial condition.

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

We are subject to the adverse effects of worldwide pandemics.

An international public health crisis, such as the one attributable to the Covid-19 pandemic that began in December 2019, has led to high unemployment levels in Chile and has impacted electricity demand, financial markets, and the ability of our business to generate income. For the year ended December 31, 2020, sales from energy distribution decreased 3.8%, sales from energy generation decreased 2.4%, and our collection rates fell 2.1%. We believe that the Covid-19 pandemic lowered our net income due to lower energy demand and increased uncollectible debts.

In March 2020, due to the Covid-19 pandemic, Chilean President Sebastián Piñera decreed a state of emergency (estado de excepción constitucional de catástrofe) for an initial 90 days, which was subsequently extended several times and is currently in effect until June 30, 2021. Under this executive authority, President Piñera has instituted nighttime military curfews, selective mandatory quarantines in affected areas, control of entrance, exit and traffic within specified zones, the prohibition of mass gatherings, and the closing of public schools, among other measures. The private sector has voluntarily taken further actions, such as adopting telecommuting wherever possible and closing commercial offices. Many businesses, such as restaurants and retail stores, have temporarily closed or have opened under constrained capacity, either voluntarily or by executive decree. Companies associated with travel, transportation, and tourism have been severely affected, and many have gone bankrupt.

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The government also announced the tightening of Chile’s borders through the month of April 2021. Chilean citizens and residents may enter Chile but are not allowed to depart from the country unless they qualify for exceptional consideration. Non-resident foreigners will not be allowed to enter Chile but will be permitted to depart.

The cumulative effect of measures of this kind has led to high unemployment levels, reduced business operations, closures of businesses, reduced travel, and decreased demand for electricity. Recent increases in infection rates indicate a second wave of Covid-19 infections in 2021. In February 2021, Chile began to implement a widespread vaccination program. However, if there is a resurgence of the Covid-19 pandemic for any reason, including new strains for which vaccines are unavailable, or the vaccination program is ineffectual, our business, results of operations, and financial condition may be materially adversely affected.

Political events or financial or other crises in any region worldwide can significantly impact Chile and may unfavorably affect our operations and liquidity.

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

Financial and political events in other parts of the world could also negatively affect our business. For example, since 2018, the U.S. and China have been involved in a trade war involving protectionist measures that increase volatility in financial markets worldwide due to the uncertainty of political decisions. Also, instability in the Middle East or any other major oil-producing region could result in higher fuel prices worldwide, which would increase the operating costs for our thermal generation power plants and unfavorably affect our results of operations and financial condition. An international financial crisis and its disruptive effects on the financial industry could adversely affect our ability to obtain new bank financings under the same historical terms and conditions that we have benefited from to date.

Political events or financial or other crises could also diminish our ability to access capital markets in Chile and international capital markets as sources of liquidity or increase interest rates available to us. Reduced liquidity could negatively affect our capital expenditures, long-term investments and acquisitions, growth prospects, and dividend payout policy.

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

The Chilean peso has been subject to devaluations and appreciations against the U.S. dollar and may be 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.

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.

The relative illiquidity and volatility of the Chilean securities markets could unfavorably affect the price of our common stock and ADS.

Chilean securities markets are substantially smaller and have less liquidity than major securities markets in the United States and other developed countries. The low liquidity of the Chilean markets may impair shareholders’ ability to sell shares, or holders of ADS to sell shares of our common stock withdrawn from the ADS program, on Chilean Stock Exchanges in the amount and at the desired price and time.

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

All our operations are located outside of the United States. All our directors and officers reside outside of the United States, and substantially all their assets are located outside the United States. If investors were to bring a lawsuit against our directors and officers in the United States, it may be difficult for them to effect service of legal process within the United States upon these persons. It may also be difficult to enforce judgments obtained in the U.S. courts based on civil liability provisions of U.S. federal securities laws against them in U.S. or Chilean courts. There is also doubt about whether an action could be brought successfully in Chile for liability based solely on the civil liability provisions of U.S. federal securities laws.

We identified a material weakness in our internal controls over financial reporting, which, if not remediated, could result in material misstatements of our consolidated financial statements or cause us to fail to meet our periodic reporting obligations.

Our management assessed the effectiveness of its internal control over financial reporting as of December 31, 2020, based on criteria established in the framework “Internal Controls — Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the assessment, we 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

A. History and Development of the Company.

We are a publicly held limited liability stock corporation organized on March 1, 2016, under the laws of the Republic of Chile. Since April 2016, we have been registered in Santiago with the CMF under Registration No. 1139. We are also registered with the SEC under the commission file number 001-37723. Our full name is Enel Chile S.A., and we are also known commercially as “Enel Chile.” 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.”

Our contact information in Chile is:

Contact Person:	Nicolás Billikopf
Street Address:	Av. Santa Rosa 76, Piso 15 Comuna de Santiago Santiago, Chile
Email:	nicolas.billikopf@enel.com
Telephone:	(56-9) 9343 5500
Website:	www.enelchile.cl

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.

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.

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.

The 2018 Reorganization

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

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● a cash tender offer by Enel Chile for all outstanding shares of common stock (including ADS) of Enel Generation.

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

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

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.

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.

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.

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.

Enel Generation

In June 2019, Enel Generation and its subsidiary GasAtacama signed an agreement with the Ministry of Energy that complemented our sustainability strategy and strategic plan and defined the process for the progressive closure of our coal-fired power plants Tarapacá, Bocamina I, and Bocamina II, which have a gross installed capacity of 158 MW, 128MW, and 350 MW, respectively.

The agreement is subject to the full implementation of the Power Transfer Regulation, which defines the Strategic Reserve State and establishes, among others, the essential conditions that ensure non-discriminatory treatment between generation companies. Under the agreement, we were formally and irrevocably obligated to close Bocamina I and Tarapacá. The deadline for closing Tarapacá was May 31, 2020; however, upon receiving authorization from the 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.

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

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

● On November 9, 2017, GasAtacama purchased the remaining 25% minority interest in Central Eólica Canela S.A, which was dissolved on December 22, 2017. Our economic interest in GasAtacama was 93.7% as of December 31, 2018.

● In September 2019, we completed the intercompany sale of our 2.6% stake in GasAtacama to Enel Generation. On October 1, 2019, GasAtacama merged into Enel Generation. This transaction reorganized and simplified the corporate structures of the subsidiaries that comprised the GasAtacama group to generate corporate and operational efficiencies for us.

Enel Distribution

Pursuant to Law No. 21,194 (known as “Ley Corta”) adopted in 2020, the Ministry of Energy requires Chilean distribution companies to operate as a separate public distribution business line with its own accounting and management without including other businesses, such as an electricity transmission business.

On December 3, 2020, Enel Distribution held an extraordinary shareholders’ meeting to approve the separation of its distribution and transmission business lines into two separate companies. Enel Distribution carried out a corporate reorganization on January 1, 2021, pursuant to which each shareholder of Enel Distribution received one share of the new company, Enel Transmission, for each share of Enel Distribution held, maintaining the same ownership position in each company after the spin-off. The energy commercialization segment, formerly executed by Enel Distribution, was transferred to Enel Generation Chile to improve synergies and cost-efficiency among affiliates.

Enel Green Power Chile (EGP Chile)

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

● on June 1, 2020, six subsidiaries of EGP Chile were merged and subsequently dissolved: Parronal SpA, Parque Solar Maipu SpA, Crucero de Atacama SpA, Crucero Este Uno SpA, Crucero Este Dos SpA, and Crucero Este Tres SpA; and

● on July 1, 2020, Panguipulli merged into Taltal Wind Farm (the legal surviving entity) and on August 1, 2020, Taltal Wind Farm merged into Almeyda Solar. On January 1, 2021, Almeyda Solar merged into EGP Chile (the legal surviving entity).

Capital Investments, Capital Expenditures, and Divestitures

We coordinate our overall financing strategy, including the terms and conditions of loans and intercompany advances entered into by our subsidiaries, 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.

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.

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.

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

	Estimated 2021-2023	2020	2019	2018
	(in millions of Ch$)
Capital Expenditure(1)	1,674,000	554,314	321,079	300,539

(1) Capital Expenditure figures listed in this table represent cash flows used to purchase property, plant and equipment, and intangible assets for each year, except for future projections.

While our planned investments go beyond the three years highlighted in this table, we 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.

Capital Expenditures in 2020, 2019, and 2018

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.

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.

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.

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.

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.

B. Business Overview.

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.

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:

	Year ended December 31,
Revenues	2020	2019	2018	Change 2020 vs. 2019
	(in millions of Ch$)			(in %)
Generation	1,577,422	1,726,612	1,580,653	(8.6)
Distribution	1,382,068	1,412,872	1,263,224	(2.2)
Other businesses and intercompany transaction adjustments	(374,088)	(368,649)	(386,716)	(1.5)
Total revenues	2,585,402	2,770,834	2,457,161	(6.7)

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.

Electricity Generation Business Segment

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.

For the year ended December 31, 2020, our consolidated electricity generation was 19,331 GWh in 2020. Our sales were 22,960 GWh, representing an 8.1% decrease in electricity generation and a 2.4% decrease in sales compared to 2019.

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

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

ELECTRICITY DATA

	Year ended December 31,
	2020	2019	2018
Number of generating units(1)	1,028	1,029	1,030
Installed capacity (MW)(2)(3)	7,200	7,303	7,463
Electricity generation (GWh)	19,331	21,041	20,046
Energy sales (GWh)	22,960	23,513	24,369

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

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

(3) Bocamina I and Tarapacá steam turbine and coal plants were decommissioned on December 31, 2020, and December 31, 2019, respectively.

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.

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

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GENERATION BY TYPE OF ENERGY (GWh)

	Year ended December 31,
	2020		2019		2018
	Generation	%	Generation	%	Generation	%
Hydroelectric	9,712	50.2	10,578	50.3	11,395	56.8
Thermal	6,452	33.4	7,233	34.4	6,268	31.3
Other generation(1)	3,166	16.4	3,230	15.4	2,384	11.9
Total generation	19,331	100.0	21,041	100.0	20,046	100.0

(1) Other generation includes wind, solar, and geothermal energy.

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

ELECTRICITY SALES BY CUSTOMER TYPE (GWh)

	Year ended December 31,
	2020		2019		2018
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales  Volume
Regulated customers	10,838	47.2	12,712	54.1	15,645	64.2
Unregulated customers	11,043	48.1	9,902	42.1	7,549	31.0
Total contracted sales(1)	21,881	95.3	22,614	96.2	23,194	95.2
Electricity pool market sales	1,079	4.7	899	3.8	1,174	4.8
Total electricity sales	22,960	100.0	23,513	100.0	24,369	100.0

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

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.

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

We attempt to minimize the risk of electricity generation deficits resulting from poor hydrological conditions in any given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated electricity production in a dry year. We consider the available statistical information concerning rainfall, mountain snow and ice, 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.

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.

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.

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.

Seasonality

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.

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.

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.

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.

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.

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

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

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

ELECTRICITY GENERATION BY COMPANY (GWh)

	Year ended December 31,
	2020	2019	2018
Enel Generation	13,613	15,428	11,314
EGP Chile(1)	3,418	3,493	2,673
Pehuenche	2,300	2,120	2,794
GasAtacama(2)	—	—	3,265
Total	19,331	21,041	20,046

(1) Includes all of EGP Chile’s subsidiaries.

(2) GasAtacama was merged into Enel Generation in October 2019.

The following table sets forth the electricity generation by type:

ELECTRICITY GENERATION BY TYPE (GWh)

	Year ended December 31,
	2020		2019		2018
	Generation	%	Generation	%	Generation	%
Hydroelectric generation	9,680	50.1	10,523	50.0	11,101	55.4
Thermal generation	6,452	33.4	7,233	34.4	6,268	31.3
Wind generation – NCRE(1)	1,768	9.1	1,845	8.8	1,352	6.7
Mini-hydro generation – NCRE(2)	32	0.2	55	0.3	293	1.5
Solar generation – NCRE	1,177	6.1	1,190	5.7	872	4.4
Geothermal generation – NCRE	221	1.1	194	0.9	159	0.8
Total generation	19,331	100.0	21,041	100.0	20,046	100.0

(1) Electricity generated by the Canela I and Canela II wind farms, and since 2018, all EGP Chile wind farms.

(2) Electricity generated in 2019 refers to the Ojos de Agua mini-hydroelectric plant. Before 2019, the information also includes generation by the Palmucho plant.

Water Resource Use Agreements

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.

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.

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.

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.

Thermal Generation

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.

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.

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.

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).

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.

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.

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.

Electricity sales and generation

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

The following table sets forth SEN’s electricity sales:

ELECTRICITY SALES IN SEN (GWh)

	Year ended December 31,
	2020	2019	2018
Total electricity sales (SEN)	71,808	71,670	71,179

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.

The following table sets forth our electricity generation and purchases:

ELECTRICITY GENERATION AND PURCHASES (GWh)

	Year ended December 31,
	2020		2019		2018
	(GWh)	% of Volume	(GWh)	% of Volume	(GWh)	% of Volume
Electricity generation	19,331	84.2	21,041	89.5	20,046	82.3
Electricity purchases	3,629	15.8	2,472	10.5	4,323	17.7
Total	22,960	100.0	23,513	100.0	24,369	100.0

We supply electricity to the major regulated electricity distribution companies, large unregulated industrial firms (primarily in the mining, pulp, and steel sectors), and the pool market. 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.

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.

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.

The most significant supply contracts with regulated customers are with our subsidiary Enel Distribution and with Compañía General de Electricidad S.A. (“CGE”), an unaffiliated entity. These are the two largest electricity distribution companies in Chile in terms of sales.

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

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

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

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.

Electricity Distribution Business Segment

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.

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.

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.

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

	Year ended December 31,
	2020	2019	2018
Electricity sales (GWh)	16,481	17,135	16,782
Residential	5,006	4,897	4,702
Commercial	4,606	4,924	5,107
Industrial	1,687	1,954	2,202
Other customers(1)	5,183	5,360	4,771
Number of customers (thousands)	2,008	1,972	1,925
Residential	1,801	1,768	1,725
Commercial	154	152	149
Industrial	12	13	13
Other customers(1)	41	40	39
Energy purchased (GWh)(2)	17,356	18,115	17,718
Total energy losses (%)(3)	5.2	5.0	5.0
SAIDI (minutes)	171	184	195
SAIFI (times)	1.5	1.6	1.5

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(1) The data for other customers includes tolls.

(2) In 2020, 2019, and 2018, Enel Distribution acquired 31%, 33%, and 37%, respectively, of its electricity purchases from Enel Generation.

(3) Energy losses are calculated as the percent difference between the energy purchased and energy sold, excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise from illegally tapped lines and technical losses.

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.

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.

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.

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.

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.

Seasonality

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.

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.

i) Generators:

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.

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.

ii) Transmitters:

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.

iii) Distributors:

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.

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.”

2. Electricity Law and Authorities

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.

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.

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.

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.

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

The CNE is the entity in charge of approving the annual transmission expansion plans, elaborating the indicative plan for the construction of new electricity generation facilities, and proposing regulated tariffs to the Ministry of Energy for approval. 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.

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

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).

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

● maintain service security;

● guarantee the efficient operation of facilities connected to the system; and

● guarantee open access to all transmission networks.

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CEN’s main activities include:

● coordinating of electricity market operations;

● authorization of connections;

● managing ancillary services, implementing information systems for the public; and

● monitoring competition and payments, among others.

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.

Limits on Integration and Concentration

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.

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.

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.

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.

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.

Resolution No. 667/2002 states that:

● electricity generation and distribution activities cannot be merged (Enel Chile must continue to keep both business segments separate and manage them as independent business units);

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

● members of the board of directors must be elected from different and independent groups; and

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

Pursuant to Law No. 21,194 (known as “Ley Corta”) adopted in 2020, the Ministry of Energy requires Chilean distribution companies to operate as a separate public distribution business line with its own accounting and management without including other businesses, such as an electricity transmission business. As of January 2021, and as

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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.

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.

3. Generation Segment

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.

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.

Dispatch, Customers, and Pricing

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.

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.

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

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

ii) Distribution companies: Distributors purchase energy from generation companies through an open bid process regulated by the CNE to satisfy regulated customers’ energy dispatch. Distributors may freely negotiate bilateral contracts with unregulated customers.

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

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energy traded on the spot market is the system’s hourly marginal cost and the price of capacity sold on the spot market at a specific node.

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.

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%.

For ancillary services, the regulator has defined four primary services that the system may require: (i) frequency control services; (ii) voltage control services; (iii) services to face contingency situations; and (iv) recovery services.

The system operator can obtain these services through (i) direct instruction to the power units that are the most efficient at delivering the service; (ii) auctions awarded to offers that most effectively reduce system costs; and (iii) bidding processes to develop new infrastructure aimed at providing the service. In 2021, auctions will only apply to secondary and tertiary frequency control services because the system operator has determined competitive conditions in that market.

Rationing

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

Generation companies may also be required to pay fines to the regulatory authorities 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.

Water Rights

Companies in Chile must pay an annual fee for unused water rights. License fees already paid may be recovered through monthly tax credits, commencing on the project’s start-up date 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.

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.

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:

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

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

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

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.

4. Transmission Segment

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.

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.

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

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

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.

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.

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.

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.

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

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.

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.

5. Distribution Segment

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.

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.

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.

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.

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.

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.

Distribution Tariffs

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.

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.

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.

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.

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.

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.

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.

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.

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.

Distribution-Related Services

Distribution-related services are services identified by the TDLC as subject to regulation, such as meter rentals and meter verification, among others. The CNE sets the tariffs of these services every four years, along with the VAD calculation.

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.

6. Environmental Regulation

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

Environmental Law No. 19,300 was enacted in 1994 and has been amended by several regulations, including the Environmental Impact Assessment System Rule issued in 1997 and modified in 2001. This law establishes a general framework of regulation of the right to live in a pollution-free environment, the protection of the environment, the preservation of nature, and 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.

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).

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.

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.

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.

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.

7. Raw Materials

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

C. Organizational Structure.

Principal Subsidiaries and Affiliates

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⁾

(1) Only principal operating consolidated entities are presented here.

(2) As of January 1, 2021, Enel Transmission was spun off from Enel Distribution.

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We consolidated 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.

Principal Subsidiaries	% Ownership of Each Main Subsidiary by Enel Chile	Consolidated Assets of Each Main Consolidated Entity	Revenues and Other Operating Income of Each Main Subsidiary
	(in %)	(in billions of Ch$)
Electricity Generation
Enel Generation	93.5%	3,091	1,490
EGP Chile(1)	99.9%	2,237	297
Electricity Distribution
Enel Distribution	99.1%	1,651	1,382

(1) EGP Chile is the result of EGPL merging into Enel Chile during the 2018 Reorganization

Generation Business

Enel Generation

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.

In June 2019, Enel Generation and its subsidiary GasAtacama Chile (now merged with and into Enel Generation) signed an agreement with the Ministry of Energy that complements our sustainability strategy and strategic plan and defines how to proceed with the progressive closures of our coal-fired power plants Tarapacá, Bocamina I and Bocamina II, which have a gross installed capacity of 158 MW, 128MW, and 350 MW, respectively.

The agreement is subject to the full implementation of the Power Transfer Regulation, which defines the Strategic Reserve State and establishes, among others, the essential conditions that ensure non-discriminatory treatment between generation companies. Under the agreement, we were formally and irrevocably obligated to close Bocamina I and Tarapacá. The deadline for closing Tarapacá was May 31, 2020. However, upon receiving authorization from the CNE to accelerate Tarapacá’s closure, we closed the plant ahead of schedule on December 31, 2019. The deadlines for closing Bocamina I and Bocamina II were December 31, 2023, and December 31, 2040, respectively. Nevertheless, we also shut down Bocamina I on December 31, 2020, and expect to voluntarily shut down Bocamina II by May 2022, well ahead of the deadline of 2040. By the end of 2022, Enel Chile, acting through Enel Generation, will become the first electricity company in Chile to complete its decarbonization process.

EGP Chile

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 (48MW) 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.

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%.

Distribution Business

Enel Distribution

Enel Distribution is one of the largest electricity distribution businesses in Chile, as measured by the number of regulated customers, distribution assets, and energy sales. Enel Distribution operates in a concession area of 2,105 square kilometers in the Santiago Metropolitan Region, serving over two million customers. Our economic interest in Enel Distribution is 99.1%.

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.

D. Property, Plant, and Equipment.

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

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).

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.

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

			Installed Capacity(1) As of December 31,
Company	Power Plant Name	Power Plant Type(2)	2020	2019	2018
			(in MW)
Enel Generation	Ralco	Reservoir	690	689	689
	Pangue(3)	Reservoir	467	466	466
	El Toro	Reservoir	450	449	449
	Rapel	Reservoir	377	376	376
	Antuco	Run-of-the-river	321	319	319
	Abanico	Run-of-the-river	136	136	136
	Cipreses	Reservoir	106	106	106
	Sauzal	Run-of-the-river	80	77	77
	Isla	Run-of-the-river	70	70	70
	Palmucho	Run-of-the-river	34	34	34
	Los Molles	Run-of-the-river	18	18	18
	Sauzalito	Run-of-the-river	12	12	12
	Ojos de Agua(3)	Run-of-the-river	9	9	9
	Total hydroelectric		2,770	2,759	2,759
	Atacama(3)	Combined Cycle /Natural Gas+Diesel Oil	732	732	732
	San Isidro 2	Combined Cycle /Natural Gas+Diesel Oil	388	388	388
	San Isidro 1(3)	Combined Cycle /Natural Gas+Diesel Oil	379	379	379
	Bocamina(4)	Steam Turbine/Coal	350	476	478
	Quintero	Gas Turbine/Natural Gas	257	257	257
	Taltal	Gas Turbine/Natural Gas+Diesel Oil	240	240	240
	Huasco	Gas Turbine	64	64	64
	Diego de Almagro	Gas Turbine/Diesel Oil	24	24	24
	Tarapacá	Gas Turbine/Diesel Oil	20	20	20
	Tarapacá(5)	Steam Turbine/Coal	—	—	158
	Total thermal		2,454	2,580	2,740
	Canela II(3)	Wind Farm	60	60	60
	Canela I(3)	Wind Farm	18	18	18
	Total wind farm		78	78	78
	Total		5,302	5,417	5,577
Pehuenche	Pehuenche	Reservoir	570	568	568
	Curillinque	Run-of-the-river	89	89	89
	Loma Alta	Run-of-the-river	40	40	40
	Total Pehuenche		699	697	697
EGP Chile(6)	Parque Solar Finis Terrae	Solar	160	160	160
	Parque Eólico Sierra Gorda Este	Wind	112	112	112
	Eólica Taltal	Wind	99	99	99
	Eólica Talinay Oriente	Wind	90	90	90
	Valle De Los Vientos	Wind	90	90	90
	Parque Eólico Renaico	Wind	88	88	88
	Pampa Solar Norte	Solar	79	79	79
	Carrera Pinto II Etapa	Solar	77	77	77
	Eólica Talinay Poniente	Wind	61	61	61
	Lalackama	Solar	60	60	60
	Pullinque	Run-of-the-river	51	51	51
	Cerro Pabellón	Geothermal	48	41	41
	Pilmaiquén	Reservoir	41	41	41
	Chañares	Solar	40	40	40
	Solar Diego de Almagro	Solar	36	36	36
	Eólica Los Buenos Aires	Wind	24	24	24
	Carrera Pinto I Etapa	Solar	20	20	20
	Lalackama 2	Solar	18	18	18
	Azabache	Solar	4	0	0
	Solar La Silla	Solar	2	2	2
	Total EGP Chile (NCRE)		1,200	1,189	1,189
	Total Aggregate Capacity for Enel Chile		7,200	7,303	7,463

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

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

(3) GasAtacama was merged into Enel Generation in October 2019.

(4) The Bocamina I steam turbine and coal plant were decommissioned on December 31, 2020.

(5) The Tarapacá steam turbine and coal plant were decommissioned on December 31, 2019.

(6) The acquisition of EGP Chile by Enel Chile was completed on April 2, 2018. It includes power plants of its subsidiaries Almeyda Solar SpA, Empresa Eléctrica Panguipulli S.A, Enel Green Power del Sur SpA, Geotérmica del Norte S.A., Parque Eólico Taltal S.A., Parque Eólico Talinay Oriente S.A., and Parque Eólico Valle de Los Vientos S.A.

Property, Plant, and Equipment of Distribution Companies

We conduct our distribution business through Enel Distribution and its subsidiary Enel Colina. A substantial portion of our distribution subsidiary’s cash flow and net income are derived from the sale of electricity distributed through our distribution installations.

The table below describes our leading electricity distribution equipment, such as distribution networks, substations, transformers, and transmission lines. They include the consolidated property, plant, and equipment figures of our subsidiary Enel Distribution.

TABLE OF DISTRIBUTION FACILITIES

General Characteristics

		Transmission Lines(1)(2)(3) As of December 31,
	Concession Area	2020	2019	2018
	(in km2)	(in kilometers)
Enel Distribution	2,105	683	683	367

(1) The transmission lines consist of circuits with voltages in the 35-220 kV range.

(2) Since 2019, the reported figures correspond to kilometers at the line circuit-level instead of at the line track-level.

(3) On January 1, 2021, the transmission business assets were spun-off to Enel Distribution shareholders as Enel Transmission.

Power and Interconnection Substations and Transformers⁽¹⁾⁽²⁾

	As of December 31, 2020			As of December 31, 2019			As of December 31, 2018
	Number of Substations	Number of Transformers	Capacity (MVA)	Number of Substations	Number of Transformers	Capacity (MVA)	Number of Substations	Number of Transformers	Capacity (MVA)
Enel Distribution	57	207	7,554	57	207	7,554	56	206	8,398

(1) The transformers’ voltage is in the range of 500 kV (in - high voltage, “hv”) and 1 kV (out - medium voltage, “mv”).

(2) On January 1, 2021, the transmission business assets were spun-off to Enel Distribution shareholders as Enel Transmission.

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Distribution Network - Medium and Low Voltage Lines⁽¹⁾

	As of December 31, 2020		As of December 31, 2019		As of December 31, 2018
	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage
			(in Kilometers)
Enel Distribution	5,406	11,960	5,349	11,819	5,331	11,678

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

Transformers for Distribution⁽¹⁾

	As of December 31, 2020		As of December 31, 2019		As of December 31, 2018
	Number of Transformers	Capacity (MVA)	Number of Transformers	Capacity (MVA)	Number of Transformers	Capacity (MVA)
Enel Distribution	21,997	5,108	21,839	4,963	21,767	4,739

(1) These transformers’ voltage is in the range of 34.5 kV (in - medium voltage, “mv”) and 380-110 V (out - low voltage, “lv”).

Insurance

Our electricity generation and distribution facilities are insured against damage caused by natural disasters such as earthquakes, fires, floods, other acts of god (but not for droughts, which are not considered force majeure risks and are not covered by insurance), and from damage from third-party actions, based on the appraised value of the facilities as determined from time to time by an independent appraiser. Based on geological, hydrological, and engineering studies, we believe that the risk of the previously described events resulting in a material adverse effect on our facilities is remote.

Claims under our subsidiaries’ insurance policies are subject to customary deductibles and other conditions. We also maintain business interruption insurance, providing coverage for the failure of any of our facilities for a period of up to 24 months, including the deductible period. Insurance policies include liability clauses, which protect our companies from claims made by third parties. The insurance coverage taken for our property is approved by each company’s management, considering the quality of the insurance companies and the coverage needs, conditions, risk evaluations of each facility, and general corporate guidelines. All insurance policies are purchased from reputable international insurers. We continuously engage with the insurance companies to negotiate what we believe is the most commercially reasonable insurance coverage.

Project Investments

We continuously analyze potential growth opportunities. The study and profitability assessment of our project portfolio is an ongoing effort. Industry technology allows for smaller, less environmentally damaging power plants. These plants can be built more quickly, allow greater flexibility to activate or deactivate according to system needs, and are preferred by our stakeholders. We favor renewable energy technology for our new power plant investments and seek opportunities by building new greenfield projects or modernizing existing brownfield assets and improving operational or environmental performance. Each project’s expected start-up is assessed and defined based on the commercial opportunities and our financing capacity to fund these projects. All our projects are financed with internally generated funds. Our project investments are ordinarily submitted for internal approvals in U.S. dollars, but occasionally they may be approved in another currency, including euros. The total amount invested as of the last fiscal year is presented in our functional currency, while the total approved investment is in the currency in which the project investment was approved, which may be different.

Below we list our most important projects under development. However, any decision related to construction will depend on commercial opportunities foreseen in the upcoming years, including future tenders for supplying the regulated market and the evolution of the regulatory framework (mainly associated with ancillary services). Budgeted amounts

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include connecting lines that could be owned by third parties and paid as tolls unless otherwise indicated. The financing for all of our projects described below comes from internally generated sources.

Distribution Business Projects

In 2020, our subsidiary Enel Distribution and its subsidiaries, Enel Colina and Empresa de Transmisión Chena, invested a total of Ch$ 116.7 billion in projects related to our customers’ natural growth rate, service quality requirements, and safety and information system needs.

The most relevant investments in 2020 include the following:

● Ch$ 34.8 billion in the medium- and low-voltage network to facilitate new customer connections, including residential and large volume customers and real estate projects.

● Ch$ 22,5 billion to reinforce feeders, specifically those defined in our quality plan. Automation of the medium-voltage network increased rapidly due to the installation of 335 new remote-control devices, reaching 2,462 devices controlled by our centralized network operations center.

● Ch$ 20.7 billion to further our digitalization processes.

● Ch$ 19.9 billion to increase our distribution capacity to high- and medium-voltage facilities: Bicentenario, Pudahuel, Quilicura, Pajaritos, Altamirano, San Joaquin, and San Jose´s Substations, and to reinforce feeders in the municipalities of Cerro Navia, Chena, San Bernardo, Vizcaya, Terminal, and Los Vientos;

● Ch$ 6.2 billion to corrective network maintenance, install transmission lines, and interconnection and power substations;

● Ch$ 4.6 billion to comply with regulations regarding network and substation normalization;

● Ch$ 3.8 billion in anti-theft measures, such as the shielding and reinforcement of the network; and

● Ch$ 4.4 billion in network relocations due to new highways and requests from municipalities.

Generation Business Projects

Projects Completed in 2020

Enel Generation

Antuco Smart Repowering Project

The Antuco repowering project was executed within our existing 321 MW Antuco power plant, located in the Bíobío Region in southern Chile. Antuco is a run-of-the-river hydroelectric power plant with two Francis vertical units. It uses the waters of the Polcura, Laja, and Pichipolcura Rivers and the discharges from the Abanico and El Toro power plants.

The project involved replacing one turbine (Unit I) installed in 1981, with an efficiency rate of 88%, with a new turbine with a target efficiency rate of 94%, producing 204 GWh/year of new energy and increasing installed capacity by 1 MW. Replacing the turbine in Unit I was a two-step process. Step one was conducted in September 2019, and step two was completed in November 2020, reaching commercial operation in November 2020.

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As of December 31, 2020, the project has been completed, except for operational improvements. The total approved investment was US$ 14.5 million, of which Ch$ 7.0 billion (US$ 9.8 million) had been incurred as of December 31, 2020.

Sauzal Smart Repowering Project

The Sauzal Smart Repowering project was executed within our existing 80 MW Sauzal power plant, located in the Libertador General Bernardo O’Higgins Region in central Chile. It is a run-of-the-river hydroelectric power plant with three Francis vertical units that use the waters of the Cachapoal and Claro Rivers.

The project involved replacing two turbines (Unit I and Unit II) installed in 1948, with an efficiency rate of 88%, with new turbines with a target efficiency rate of 94.7%, each producing 13.7 GWh/year of new energy. The project increased installed capacity by 3 MW.

As of December 31, 2020, the project has been completed except for operational improvements. The construction of Unit I began in July 2019, and it achieved commercial operation in October 2019. The construction of Unit II began in August 2020, and it achieved commercial operation in October 2020.

The total approved investment was US$ 10.5 million, of which Ch$ 5.2 billion (US$ 7.4 million) had been incurred as of December 31, 2020.

Projects under Construction in 2020

Enel Generation

Bocamina Coal Plant Landfill Closure Plan

The project considers the application of the best practices for ash dumpsite facilities. It includes improvements to the landfill’s infrastructure and operations, the implementation of a high standard for its closure, and fulfillment of the obligations arising from the Environmental Qualification Resolution (“RCA” in its Spanish acronym) approved in March 2015. The closure plan comprises waterproofing materials that include a conductive geomembrane, use of the highest thicknesses of fillers and substrates, a selection of native species, a high density of specimens per hectare, and a revegetation design according to reference ecosystems in the area, with the advice of Universidad de Concepción.

The closure plan is composed of two stages:

● Stage 1: The approved project considers the closure of 67,000 m² of the landfill.

● Stage 2: This stage will be executed when the landfill completes its operational life.

In February 2019, the SEA issued all permits. In July 2019, the revegetation pilot was completed, and a notice to proceed with a contractor to complete stage 1 was given. The installation of waterproof materials and the application of soil and substrates fillers were completed on May 29, 2020. After this milestone, native species were planted, and the process was completed on September 16, 2020.

The total approved investment is €15.9 million, of which Ch$ 12.9 billion (€14.8 million) had been incurred as of December 31, 2020. We expect stage 2 to be completed in 2021-2022.

Los Cóndores Hydroelectric Project

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

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As of December 31, 2020, 75% of the project had been completed, and 89% of the transmission lines had been completed and assembled.

The total approved investment is US$ 1.2 billion, of which Ch$ 637.3 billion (US$ 879.0 million) had been incurred as of December 31, 2020. Construction began in April 2014, and we expect the project to be completed by 2023.

Rapel Smart Repowering Project

The Rapel Hydroelectric Repowering project will be executed within our existing 377 MW Rapel power plant, located in the Libertador General Bernardo O’Higgins Region in central Chile. Rapel is a reservoir hydroelectric power plant with five Francis vertical units that use water from the Rapel River.

The project involves replacing two turbines (Unit 3 and Unit 4) installed in 1968 with an efficiency rate of less than 85%. The turbines will have a new hydraulic design, offering improved efficiency and a more extensive operation range. We expect to increase installed capacity by 2 MW (1 MW each unit) and produce 67 GWh/year of new energy. The contract was awarded in September 2020, and the contractor’s basic design activities began immediately.

As of December 31, 2020, 2% of the project had been completed. In 2021, the engineering design will be completed, and model tests and the main manufacturing activities will be executed. Unit 3 will be dismantled, and the installation of the new turbine will begin in 2022. Once the new Unit 3 turbine has been installed, Unit 4 will be dismantled, and the new turbine will be installed.

The total approved investment is US$ 11.9 million, of which none had been incurred as of December 31, 2020. We expect both units to be installed and the project to be completed by 2023.

EGP Chile

Azabache Solar Project

Azabache is a photovoltaic (“PV”) project in Calama in the Antofagasta Region in northern Chile and is being executed within our existing Valle de los Vientos wind farm. The project has an installed capacity of 61 MW, consisting of 154,710 monocrystalline bifacial PV modules with a solar tracking system and occupying approximately 149 hectares.

The plant is connected to the Valle de los Vientos substation, which is connected to the Calama substation. The interconnection solution includes the main transformer and a step-up substation with a conventional bay, including its ancillary elements.

A connection contract between EGP Chile and Acciona was signed, which requires the Usya PV solar power plant project (owned by Acciona) to install the second circuit of the Valle de los Vientos – Calama transmission line (13.6 km) and the extension of Valle de los Vientos substation.

The total approved investment is US$ 49 million, of which Ch$ 28.0 billion (US$ 39.4 million) had been incurred as of December 31, 2020. Construction began in April 2020, and we expect the project to be completed by the end of the second quarter of 2021.

Campos del Sol I Solar Project

The Campos del Sol I solar project is in the Atacama Region in northern Chile, approximately 60 km northeast of Copiapó. The PV solar power plant has 382 MW of installed capacity and consists of 974,400 crystalline bifacial PV modules with a solar tracking system. It will be the largest PV solar power plant in Chile, covering approximately 1,700

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hectares. The connection point includes two main transformers through the Carrera Pinto substation, owned by Transelec, via a 7.5 km, 220 kV transmission line.

The project was awarded to EGP Chile during the 2016 Distribution Companies Tender. EGP Chile intended to bid part of this project in the bilateral processes to move up the commercial date of operation. The land has been secured, the environmental approval has been obtained, and the power purchase agreements for 2021-2045 have already been confirmed. The project has potential synergies with EGP Chile’s operational Carrera Pinto solar project.

The total approved investment is US$ 320.9 million, of which Ch$ 164.3 billion (US$ 231.2 million) had been incurred as of December 31, 2020. Construction began in August 2019, and we expect the project to be completed by the third quarter of 2021.

Cerro Pabellón Geothermal Extension Project

The Cerro Pabellón extension project is a geothermal energy plant with a capacity of 28 MW and is in the Antofagasta Region in northern Chile. It has potential synergies with our operational Cerro Pabellón geothermal project and will use existing infrastructure such as a substation and a transmission line.

The total approved investment is US$ 95.8 million, of which Ch$ 55.9 billion (US$ 78.7 million had been incurred as of December 31, 2020. Construction began in August 2019, and we expect the project to be completed by the end of the second quarter of 2021.

Domeyko Solar Project

The Domeyko PV solar project is in the Antofagasta Region in northern Chile. It has an installed capacity of 204 MW, consisting of 486,720 bifacial PV modules with a solar tracking system and occupying approximately 700 hectares.

The Domeyko project will be connected to the Puri substation, owned by Minera Escondida Ltda., via an 18 km, 220 kV interconnection line. The interconnection substation has a gas-insulated substation configuration, while the step-up substation will have a single bar configuration. The Domeyko project will sell energy to Enel Generation under a 20-year power purchase agreement.

The total estimated investment is US$ 164.2 million, of which Ch$ 71.7 billion (US$ 100.9 million) had been incurred as of December 31, 2020. Construction began in May 2020, and we expect the project to be completed by the end of the third quarter of 2021.

Finis Terrae Solar Extension Project

The Finis Terrae extension project is a PV solar power plant in María Elena in the Antofagasta Region in northern Chile and has an installed capacity of 126 MW.

The project has strong operational synergies with EGP Chile’s existing Finis Terrae power plant and will use the same transmission infrastructure as the existing Finis Terrae power plant. A new bay unit and new power transformer will be installed in the current substation for interconnection purposes.

The total approved investment is US$ 94.4 million, of which Ch$ 35.3 billion (US$ 49.7 million) had been incurred as of December 31, 2020. Construction began in May 2020, and we expect the project to be completed by the end of the fourth quarter of 2021.

Renaico II Wind Project

The Renaico II wind project is in the Araucanía Region in southern Chile. It consists of a 144 MW power plant with two farms: (i) the Las Viñas project, including a 58.5 MW wind power plant built by EGP Chile and (ii) the

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Puelche project, which consists of an 85.5 MW wind power plant developed independently by Pacific Energy. The Puelche project will be acquired in its entirety by EGP Chile.

The project consists of 32 wind turbine generators, interconnected to SEN through the existing Renaico I 220 kV substation. A new bay will be installed in the substation with a main transformer of 165 MVA. The Renaico II wind project has potential synergies with EGP Chile’s operational Renaico I wind project and will use existing infrastructure such as a substation and a transmission line. The land has been secured, and the environmental approvals were obtained.

The total approved investment is US$ 176.4 million, of which Ch$ 77.5 billion (US$ 109.0 million) had been incurred as of December 31, 2020. Construction began in April 2020, and we expect the project to be completed by the end of the third quarter of 2021.

Sol de Lila Solar Project

Sol de Lila is a PV solar project in the Atacama Desert in the Antofagasta Region in northern Chile, at an altitude of 2,700 meters and approximately 250 km southeast of the city of Antofagasta. Due to the project’s remoteness, the construction of a camp with a capacity for 400 people is required.

It is a greenfield solar project with an installed capacity of 163 MW that consists of 407,400 crystalline bifacial PV modules with a solar tracking system. The solar plant is connected to the Andes substation, owned by AES Gener, and includes one main transformer and a 1.2 km, 220 kV transmission line.

The total approved investment is US$ 129.7 million, of which Ch$ 58.5 billion (US$ 82.3 million) had been incurred as of December 31, 2020. Construction began in February 2020, and we expect the project to be completed by the end of the third quarter of 2021.

Projects under Development in 2020

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

Enel Generation

Quintero Combined-Cycle Thermal Project

The Quintero project is in the Valparaíso Region in central Chile. It is an energy efficiency project that will take advantage of the heat of the gases emitted by the existing turbines to produce steam by installing a steam turbine and a generator, which will convert the existing open-cycle plant into a combined-cycle gas plant. Currently, the Quintero plant has two gas turbines with a total capacity of 257 MW. With a steam turbine unit of 130 MW capacity, the Quintero plant will reach a full capacity of 387 MW. We will deliver the produced energy to SEN through the existing Quintero-San Luis line, a simple 220 kV circuit built to transmit the combined-cycle power plant’s energy.

In 2017, we started the preparation of the environmental assessment and the implementation of the sustainability plan. However, during August 2018, the Quintero and Puchuncaví areas suffered an ecological crisis that left more than 300 people suffering from the toxic effects of other industries’ gas emissions. As a result, the project was indefinitely postponed, and the environmental assessment has been suspended.

The total estimated investment is US$ 215.1 million, of which Ch$ 2.9 billion (US$ 4.0 million) had been incurred as of December 31, 2020.

San Isidro Power Plant Upgrade

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The San Isidro power plant is a combined cycle plant located in the Valparaiso Region in Central Chile. The power plant has two combined-cycle units, with a total installed capacity of 740 MW. The project consists of upgrading the existing gas turbines to improve the units’ efficiency. The capacity for each unit will increase by approximately 10 MW, which will increase the expected generation of the power plant.

The total estimated investment is US$ 10.2 million, of which Ch$ 51.8 million (US$ 0.1 million) had been incurred as of December 31, 2020. We expect work on the project to begin in 2023 and Unit 2 to be completed in 2023 and Unit 1 in 2026.

Taltal Combined-Cycle Thermal Project

The Taltal power plant is in the Antofagasta Region in northern Chile and has an installed capacity of 240 MW comprised of two 120 MW gas turbines. The project would convert the existing Taltal gas-fired, open-cycle plant into a combined-cycle plant by adding a turbine to the vapor phase. This turbine would use the steam generated by the gas turbines’ heat emissions to produce energy and considerably improve its efficiency. The steam turbine would add 130 MW of installed capacity, and therefore, the Taltal power plant would reach a total capacity of 370 MW. We would supply the energy produced to SEN via the existing 220 kV double-circuit, Diego de Almagro – Paposo transmission line.

The environmental permit, requested through an EIA and submitted in December 2013, was approved in January 2017 by the SEA in the Antofagasata Region. Any decision related to the development of the project will depend primarily on the commercial opportunities foreseen in the upcoming years, such as prices in future tenders and negotiations with unregulated customers, among others.

The total estimated investment is US$ 196.4 million, of which Ch$ 2.9 billion (US$ 4.0 million) had been incurred as of December 31, 2020. We expect the project to be completed in 2021-2023.

EGP Chile

Campos del Sol II Solar Project

The Campos del Sol II solar project is in Copiapó in the Atacama Region and has an installed capacity of 398 MW. Campos del Sol II is a PV solar power plant consisting of 893,508 crystalline bifacial PV modules with a solar tracking system. The plant is built on approximately 1,000 hectares.

The connection point will be the Bella Mónica step-up substation, located between Campos del Sol I and Campos del Sol II. Bella Mónica is located 8 km from the Illapa substation, owned by Celeo Redes Chile Ltda., and is connected via a 220kV transmission line.

The total estimated investment is US$ 273.6 million, of which Ch$ 12.8 billion (US$ 18.0 million) had been incurred as of December 31, 2020. We expect construction to begin in 2021 and the project to be completed in 2022-2023.

El Manzano Solar Project

The El Manzano solar project is located in the Metropolitan Region of Chile, with an installed capacity of 101 MW. The land has been secured, and environmental approval has been obtained.

The total estimated investment is US$ 78.1 million, of which none had been incurred as of December 31, 2020. We expect construction to begin in 2022 and the project to be completed in 2023.

Finis Terrae 3 Solar Project

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The Finis Terrae 3 solar project is located in the Antofagasta Region of Chile. It has an installed capacity of 18 MW and is an extension of the Finis Terrae Extension project currently under construction. The land has been secured, and environmental approval has been obtained.

The total estimated investment is US$ 11.1 million, of which Ch$ 14.1 million (US $ 0.02 million) had been incurred as of December 31, 2020. We expect construction to begin in 2021 and the project to be completed in 2021-2022.

PMGD Solar Projects

The PMGD solar projects represent a cluster of 10 solar PV plants located in Chile’s central region, with a cumulative installed capacity of 75 MW. The plants are located on separate plots of land, and the environmental approval process is ongoing.

The total estimated investment is US$ 51.6 million, of which Ch$ 4.7 billion (US$ 6.6 million) had been incurred as of December 31, 2020. We expect construction to begin in 2021-2022 and the projects to be completed in 2021-2022.

Sierra Gorda Solar Project

The Sierra Gorda PV solar project is in Sierra Gorda, near Calama, in the Antofagasta Region in northern Chile. The PV solar power plant has an installed capacity of 375 MW and occupies 850 hectares, with a perimeter of approximately 28 km.

It is a greenfield project that will be built inside the existing Sierra Gorda wind farm, which EGP Chile owns. The project has five main areas for PV modules inside the wind farm and an independent space for the medium voltage/high voltage substation. It consists of 830,000 monocrystalline bifacial PV modules with a solar tracking system. The interconnection substation is located 19 km from the solar plant, in the Centinela substation owned by Red Eléctrica Chile.

The total estimated investment is US$ 252.5 million, of which Ch$ 1.2 billion (US$ 1.7 million) had been incurred as of December 31, 2020. We expect construction to begin in 2021 and the project to be completed in 2022-2023.

Valle del Sol Solar Project

The Valle del Sol PV solar project is in the Atacama Desert, approximately 100 km west of Calama in the Antofagasta Region in northern Chile. It was awarded a 20-year power purchase agreement during the energy Distribution Companies Tender 2017 (2024-2043).

It is a greenfield solar project with an installed capacity of 163 MW that consists of 406,980 monocrystalline bifacial PV modules with a solar tracking system and occupying 320 hectares. Valle del Sol will connect to the Miraje substation, owned by Transelec, via a new 220 kV bay. The connection solution includes a step-up substation, one main transformer of 130/160 MVA (33/220 kV), and the interconnection 10 km, 220 kV transmission line.

The total estimated investment is US$ 125.4 million, of which Ch$ 30.2 billion (US$ 42.5 million) had been incurred as of December 31, 2020. We expect construction to begin in 2021 and the project to be completed in 2021-2023.

Major Encumbrances

As of December 31, 2020, we did not have any major encumbrances.

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Item  4A.      Unresolved Staff Comments

None.

Item  5.      Operating and Financial Review and Prospects

A. Operating Results.

General

The following discussion should be read in conjunction with our audited consolidated financial statements and the notes thereto, included in Item 18 in this Report, and “Selected Financial Data,” included in Item 3 of this Report. Our audited consolidated financial statements as of December 31, 2020, and 2019 and for each year in the three-year period ended December 31, 2020 have been prepared in accordance with IFRS, as issued by the IASB.

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

Through our subsidiaries, we own and operate electricity generation, transmission, and distribution companies in Chile. Our revenues, income, and cash flow are derived primarily from the operations of our subsidiaries and associates in Chile.

Factors such as (i) hydrological conditions, (ii) fuel prices, (iii) regulatory developments, (iv) extraordinary actions adopted by governmental authorities, and (v) changes in economic conditions may materially affect our financial results. Our results from operations and financial condition are affected by variations in the exchange rate between the Chilean peso and the U.S. dollar. We have certain critical accounting policies that affect our consolidated operating results. For the years covered by this Report, the impact of these factors on us is discussed below.

Since April 2, 2018, we have owned 93.6% of Enel Generation and consolidated operations and results of EGP Chile, a wholly-owned subsidiary, following the completion of the 2018 Reorganization. For further information regarding our incremental acquisition of Enel Generation, please refer to “Item 4. Information on the Company — A. History and Development of the Company. — History.” The effects of this transaction on our consolidated financial statements as of and for the years December 31, 2020, and 2019 are described in Note 5 to our consolidated financial statements.

On November 2, 2019, the Ministry of Energy published Law No. 21,185, establishing a Transitional Mechanism for the Stabilization of Electric Power Prices for Customers subject to Tariff Regulation (the “Tariff Stabilization Law”). An agreement to sell up to US$ 290 million of the accounts receivables generated through this mechanism was executed with Goldman Sachs and the Inter-American Development Bank.

On September 14, 2020, the National Energy Commission published Exempt Resolution No. 340, which modified the technical provisions for implementing the Tariff Stabilization Law. This Resolution clarified that the payment to each supplier must be imputed to the payment of balances chronologically, first paying off the oldest balances and then the newest ones, and not on a weighted basis over the total payment balances pending, as the industry had interpreted before said date. The effects of the Tariff Stabilization Law as of December 31, 2020, and 2019 are described in Note 9a.1 to our consolidated financial statements.

In 2020 and 2019, we recorded impairment costs associated with accelerating the closures of the Tarapacá, Bocamina I, and Bocamina II coal-fired power plants (see Notes 16.e.x and 31.b. to our consolidated financial statements). In 2019, we accounted for non-recurring income from the early termination of three energy supply contracts signed in 2016 between Enel Generation and Anglo American Sur. The effects are described in Note 28.3 to our consolidated financial statements.

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a.Generation Business

A substantial part of our generation capacity is hydroelectric and depends on the prevailing hydrological conditions in Chile. Our installed capacity as of December 31, 2020, 2019, and 2018 was 7,200 MW, 7,303 MW, and 7,463 MW, respectively, of which 49.5%, 48.6%, and 47,5% was hydroelectric, respectively. See “Item 4. Information on the Company — D. Property, Plant and Equipment.”

Hydroelectric generation was 9,712 GWh, 10,578 GWh, and 11,395 GWh in 2020, 2019, and 2018, respectively. Our hydroelectric generation decreased in 2020 compared to 2019, mainly related to lower hydrological production due to drier conditions. Since 2010, some critical reservoirs have been at relatively low levels due to several years of accumulated drought, characterized by low rainfall levels and low snowmelt.

Hydrological conditions in Chile can range from very wet, as a result of several years of abundant rainfall with lakes at their peak capacity, to extremely dry, as a consequence of a prolonged drought lasting for several years, the partial or material depletion of water reservoirs, and the significant reduction of snow and ice in the mountains, which in turn leads to materially lower levels of available water as a consequence of lower melts. There is a wide range of possible hydrological conditions between these two extremes, and their final effect on us often depends on accumulated hydrology. For instance, a new year with drought conditions has a smaller impact on us if it follows several abundant rainfall periods instead of exacerbating a prolonged drought. Likewise, an abundant hydrological year has a smaller marginal effect after several wet years instead of after a prolonged drought.

In Chile, the period of the year that typically has the most precipitation is from May through August. The period in which snow and ice in the mountains melt at higher levels is during the warmer months, from October through March, providing water flow to lakes, reservoirs, and rivers, which supply our hydroelectric plants, most of which are located in southern Chile.

We generally classify our hydrological conditions as either dry or wet, although there are several other intermediate scenarios. Extreme hydrological conditions materially affect our operating results and financial condition. However, it is difficult to indicate the effects of hydrology on our operating income without concurrently considering other factors. Our operating income can only be explained by looking at a combination of factors.

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

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

Hydrological conditions do not have an isolated effect but need to be evaluated in conjunction with other factors to understand the impact on our operating results better. Many different factors may affect our operating income, including

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the level of contracted sales, purchases and sales in the spot market, commodity prices, energy demand and supply, technical and unforeseen problems that can affect the availability of our thermal plants, plant locations in relation to urban demand centers, and transmission system conditions, among others.

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

Hydrological conditions	Expected effects on spot prices and generation	Expected impact on our operating results
Dry	Higher spot prices	Positive: if our generation is higher than our contracted energy sales, energy surpluses are sold in the spot market at higher prices. Negative: if our generation is lower than our contracted sales, we have an energy deficit and must purchase energy in the spot market at higher prices.
	Reduced hydroelectric generation	Negative: less energy available to sell in the spot market.
	Increased thermal generation	Positive: increases our energy available for sale and either reduces purchases in the spot market or increases sales in the spot market at higher prices.
Wet	Lower spot prices	Positive: if our generation is lower than contracted energy sales, the energy deficit is covered by purchases in the spot market at lower prices. Negative: if we have energy surpluses, they are sold in the spot market at lower prices.
	Increased hydroelectric generation	Positive: more energy available to sell in the spot market at lower prices.
	Reduced thermal generation	Negative: less energy available to sell in the spot market.

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

b. Distribution Business

Our electricity distribution business is conducted through Enel Distribution in the Santiago metropolitan area, providing electricity to more than 2.0 million customers. Santiago is Chile’s most densely populated area and has the highest concentration of industries, industrial parks, and office facilities.

For the year ended December 31, 2020, electricity sales were 16,481 GWh, representing a 3.8% decrease compared to 2019. For the year ended December 31, 2019, electricity sales amounted to 17,135 GWh, representing a 2.1% increase compared to 2018.

Distribution revenues are mainly derived from the resale of electricity purchased from generators. Revenues associated with distribution include the recovery of the cost of electricity purchased and the resulting revenues from the “Value Added from Distribution,” or VAD, plus the physical energy losses permitted by the regulator. Other revenues derived from our distribution business typically consist of transmission revenues, charges for new connections and maintenance, and rental of meters, among others. It also includes revenues from public lighting, infrastructure projects

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mainly associated with real estate development, and energy efficiency solutions, including air conditioning equipment, LED lights, etc., in all cases, including customers outside of our concession area.

Although these other revenue sources have increased, our core business continues to be the distribution of electricity at regulated prices. Therefore, the electricity regulatory framework has a substantive impact on our distribution business results. In particular, regulators set distribution tariffs considering the cost of electricity purchases paid by distribution companies (which distribution companies pass on to their customers) and the VAD, all of which are intended to reflect the investment and operating costs incurred by distribution and generation companies and to allow them to earn a regulated level of return on their investments and guarantee service quality and reliability. Our earnings are determined to a large degree by government regulation, mainly through the tariff setting process. Our ability to purchase electricity relies heavily on generation availability and, to a lesser degree, regulation. The cost of electricity purchases is passed on to end-users through tariffs that are set for multi-year periods. Therefore, variations in the price at which a distribution company purchases electricity do not impact our profitability.

In the past, we focused on reducing physical losses, especially those due to illegally tapped energy. Our physical losses have generally been around 5% over 20 years, a level close to our concession’s distribution technical loss threshold. Reducing losses below this level requires additional investments to reduce illegal tapping and would not be expected to have an economically attractive return. Currently, we are working instead on improving our efficiency, primarily through new technologies to automate our networks as well as in increasing our quality of service to enhance the effectiveness of our facilities, profitability of our business and increase our capacity to satisfy our growing number of customers and their increasing demands.

Enel Distribution’s tariff review process, which set the tariffs for the 2016-2020 period, was finalized in August 2017. The new tariffs were applied retroactively as of November 2016, and the review did not have a significant effect on Enel Distribution’s tariffs. Tariffs for residential, commercial, and industrial customers changed, but the changes offset each other, and Enel Distribution’s revenues remained stable. In September 2018, there was an tariff update process effective until the next tariff-setting process. This tariff increase recognizes the necessary investments to comply with the new requirements on the quality of service standards and was not retroactive. Tariff reviews seek to capture distribution efficiencies and economies of scale resulting from economic growth.

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.

In response to the Covid-19 pandemic, Law No. 21,249 was published on August 8, 2020, providing exceptional measures for end-users of health services, electricity, and natural gas. The law prohibits utility companies from cutting off services to residential and small businesses due to late payment for 90 days following the publication of the law. Also, unpaid amounts accrued from March 18, 2020 to November 30, 2020, may be paid in up to 12 equal and consecutive monthly installments, beginning in December 2020. The monthly installments may not include fines, interest, or associated expenses. On December 29, 2020, Law No. 21,301 was ratified and extended the terms defined in Law No. 21,249, increasing the prohibition on cutting off services to 270 days from 90 days, as well as the maximum number of monthly installments to 36 from 12.

c. Economic Conditions

Macroeconomic conditions, such as economic growth or recessions, changes in employment levels, and inflation or deflation, may significantly affect our operating results. Macroeconomic factors, such as the variation of the Chilean peso against the U.S. dollar, may impact our operating results, as well as our assets and liabilities, depending on the amounts denominated in U.S. dollars. For example, a devaluation of the Chilean peso against the U.S. dollar increases the cost of capital expenditure plans and the cost of servicing U.S. dollar debt. For additional information, see “Item 3. Key Information — D. Risk Factors — Foreign exchange risks may unfavorably affect our results and the U.S. dollar value of dividends payable to ADS holders.” and “Item 3. Key Information — D. Risk Factors — Fluctuations in the

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Chilean economy, economic interventionist measures by governmental authorities, political and financial events, or other crises in Chile and worldwide may affect our results of operations, financial condition, liquidity, and the value of our securities.”

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

	Local Currency U.S. Dollar Exchange Rates
	2020		2019		2018
	Average	Year End	Average	Year End	Average	Year End
Chilean pesos per U.S. dollar	792.22	710.95	702.63	748.74	640.29	694.77

Source: Central Bank of Chile

d. Critical Accounting Policies

Critical accounting policies are defined as those that reflect significant judgments and uncertainties that would potentially result in materially different results under different assumptions and conditions. We believe that our most critical accounting policies regarding the preparation of our consolidated financial statements under IFRS are those described below.

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

Impairment of Non-Financial Assets

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

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

The criteria used to identify the cash-generating units are in line with our management’s strategic and operational vision, within the specific characteristics of the business, the operating rules and regulations of the market in which we operate, and the corporate organization.

The recoverable amount is the greater of (i) the fair value less the cost needed to sell, and (ii) the value in use, which is defined as the present value of the estimated future cash flows. To calculate the recoverable value of property, plant and equipment, goodwill, and intangible assets that form part of a cash-generating unit, we use the value in use criteria in practically all cases.

To estimate the value in use, we prepare future pre-tax cash flow projections based on the most recent budgets available. These budgets incorporate management’s best estimates of cash-generating units’ revenues and costs using sector projections, past experience, and future expectations.

In general, these projections cover the next three years, estimating cash flows for future years and applying reasonable growth rates, which in no case are increasing nor exceed the average long-term growth rates for the Chilean electricity sector in which we operate. At the end of December 2020, projected cash flows were extrapolated using an annual growth rate of between 2.0% and 2.9%.

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Future cash flows are discounted to calculate their present value at a pre-tax rate that covers the cost of capital for the business activity and the geographic area in which it is carried out. The time value of money and risk premiums generally used among analysts for the business activity and the geographic zone are taken into account to calculate the pre-tax rate. The pre-tax discount rates, expressed in nominal terms, applied at the end of December 2020 were between 6.3% and 8.2%.

The pre-tax nominal discount rates applied in 2020, 2019, and 2018 are as follows:

Year ended December 31,
2020		2019		2018
Minimum	Maximum	Minimum	Maximum	Minimum	Maximum
6.3%	8.2%	7.7%	10.7%	6.9%	11.0%

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

Impairment losses recognized for an asset other than goodwill in prior periods are reversed when its estimated recoverable amount changes, increasing the asset’s value with a credit to earnings, limited to the asset’s carrying amount if no impairment loss had been recognized for the asset. Impairment losses for goodwill are not reversible.

Litigation and Contingencies

We are currently involved in legal and tax proceedings. As discussed in Note 25 of the Notes to our consolidated financial statements, we recognized provisions for legal and tax proceedings in an aggregate amount of Ch$ 16.3 billion as of December 31, 2020. This amount was based on consultations with our legal and tax advisors, who are carrying out our defense in these matters and analyzing potential results, assuming a combination of litigation and settlement strategies.

Hedges of Cash Revenues Directly Linked to the U.S. Dollar

We have established a policy to hedge the portion of our revenues directly linked to the U.S. dollar by obtaining financing in U.S. dollars. Exchange differences related to this debt, which are accounted for as cash flow hedge transactions, are charged net of taxes to an equity reserve account that forms part of Other Comprehensive Income. They are recorded as income during the period in which the hedged cash flows are realized. This term has been estimated at ten years.

This policy reflects a detailed analysis of our future revenues directly linked to the U.S. dollar to confirm that hedge accounting is applicable. Such analysis may change in the future due to new electricity regulations limiting the cash flows tied to the U.S. dollar.

Pension and Post-Employment Benefit Liabilities

We have various defined benefit plans for our employees. These plans pay benefits to employees at retirement and use formulas based on years of service and employee compensations. We also offer certain additional benefits for some specific retired employees.

The liabilities shown for the pensions and post-employment benefits reflect our best estimate of the future cost of meeting our obligations under these plans. The accounting applied to these defined benefit plans involves actuarial calculations, which contain key assumptions that include employee turnover, life expectancy, retirement age, discount rates, the future level of employee compensations and benefits, the claims rate under medical plans, and future medical costs. These assumptions change as economic and market conditions vary, and any change in any of these assumptions could have a material effect on the reported results from operations.

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The effect of an increase of 100 basis points in the discount rate used to determine the present value of the post-employment defined benefits would decrease the liability by Ch$ 5.6 billion, and Ch$ 5.3 billion, as of December 31, 2020, and 2019, respectively. The effect of a decrease of 100 basis points in the rate used to determine the present value of the post-employment defined benefits would increase the liability by Ch$ 6.1 billion, and Ch$ 5.8 billion as of December 31, 2020, and 2019, respectively.

.

Revenue and expense recognition

Revenue is recognized when the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which it is expected to be entitled upon the transfer of control, excluding the amounts collected on behalf of third parties.

We analyze and consider all relevant facts and circumstances for revenue recognition, applying the five-step model established by IFRS 15: 1) identifying the contract with a customer; 2) identifying the performance obligations; 3) determining the transaction price; 4) allocating the transaction price; and 5) recognizing revenue.

The following are the criteria for revenue recognition by type of good or service that we provide:

● Electricity supply (sale and transportation): Corresponds to a single performance obligation that transfers to the customer several different goods or services that are substantially the same and have the same transfer pattern. Since the customer receives and simultaneously consumes the benefits that we provide, it is considered a performance obligation met over time. In these cases, we apply an output method to recognize revenue in the amount to which it is entitled to bill for electricity supplied to date.

● Generation: Revenue is recognized according to the physical deliveries of energy and power, at the prices established in the respective contracts, at the prices stipulated in the electricity market by the current regulations, or at the marginal cost of energy and power, depending on whether unregulated customers, regulated customers, or energy trading in the spot market are involved, respectively.

● Distribution of electricity: Revenue is recognized based on the amount of energy supplied to customers during the period, at prices established in the respective contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate.

These revenues include an estimate of the service provided and not invoiced as of the balance sheet date. See Notes 2.3, 28, and Appendix 2.2 of our consolidated financial statements.

● Sale and transportation of gas: Revenue is recognized over time, based on the actual physical deliveries of gas in the period of consumption, at the prices established in the respective contracts.

● Other services: Mainly the provision of supplementary services to the electricity business, construction of works and engineering, and consulting services. Customers control committed assets as they are created or improved. Therefore, we recognize this revenue over time based on progress, measuring progress through output methods (performance completed to date, milestones reached, etc.) or resource methods (resources consumed, hours of labor spent, etc.), as appropriate in each case.

● Sale of goods: Revenue from the sale of goods is recognized at a particular time when control of the goods has been transferred to the client, which generally occurs at the time of the physical delivery of the goods. Revenues are measured at the independent sale price of each good and any type of appropriate variable compensation.

In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance obligations of the transaction, based on the control transfer pattern of each good or service that is separate and an independent selling price allocated to each of them, or two or more transactions jointly,

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when these are linked to contracts with customers that are negotiated with a single commercial purpose and the goods and services committed represent a single performance obligation, and their selling prices are not independent.

We determine the existence of significant financing components in its contracts, adjusting the value of the consideration if applicable and reflecting the effects of the time value of money. However, we apply the practical solution provided by IFRS 15. We will not adjust the amount of the consideration committed for a significant financing component if we expect, at the beginning of the contract, that the period between the payment and the transfer of goods or service to the customer is one year or less.

We exclude the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue figure. We only record as revenue the payment or commission to which we expect to be entitled.

Given that we mainly recognize revenue for the amount to which we have the right to invoice, we have decided to apply the practical disclosure solution provided in IFRS 15, through which we are not required to disclose the aggregate amount of the transaction price allocated to the obligations of performance not met (or partially not met) at the end of the reporting period.

Also, we evaluate the existence of incremental costs of obtaining a contract and costs directly related to the fulfillment of a contract. These costs are recognized as an asset if their recovery is expected with the transfer of the related goods or services and amortized in a manner consistent with the transfer of the related goods or services. The incremental costs of obtaining a contract are recognized as an expense if the depreciation period of the asset that has been recognized is one year or less. Costs that do not qualify for capitalization are recognized as expenses incurred unless they are explicitly attributable to the customer.

As of December 31, 2020, and 2019, we had not incurred costs to obtain or fulfill a contract that met the conditions for such capitalization. The expenses incurred to gain a contract are substantially commission payments for sales that, even though they are incremental costs, are related to short-term contracts or performance obligations met at a particular time. Therefore, we would recognize these costs as an expense if they occurred.

Interest revenue (expenses) are recorded considering the effective interest rate applicable to the principal with pending amortization during the corresponding accrual period.

Impairment of financial assets

Under IFRS 9 Financial Instruments, we apply an impairment model based on expected credit losses based on our history, existing market conditions, and prospective estimates at the end of each reporting period. The new impairment model is applied to financial assets measured at amortized cost or fair value through other comprehensive income, except for investments in equity instruments.

The expected credit loss, determined considering Probability of Default (PD), Loss Given Default (LGD), and Exposure at Default (EAD), is the difference between all cash flows that are owed under the contract and all the cash flows that are expected to be received (that is, all cash deficiencies), discounted at the original effective interest rate.

To determine the expected credit losses, we apply two separate approaches:

● General approach: Applied to financial assets other than trade accounts receivable, contractual assets, or lease receivables. This approach is based on evaluating significant increases in the credit risk of financial assets from the date of initial recognition. If the credit risk has not increased significantly on the date of issuance of the financial statements, the impairment losses are measured by reference to the expected credit losses in the next 12 months. If, on the other hand, the credit risk has increased significantly, the impairment is measured considering the expected credit losses for the lifetime of the asset. In general, the measurement of expected credit losses under the general approach is performed individually.

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● Simplified approach: Applied to trade receivables, contract assets, and lease receivables. The impairment provision is consistently recognized by reference to the expected credit losses for the asset’s lifetime. This approach is most commonly applied because trade receivables represent the principal financial asset of Enel Chile and our subsidiaries.

For trade accounts receivable, contractual assets, and accounts receivable for lease, we apply two types of evaluations of expected credit losses:

● Collective evaluation: Based on grouping accounts receivable into specific groups or “clusters,” considering each business and the local regulatory context. Accounts receivable are grouped according to the characteristics of client portfolios in terms of credit risk, maturity information, and recovery rates. A specific definition of default is considered for each group.

● Analytical or individual evaluation: If accounts receivable are considered individually significant by management, and there is specific information on any significant increase in credit risk, we apply an individual evaluation of accounts receivable. For the individual evaluation, the PD is generally obtained from an external provider.

Based on the reference market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for such accounts receivable, we mainly apply a default definition of 180 days after maturity to determine the expected credit losses, since this is considered an effective indicator of a significant increase in credit risk.

To measure the expected credit losses collectively, we consider the following assumptions:

● PD: average default estimate, calculated for each group of trade accounts receivable, taking into account a minimum of 24-month historical data;

● LGD: calculated based on the recovery rates of a predetermined section, discounted at the effective interest rate; and

● EAD: accounting exposure on the date of the financial report, net of cash deposits, including invoices issued but not due, and invoices to be issued.

The prospective adjustment can be applied based on specific management evaluations, considering qualitative and quantitative information to reflect possible future events and macroeconomic scenarios affecting the portfolio risk or the financial instrument.

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Recent Accounting Pronouncements

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

2. Analysis of Results of Operations for the Years Ended December 31, 2020, and 2019

Consolidated Revenues and other operating income

The following table sets forth our revenues and other operating income by reportable segment for the years ended December 31, 2020, and 2019:

	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	1,577,422	1,726,612	(149,189)	(8.6)
Distribution Business
Enel Distribution and subsidiaries	1,382,068	1,412,872	(30,804)	(2.2)
Non-electricity business and consolidation adjustments	(374,088)	(368,650)	(5,438)	(1.5)
Total Revenues and Other Operating Income (Loss)	2,585,402	2,770,834	(185,432)	(6.7)

Generation Business: Revenues and other operating income

Revenues and other operating income from our generation business decreased Ch$ 149.2 billion, or 8.6%, in 2020 compared to 2019, explained by:

(i)a decrease of Ch$ 111.6 billion in other operating income, mainly due to:

a. Ch$ 121.1 billion associated with non-recurring income recorded in 2019 due to the early termination of three energy supply contracts with Anglo American Sur, partially offset by

b. Ch$ 7.7 billion in higher revenues from temporary facility rentals.

(ii)a decrease of Ch$ 59.0 billion in other sales, mainly due to lower gas sales.

The decrease in our generation business revenues and other operating income was partially offset by:

(iii)an increase of Ch$ 21.6 billion in energy sales, mainly explained by:

a) Ch$ 53.2 billion, due to higher prices caused by the depreciation of the Chilean peso against the U.S. dollar;

b) Ch$ 23.1 billion from ancillary services related to service quality and safety; and

c) Ch$ 10.7 billion from commodity hedging; partially offset by:

d) Ch$ 65.4 billion in physical net sales for 554 GWh, explained by 1,874 GWh from lower regulated customers partially offset by 1,141 GWh from unregulated customers and 179 GWh from the spot market, related primarily to customer migration and the lockdowns declared in the country’s urban areas due to the Covid-19 pandemic.

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Distribution Business: Revenues and other operating income

Revenues and other operating income from our distribution business decreased Ch$ 30.8 billion, or 2.2%, in 2020 compared to 2019, primarily due to:

(i) Ch$ 48.2 billion in lower energy sales, primarily as the result of 654 GWh in lower physical energy sales, equivalent to Ch$ 50.3 billion, mainly from commercial and industrial customers, particularly during the second and third quarters of 2020 because of the lockdowns as a consequence of the Covid-19 pandemic. This decrease was partially offset by a higher average sales price as a consequence of a Ch$ 2.1 billion positive exchange rate effect; and

(ii) Ch$ 2.8 billion in other sales mainly due to (i) Ch$ 2.1 billion in lower income from a non-recurring sale of retail materials to Enel X Chile recorded in 2019 and (ii) Ch$ 0.7 billion in lower non-regulated business services revenues, such as the relocation of customer connections and networks.

The decrease in our distribution business revenues and other operating income was partially offset by higher revenues of:

(iii) Ch$ 18.8 billion from other services, mainly due to (i) Ch$ 11.4 billion in higher transmission tolls in the zonal transmission segment and (ii) Ch$ 7.4 billion from the construction of customer connections; and

(iv) Ch$ 1.4 billion in other operating revenues, mainly from insurance claims.

The number of customers rose by 35,802, or 1.8%, in 2020 to a total of 2,008,018. The increase in customers was mainly from residential and commercial customers.

Consolidated Operating Costs

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

The following two tables set forth the consolidated operating costs (excluding depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses, which are discussed below under Consolidated Selling and Administrative Expenses) for the years ended December 31, 2020, and 2019, by category and by business segment.

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	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Energy purchases	864,863	835,285	29,579	3.5
Fuel consumption	231,176	230,944	232	0.1
Transmission costs	141,540	196,849	(55,309)	(28.1)
Other variable procurement and services	136,866	158,127	(21,261)	(13.4)
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,374,446	1,421,205	(46,760)	(3.3)

	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	616,852	678,188	(61,335)	(9.0)
Distribution Business
Enel Distribution and subsidiaries	1,116,324	1,114,936	1,388	0.1
Non-electricity business and consolidation adjustments	(358,731)	(371,919)	13,187	3.5
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,374,446	1,421,205	(46,760)	(3.3)

Generation Business: Operating Costs

Operating costs of our generation business decreased Ch$ 61.3 billion, or 9.0%, in 2020 compared to 2019, mainly due to:

1) a decrease of Ch$ 55.4 billion, mainly explained by:

a)Ch$ 62.6 billion in lower transmission tolls primarily due to (i) Ch$ 42 billion in a lower electricity transmission charge (“CET” in its Spanish acronym) that is a component of the toll for feeding electricity into the national transmission system and (ii) Ch$ 18.1 billion in a lower cost of the zonal transmission system’s AAT (Spanish acronym for harmonization adjustment tariff); and

b)Ch$ 6.4 billion in gas transportation primarily due to a lower amount of gas purchased from Argentina, partially offset by

c)Ch$ 13.7 billion in higher regasification costs.

2) a decrease of Ch$ 23.2 billion in other variable procurement and services, mainly due to lower costs of:

a)Ch$ 40.7 billion in gas commercialization; and

b)Ch$ 1.4 billion in thermal emission taxes; partially offset by

c)Ch$ 13.5 billion in higher commodity hedging transactions; and

d)Ch$ 5.6 billion related to higher temporary facility rentals.

The decrease in our generation business operating costs was partially offset by higher costs of:

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3) Ch$ 17.0 billion in energy purchases, mainly explained by higher physical purchases in the spot market (1,425 GWh) due to (a) lower hydroelectric generation (866 GWh) as a result of the country’s hydrological conditions and (b) lower thermal dispatch (780 GWh) primarily related to lower coal-fired electricity generation; and

4) Ch$ 0.2 billion in fuel consumption primarily due to (a) Ch$ 23.7 billion in higher commodity hedging; (b) Ch$ 21.2 billion and Ch$ 0.3 billion in impairment losses on coal inventories and on diesel oil inventories, respectively, accounted for in the second quarter of 2020, due to the process to cease the operations of Bocamina II; (c) Ch$ 8.0 billion in gas consumption related to higher gas-fired electricity generation despite lower gas purchase prices; and (d) Ch$ 2.4 billion in fuel oil consumption, partly offset by Ch$ 56 billion in coal consumption related to lower coal-fired thermal generation and lower coal purchase prices during the period.

Distribution Business: Operating Costs

Operating costs of our distribution business increased slightly by Ch$ 1.4 billion in 2020 compared to 2019, mainly due to:

1) Ch$ 3.9 billion in energy purchases largely explained by Ch$ 48.2 billion from a higher purchase price, partially offset by Ch$ 44 billion in lower physical purchases (759 GWh) during the period; and

2) Ch$ 0.9 billion in transportation costs due to higher zonal transmission toll payments to electricity distribution and transmission companies.

The increase in our distribution business operating costs was partially offset by:

3) Ch$ 3.5 billion in lower other variable procurement and services, explained by (a) Ch$ 2.1 billion from the non-recurring sale of retail materials to Enel X Chile recorded in 2019 and (b) Ch$ 1.5 billion in other costs, mainly related to emergency plans.

Consolidated Selling and Administrative Expenses

Our selling and administrative expenses are salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.

The following two tables set forth our selling and administrative expenses for the years ended December 31, 2020, and 2019, by category and by business segment:

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	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Depreciation, amortization, and impairment losses	942,931	527,437	415,494	78.8
Other fixed costs	190,593	184,143	6,450	3.5
Employee benefit expenses and others	111,687	111,994	(307)	(0.3)
Total Consolidated Selling and Administrative Expenses	1,245,212	823,574	421,638	51.2

	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	1,056,586	652,489	404,098	61.9
Distribution Business
Enel Distribution and subsidiaries	165,855	145,642	20,213	13.9
Non-electricity business and consolidation adjustments	22,771	25,443	(2,673)	(10.5)
Total Consolidated Selling and Administrative Expenses	1,245,212	823,574	421,638	51.2

Consolidated selling and administrative expenses increased Ch$ 421.6 billion in 2020 compared to 2019, mainly due to a Ch$ 404.1 million increase in the generation business, explained by:

(i) an increase of Ch$ 415.5 billion in depreciation, amortization, and impairment costs in 2020 compared to 2019, mainly due to:

a) Ch$ 407.3 billion in the generation business segment, due to Ch$ 417.8 billion from Enel Generation as a result of the Ch$ 697.9 billion impairment recognized in 2020 related to accelerated schedule for the closure of the Bocamina II coal-fired power plant, compared to the impairment recognized in 2019 related to the announcement of the closures of the Tarapacá and Bocamina I coal-fired power plants, all of this as a result of the announced closure as part of our decarbonization process. This effect was partially offset by a decrease of Ch$ 11.1 billion, explained by Ch$ 21 billion in lower Enel Generation expenses primarily related to the depreciation of the coal-fired power plants impaired in 2019 and 2020, offset by Ch$ 10.3 billion in EGP Chile depreciation, mainly due to exchange rate effects; and

b) Ch$ 9.7 billion in the distribution business segment, mainly due to (i) Ch$ 4.9 billion in impairment expense of trade accounts receivable related to higher commercial debt partly caused by the Covid-19 pandemic; (ii) Ch$ 2.6 billion in intangible amortization related to software; and (iii) Ch$ 1.9 billion in fixed asset depreciation due to an increase in the transfer of assets to operations in connection with optimizing distribution network infrastructure to improve efficiency and quality of service.

(ii) Ch$ 6.5 billion in other fixed costs, mainly due to (i) higher technical support and administrative services and (ii) higher operation and maintenance costs related to customer service (call center and meter reading), maintenance, and repairs.

Consolidated Operating Income

The following table sets forth our operating income by reportable segment for the years ended December 31, 2020, and 2019:

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	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	(96,017)	395,935	(491,952)	(124.3)
Distribution Business
Enel Distribution and subsidiaries	99,889	152,294	(52,405)	(34.4)
Non-electricity business and consolidation adjustments	(38,128)	(22,174)	(15,954)	(72.0)
Total Consolidated Operating (Loss) / Income	(34,255)	526,055	(560,310)	(106.5)
Operating margin(1)	(1.3)%	19.0%	—	—

(1) Operating margin, a measure of efficiency, represents operating income as a percentage of revenues. However, caution must be applied in making comparisons among periods, which may have experienced non-recurring gains or losses, as was the case in 2020 and 2019 with the expense related to the closure of two coal-fired power plants.

Our operating income in 2020 decreased compared to 2019 due to the following:

Generation Business 

Revenues totaled Ch$ 1.6 trillion as of December 31, 2020, a decrease of 8.6%, mainly due to the income generated in March 2019 from the early termination of the contracts with Anglo American Sur, and lower sales from gas commercialization, partially offset by higher energy sales associated with a positive effect on the average sales price expressed in Chilean pesos.

The costs totaled Ch$ 617 billion as of December 31, 2020, a decrease of 9.0% compared to 2019, resulting from lower transportation expenses and lower other variable procurement and services costs.

Operating income was affected by the impairment of the Bocamina II coal-fired generating unit recognized in 2020, compared to the impairment recognized in 2019 related to the announcement of the closures of the Tarapacá and Bocamina I coal-fired power plants, partially offset by lower depreciation and amortization expense, primarily associated with the lower depreciation of the impaired coal-fired plants in 2019 and 2020.

Distribution Business

Revenues were Ch$ 1.4 trillion as of December 31, 2020, a decrease of 2.2% compared to 2019, mainly due to lower energy sales. Physical sales were 16,481 GWh as of December 31, 2020, reflecting a decline of 3.8% compared to 2019, mainly due to lower sales in the commercial and industrial segments primarily associated with quarantines imposed in the Santiago metropolitan region during the Covid-19 pandemic.

The costs remained stable at Ch$ 1.1 trillion as of December 31, 2020.

Operating income was mainly affected by (i) a higher impairment loss on trade receivables due to higher trade debt, primarily as a result of the Covid-19 pandemic; (ii) higher amortization of intangibles due to IT developments; and (iii) a higher depreciation of fixed assets due to an increase in the transfer of assets to operations in connection with optimizing distribution network infrastructure to improve efficiency and quality of service.

Consolidated Financial and Other Results

The following table sets forth our financial and other results for the years ended December 31, 2020, and 2019:

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	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Financial results
Financial income	36,160	27,399	8,761	32.0
Financial costs	(127,409)	(164,898)	37,489	22.7
Gain (loss) from indexed assets and liabilities	2,086	(2,982)	5,068	169.9
Foreign currency exchange differences	(23,272)	(10,412)	(12,860)	(123.5)
Total financial results	(112,435)	(150,893)	38,458	25.5
Other Results
Share of the profit (loss) of associates and joint ventures accounted for using the equity method	3,509	366	3,143	858.6
Other gains (losses)	9,489	1,793	7,696	429.2
Total Other results	12,998	2,159	10,839	502.0
Total Consolidated Financial and Other Results	(99,437)	(148,734)	49,297	33.1

Financial Results

We recorded a lower net financial expense for 2020, compared to 2019, primarily attributable to:

(i) a decrease of Ch$ 37.5 billion in financial costs, mainly due to:

a) Ch$ 23.8 billion from capitalized interest primarily related to the development of NCRE projects and greater continuity in the development of the Los Cóndores project, despite the Covid-19 pandemic;

b) Ch$ 14.5 billion related to the Tariff Stabilization Law, mainly explained by higher expenses recognized during the fourth quarter of 2019 when the law was implemented; and

c) Ch$ 7.3 billion in interest on bank loans, primarily due to the amortization of Enel Chile debt totaling Ch$ 213.8 billion and EGP Chile debt for Ch$ 187.4 billion; partially offset by

d) Ch$ 7.7 billion in higher interest on derivative contracts.

(ii) an increase of Ch$ 8.8 billion in financial income, mainly Ch$ 10.1 billion related to the Tariff Stabilization Law amounting, of which Ch$ 9.8 billion represents the impact of changes to the technical provisions established to implement such law determined by the CNE through Exempt Resolution No. 340, issued in September 2020, which was partially offset by Ch$ 1.7 billion in lower income on short-term fixed income investments.

(iii) an increase of Ch$ 5.1 billion in gains related to indexation of assets and liabilities primarily due to:

a) Ch$ 3.2 billion in lower indexation losses related to IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch of our subsidiary Enel Generation located in Argentina; and

b) Ch$ 1.9 billion from indexed financial instruments and derivatives.

(iv) an increase of Ch$ 12.9 billion in losses from exchange rate differences, mainly due to negative exchange rate effects arising from:

a) Ch$ 26.3 billion in trade account receivables, including a Ch$ 36.5 billion negative effect related to the Tariff Stabilization Law that set the U.S. dollar as the currency for the accounts receivables of pending billings to regulated customers;

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b) Ch$ 3.4 billion in trade account payables, including the Ch$ 11.2 billion positive effect related to the Tariff Stabilization Law; and

c) Ch$ 2.1 billion in financial debt and derivatives; partially offset by

d) the favorable exchange rate difference effect on (i) cash and cash equivalents for Ch$ 11.0 billion and (ii) other financial assets and liabilities for Ch$ 7.9 billion.

Other Results

Our gain from the disposition of assets increased Ch$ 7.9 billion in 2020 compared to 2019, mainly explained by the sale of the Quintero-San Luis transmission line for Ch$ 9.4 billion in December 31, 2020, compared to net income from the sale of a gas turbine to the related company Enel Generación Costanera for Ch$ 1.3 billion recognized in 2019.

We also registered an increase of Ch$ 3.1 billion in the share of the profit of associates and joint ventures recognized using the equity method in 2020 when compared to 2019.

Consolidated Income Tax Expenses

The effective tax rate was an income tax benefit of 60.8% in 2020 compared to an income tax expense of 16.2% in 2019.

Consolidated income tax benefit increased Ch$ 142.5 billion in 2020 compared to 2019. This is mainly due to:

(1) Ch$ 112.8 billion in higher income tax benefit due to the higher impairment loss recognized in 2020 as a result of our decarbonization plan;

(2) Ch$ 33.7 billion in higher income tax benefit related to Enel Generation’s fixed-asset goodwill recognized in 2020, resulting from the merger of GasAtacama Chile in 2019; and

(3) Ch$ 32.7 billion in lower income tax expense, due to non-recurring revenues as a result of the income generated in 2019 by the early termination of three energy supply contracts with Anglo American Sur.

The increase in our income tax benefit was partially offset by the non-recurrence of:

(4) Ch$ 29.3 billion in income tax benefit in 2019, resulting from the goodwill recognized due to the absorption of GasAtacama Argentina by GasAtacama Chile.

For further details, please refer to Note 19 of the Notes to our consolidated financial statements.

Consolidated Net Income

The following table sets forth our consolidated net income before taxes, income tax expenses, and net income for the years ended December 31, 2020, and 2019:

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	Years ended December 31,
	2020	2019	Change	Change
	(in millions of Ch$)			(in %)
Operating income (loss)	(34,255)	526,055	(560,310)	(106.5)
Other results	(99,437)	(148,734)	49,297	33.1
Net (Loss) / Income before Taxes	(133,692)	377,321	(511,013)	(135.4)
Income tax (expenses) / benefit	81,305	(61,228)	142,533	232.8
Consolidated Net (Loss) / Income	(52,387)	316,093	(368,480)	(116.6)
Net income attributable to the Parent Company	(50,860)	296,154	(347,014)	(117.2)
Net income attributable to non-controlling interests	(1,527)	19,939	(21,465)	(107.7)

Net income attributable to the Parent Company decreased Ch$ 347 billion in 2020 compared to 2019, mainly explained by an increase in impairment expense associated with the accelerated schedule for the Bocamina II coal-fired power plant closure as part of the decarbonization process and the income in 2019 from the early termination of three contracts signed in 2016 between Enel Generation and Anglo American Sur.

3. Analysis of Results of Operations for the Years Ended December 31, 2019 and 2018

Consolidated Revenues and other operating income

The following table sets forth our revenues and other operating income by reportable segment for the years ended December 31, 2019, and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	1,726,612	1,580,653	145,958	9.2
Distribution Business
Enel Distribution and subsidiaries	1,412,872	1,263,224	149,648	11.8
Non-electricity business and consolidation adjustments	(368,650)	(386,716)	18,066	4.7
Total Revenues and other operating income	2,770,834	2,457,161	313,673	12.8

Generation Business: Revenues and other operating income

Revenues and other operating income from our generation business increased Ch$ 146 billion in 2019 compared to 2018, explained by:

(i) an increase of Ch$ 105 billion in other operating income, mainly due to:

a) an increase of Ch$ 121.1 billion in non-recurring income from the early termination of three energy supply contracts with Anglo American Sur, offset by

b) a decrease of Ch$ 16.5 billion in revenues due to the non-recurring income from insurance compensation for claims related to incidents at Tarapacá received in 2018.

(ii) an increase of Ch$ 46.6 billion in revenues from electricity sales, mainly attributable to:

a) an increase of Ch$ 183.3 billion in sales due to a higher average sales price in Chilean pesos as a result of a higher average exchange rate for the period, offset by a decrease of Ch$ 92.2 billion due to a decline of 855 GWh in physical sales (2,933 GWh less to regulated customers and 275 GWh less in spot market sales, partially compensated by 2,353 GWh more to non-regulated customers). The lower physical sales to the regulated customers are due to the migration of customers from the regulated to a non-regulated market, together with a strong contraction in

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demand in October and November 2019 explained by the social crisis in Chile. In the case of spot market sales, the reduction is primarily due to lower hydrological generation of our plants;

b) a decrease of Ch$ 40.8 billion in revenues from exchange rate hedging derivatives; and

c) a decrease of Ch$ 7.5 billion in revenues from commodities hedging, such as coal and Brent oil; and

(iii) a decrease of Ch$ 5.9 billion in other sales mainly due to a reduction of Ch$ 6.1 billion in gas sales.

Distribution Business: Revenues and other operating income

Revenues and other operating income from our distribution business increased Ch$ 150 billion in 2019 compared to 2018, primarily due to:

(i) An increase of Ch$ 114.5 billion in sales due to a higher average sale price in Chilean pesos as a result of a higher exchange rate for the period;

(ii) an increase of Ch$ 22.6 billion, due to higher physical sales of 325 GWh; and

(iii) an increase of Ch$ 11.1 billion, due to the positive effect on the tariff that originated from the application of the technical standard of quality of service for distribution systems, which was established by the CNE in a resolution promulgated on December 2017.

The number of customers rose by 47,229 in 2019 to a total of 1,972,216. The increase in customers was mainly in the residential segment.

Consolidated Operating Costs

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

The following two tables set forth the consolidated operating costs (excluding depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses, which are discussed below under Consolidated Selling and Administrative Expenses) for the years ended December 31, 2019, and 2018, by category and by business segment.

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Energy purchases	835,285	747,647	87,638	11.7
Fuel consumption	230,944	231,028	(84)	(0.0)
Transmission costs	196,849	166,876	29,973	18.0
Other variable procurement and services	158,127	146,627	11,501	7.8
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,421,205	1,292,177	129,028	10.0

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	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	678,188	709,506	(31,319)	(4.4)
Distribution Business
Enel Distribution and subsidiaries	1,114,936	972,500	142,436	14.6
Non-electricity business and consolidation adjustments	(371,919)	(389,829)	17,910	4.6
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,421,205	1,292,177	129,028	10.0

Generation Business: Operating Costs

Operating costs of our generation business decreased Ch$ 31 billion in 2019 compared to 2018, mainly due to:

(i) a decrease of Ch$ 53 billion in energy purchases, equivalent to a reduction of 24.9% compared to 2018, partly explained by a decline of 1,850 GWh in physical energy purchases (1,216 GWh in spot market purchases and 634 GWh in contracted energy purchases), explained by the higher availability of our power plants and a decrease in physical sales. This lower cost includes the positive effect of the consolidation of EGP Chile with Enel Chile, which led to a net Ch$ 60.2 billion decrease in Enel Chile’s cost of energy purchases due to the elimination of related-party transactions (sales between EGP Chile and Enel Generation).

(ii) Fuel consumption costs remained unchanged in the aggregate, with higher coal costs completely offsetting lower fuel oil and gas costs:

a) a decrease of Ch$ 7.8 billion in fuel oil consumption significantly related to the lower dispatch of the power plants that operate with fuel oil;

b) a decrease of Ch$ 6 billion in gas consumption cost, mainly due to the lower price of gas as a result of an increase in the supply of gas from Argentina; and

c) an increase of Ch$ 13.7 billion in coal consumption costs due to higher thermal dispatch as a consequence of the poorer hydrologic conditions in Chile in 2019.

(iii) an increase of Ch$ 15 billion in transportation costs, mainly due to:

a) an increase of Ch$ 14.7 billion in gas transportation costs;

b) an increase of Ch$ 0.7 billion in regasification costs related to higher gas fueled electricity generation; and

c) a decrease of Ch$ 0.5 billion in toll expenses.

(iv) An increase of Ch$ 6.8 billion in other variable procurement and services costs, mainly due to:

a) an increase of Ch$ 10.5 billion in thermal emissions tax cost;

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b) an increase of Ch$ 1.7 billion in other various electricity generation supply costs (such as water, chemicals, etc.); and

c) a decrease of Ch$ 5.5 billion in costs of sales in the gas commercialization business.

Distribution Business: Operating Costs

Operating costs of our distribution business increased Ch$ 142 billion in 2019 compared to 2018, mainly due to:

(i) an increase of Ch$ 109.4 billion due to a higher average purchase price;

(ii) an increase of 397 GWh in physical purchases required to satisfy demand, equivalent to Ch$ 20.8 billion;

(iii) an increase of Ch$ 12.9 billion due to higher transportation costs; and

(iv) a decrease of Ch$ 0.6 billion in other variable procurement and services.

Consolidated Selling and Administrative Expenses

Our selling and administrative expenses are salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.

The following two tables set forth our selling and administrative expenses for the years ended December 31, 2019, and 2018, by category and by business segment:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Depreciation, amortization and impairment losses	527,437	220,750	306,687	138.9
Other fixed costs	184,143	167,211	16,932	10.1
Employee benefit expense and others	111,994	106,419	5,575	5.2
Total Consolidated Selling and Administrative Expenses	823,574	494,380	329,194	66.6

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	652,489	337,527	314,962	93.3
Distribution Business
Enel Distribution and subsidiaries	145,642	131,465	14,177	10.8
Non-electricity business and consolidation adjustments	25,443	25,388	55	0.2
Total Consolidated Selling and Administrative Expenses	823,574	494,380	329,194	66.6

Consolidated selling and administrative expenses increased Ch$ 329 billion in 2019 compared to 2018, mainly due to an increase in the generation business, explained by:

(i) the impairment expense associated with the Tarapacá and Bocamina I coal-fired generating units of Ch$ 197.2 billion and Ch$ 82.8 billion, respectively, as a result of their announced closures as part of our decarbonization process, and higher depreciation contributed by EGP Chile of Ch$ 27 billion;

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(ii) an increase of Ch$ 8.9 billion in costs of maintenance and repair services in the generation segment, an increase of Ch$ 3.8 billion in maintenance costs associated with the technical distribution standard, and an increase of Ch$ 3.5 billion in disposals and removals from service in property, plant, and equipment; and

(iii) an increase in employee benefit expenses corresponding to (i) an increase of Ch$ 3.1 billion in personnel expense, mainly due to higher staffing and the effect of the consolidation of EGP Chile for a full year in 2019 compared to nine months in 2018; and (ii) a decrease of Ch$ 2.1 billion in the capitalization of personnel cost.

Consolidated Operating Income

The following table sets forth our operating income by reportable segment for the years ended December 31, 2019, and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	395,935	533,620	(137,685)	(25.8)
Distribution Business
Enel Distribution and subsidiaries	152,294	159,259	(6,965)	(4.4)
Non-electricity business and consolidation adjustments	(22,174)	(22,275)	101	0.5
Total Consolidated Operating Income	526,055	670,605	(144,550)	(21.6)
Operating margin(1)	19.0%	27.3%	—	—

(1) Operating margin, a measure of efficiency, represents operating income as a percentage of revenues. However, caution must be applied in making comparisons among periods, which may have experienced non-recurring gains or losses, as was the case in 2019 with the expense related to the closure of two coal-fired power plants.

Our operating income in 2019 decreased compared to 2018 due to:

Generation Business 

Operating income was affected by the non-recurring loss generated from the impairment related to the announcement of the closure of the Tarapacá and Bocamina I coal-fired power plants, partially offset by the non-recurring income generated by the early termination of three energy supply contracts with Anglo American Sur.

On the other hand, during 2019, hydrological conditions were one of the driest in the last 10 years in Chile, causing a decrease in the generation of electricity from hydroelectric plants. As a result, we increased thermal generation, which increased our operating costs.

The commissioning of new NCRE plants and the interconnection between the central and northern interconnected systems helped to reduce the impact of the change in our energy matrix and stabilize the marginal operating costs in 2019 compared to 2018. As a result, we were able to cover our energy deficit in the spot market at lower prices. This energy deficit decreased mainly due to i) greater generation from our thermal plants, and ii) increased availability of Argentine natural gas for our combined cycles.

Although our physical sales decreased in 2019, they were sold at higher average sales prices expressed in Chilean peso due to a higher average exchange rate, which was partially offset by lower revenues as a result of the migration of customers from the regulated market to the non-regulated market.

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Distribution Business

Operating costs increased due to a higher average energy purchase price, higher physical purchases, and, to a lesser degree, higher operation and maintenance costs, depreciation of fixed assets and amortization of intangible assets due to higher transfers of constructions in progress to assets in operation. As a result, our distribution business operating income decreased in 2019.

Consolidated Financial and Other Results

The following table sets forth our financial and other results for the years ended December 31, 2019, and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Financial results
Financial income	27,399	19,934	7,465	37.4
Financial costs	(164,898)	(122,184)	(42,714)	(35.0)
Gain (loss) from indexed assets and liabilities	(2,982)	(818)	(2,164)	264.5
Foreign currency exchange differences	(10,412)	(7,807)	(2,605)	(33.4)
Total financial results	(150,893)	(110,875)	(40,018)	(36.1)
Other Results
Share of the profit (loss) of associates and joint ventures accounted for using the equity method	366	3,190	(2,824)	(88.5)
Gain (loss) from sales of assets	1,793	3,411	(1,618)	(47.4)
Total Other results	2,159	6,601	(4,441)	(67.3)
Total Consolidated Financial and Other Results	(148,734)	(104,274)	(44,460)	(42.6)

Financial Results

We recorded a higher net financial expense for 2019, compared to 2018, primarily attributable to:

(i) financial costs increased Ch$ 42.7 billion, mainly due to:

a) an increase of Ch$ 19 billion in expenses related to the Tariff Stabilization Law;

b) an increase of Ch$ 14.8 billion in financial expenses due to the consolidation of EGP Chile for a full year in 2019 compared to nine months in 2018;

c) an increase of Ch$ 11.9 billion in interest on bank loans related to our corporate reorganization carried out in 2018;

d) an increase of Ch$ 1.8 billion in financial expenses due to factoring operations; and

e) a decrease of Ch$ 4.9 billion in financial expenses due to the loan renegotiation between EGP del Sur and Enel Finance International.

(ii) an increase of Ch$ 7.5 billion in financial income, mainly due to:

a) an increase of Ch$ 5.2 billion in interest income related to the application of the Tariff Stabilization Law;

b) an increase of Ch$ 5.3 billion in interest income related to regulated customer accounts receivables to be billed before to the application of the Tariff Stabilization Law; and

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c) a decrease of Ch$ 2.4 billion in interest income on short-term fixed income investments, and Ch$ 0.2 billion in lower interest income from refinancing to customers.

(iii) an increase of Ch$ 2.2 billion in losses related to indexation primarily due to:

a) an increase of Ch$ 1.6 billion in losses due to a negative impact of IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch of the Enel Generación Group located in Argentina;

b) a decrease of Ch$ 0.8 billion in income from recoverable taxes;

c) a decrease of Ch$ 0.5 billion in income from hedging derivative contracts; partially offset by

d) a decrease of Ch$ 0.7 billion in losses as a result of indexation of financial liabilities recorded in U.F.

(iv) a decrease of Ch$ 2.6 billion in income from exchange rate differences, mainly due to negative exchange rate arising from:

(v) a decrease of Ch$ 2.6 billion in income from exchange rate differences, mainly due to negative exchange rate arising from:

a) a decrease of Ch$ 6.4 billion in forward contracts; and

b) a decrease of Ch$ 0.5 billion in cash and cash equivalents; partially offset by

c) the positive effects of (i) an increase of Ch$ 3 billion in trade accounts payable, and (ii) an increase of Ch$ 1.1 billion in trade accounts receivable, including an increase of Ch$ 3.8 billion due to the Tariff Stabilization Law that dollarized the regulated customer accounts receivable whose bills are outstanding.

Other Results

Our gain from disposition of assets decreased in 2019 compared to 2018, primarily due to a decrease of Ch$ 1.7 billion in sales of Enel Generation to third parties.

We also registered a decrease of Ch$ 2.8 billion in the share of the profit (loss) of associates and joint ventures accounted for using the equity method in 2019 when compared to 2018, mainly due to lower results compared to 2018 from (i) HidroAysén, which was liquidated in 2018, amounting to Ch$ 1.7 billion, and (ii) GNL Chile S.A. of Ch$ 1.1 billion.

Consolidated Income Tax Expenses

The effective tax rate decreased to 16.2% in 2019 compared to 27.1% in 2018.

Consolidated income tax expenses decrease of Ch$ 92.2 billion in 2019 compared to 2018. This decrease is mainly due to:

(i) a decrease of Ch$ 75.6 billion in tax expense as a result of the impairment of Bocamina I and Tarapacá coal-fired power plants in relation to their announced closures as part of the decarbonization process;

(ii) a decrease of Ch $ 29.3 billion, arising from the absorption of GasAtacama Argentina by GasAtacama Chile;

(iii) a decrease of Ch$ 8.1 billion in income tax expense associated with lower results;

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(iv) a decrease of Ch$ 6.3 billion in expense corresponding to non-refundable credits attributed to tax losses in 2018;

(v) a decrease of Ch$ 5.1 billion in income tax expense for Enel Chile due to a loss incurred on the sale of its interest in GasAtacama Chile to Enel Generation; and

(vi) an increase of Ch$ 32.7 billion in income tax expense for the non-recurring revenues generated by the early termination of three energy supply contracts with Anglo American Sur.

For further details, please refer to Note 20 of the Notes to our consolidated financial statements.

Consolidated Net Income

The following table sets forth our consolidated net income before taxes, income tax expenses and net income for the years ended December 31, 2019 and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Consolidated Operating income	526,055	670,605	(144,550)	(21.6)
Consolidated Other results	(148,734)	(104,274)	(44,460)	(42.6)
Consolidated Net income before taxes	377,321	566,331	(189,010)	(33.4)
Income tax expenses	(61,228)	(153,483)	92,255	60.1
Consolidated Net income	316,093	412,848	(96,755)	(23.4)
Net income attributable to the Parent Company	296,154	361,710	(65,556)	(18.1)
Net income attributable to non-controlling interests	19,939	51,138	(31,199)	(61.0)

The decrease in net income attributable to non-controlling interests in 2019 compared to 2018 of Ch$ 31.2 billion is primarily due to the decrease in the percentage of minority shareholders of Enel Generation corresponding to Enel Chile’s increased economic interest in Enel Generation after the completion of the 2018 Reorganization.

B. Liquidity and Capital Resources.

Our main assets are our consolidated Chilean subsidiaries, Enel Generation, EGP Chile, and Enel Distribution. The following discussion of cash sources and uses reflects the key drivers of our cash flow.

We receive cash inflows from our subsidiaries and related companies. Our subsidiaries’ and associates’ cash flows may not always be available to satisfy our own liquidity needs because there may be a time lag before we have access to those funds through dividends or capital reductions. However, we believe that cash flow generated from our business operations, cash balances, borrowings from commercial banks, short- and long-term intercompany loans, and ample access to the capital markets will be sufficient to satisfy all our needs for working capital, expected debt service, dividends, and planned capital expenditures in the foreseeable future.

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Set forth below is a summary of our consolidated cash flow information for the years ended December 31, 2020, 2019, and 2018:

	Year ended December 31,
	2020	2019	2018
	(in billions of Ch$)
Net cash flows provided by operating activities	756	744	736
Net cash flows used in investing activities	(555)	(312)	(1,882)
Net cash flows provided by (used in) financing activities	(128)	(440)	967
Net increase (decrease) in cash and cash equivalents before the effect of exchange rates changes	73	(8)	(179)
Effect of exchange rate changes on cash and cash equivalents	23	(1)	5
Cash and cash equivalents at the beginning of the period	236	245	419
Cash and cash equivalents at the end of the period	332	236	245

For the year ended December 31, 2020, net cash flow provided by operating activities increased Ch$ 12 billion, or 1.6%, compared to the same period in 2019. The increase was in part the result of:

(i) Ch$ 94 billion in collections from leasing and the subsequent sale of these assets, mainly from Ch$ 82 billion Enel X Chile received from leasing electric buses to the AMPCI consortium and Ch$ 4 billion Enel Distribution received from the leasing of public lighting; and

(ii) Ch$ 81 billion in lower income tax payments in 2020, explained by (i) Ch$ 48.6 billion Enel Chile received in tax refunds from the recognition of tax losses; (ii) Ch$ 15.4 billion in lower Enel Distribution monthly tax payments; (iii) Ch$ 9.8 billion in lower Pehuenche monthly tax payments; and (iv) Ch$ 9.3 billion EGP Chile received in tax refunds from the recognition of tax losses.

These operating activity net cash flow increases were partially offset by:

(iii) Ch$ 92 billion in lower sales of goods and services, comprised mainly of:

i) Ch$ 100.5 billion from Enel Generation, mainly due to the non-recurrence of the 2019 early termination of electricity supply contracts with Anglo American for Ch$ 106.5 billion, partially offset by

ii) Ch$ 12.1 billion from Enel X Chile, mainly due to higher collections from the sale of energy-efficient products.

The effects of the Covid-19 pandemic led to a reduction in energy consumption during lockdown periods, which negatively impacted Chile’s economic activity and affected our collections. However, in December 2020, Enel Distribution Chile transferred collection rights from a portion of its trade receivables for the sale of energy to some customer segments for Ch$ 44.8 billion. See Note 9.a.2 of the Notes to our consolidated financial statements.

(iv) Ch$ 23 billion in lower insurance claims, mainly due to the non-recurrence of 2019 insurance claims of Ch$ 12.5 billion for Tarapacá and Ch$ 9.7 billion for Los Cóndores;

(v) Ch$ 17 billion in higher payments by Enel X Chile for manufacturing or acquiring assets leased to third parties and the acquisition of electric buses for leasing, and by Enel Distribution for the construction of public lighting to lease to municipalities;

(vi) Ch$ 16 billion in other payments for operating activities, primarily due to Ch$ 10.5 billion in higher VAT payments by Enel X Chile and Ch$ 8.2 billion in higher green emissions tax payments by Enel Generation; and

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(vii) Ch$ 10 billion in higher payments to and on behalf of employees for operating activities, mainly by Enel Distribution for Ch$ 8.7 billion associated with remunerations and union agreements.

For the year ended December 31, 2019, net cash flow provided by operating activities increased Ch$ 8 billion, or 1.1%, compared to the same period in 2018. The increase was in part the result of:

(i) a decrease of Ch$ 52 billion in income tax payments during 2019, explained by Enel Generation’s lower income tax payments due to lower monthly and annual tax payments of Ch$ 82.8 billion and an increase of Ch$ 17.9 billion in tax refunds, offset by (i) Ch$ 45 billion of higher income tax payments by GasAtacama Chile due to tax refunds received in 2018 from the recognition of tax losses in Celta and monthly tax payments and (ii) Ch$ 5 billion of higher monthly tax payments by Enel Distribution;

(ii) an increase of Ch$ 21 billion in collections from insurance claims mainly due to insurance claims for Tarapacá for Ch$ 12.5 billion and Los Cóndores for Ch$ 9.7 billion; and

(iii) an increase of Ch$ 16 billion in collections from the sale of goods and services, comprised mainly of:

(i) an increase of Ch$ 7 billion in Enel Distribution, due to higher physical sales; and

(ii) an increase of Ch$ 6 billion in Enel X Chile.

These operating activity net cash flow increases were partially offset by:

(iv) an increase of Ch$ 17 billion in other payments for operating activities, due to higher VAT payments from EGP del Sur for new wind plants in operation since the second half of 2018;

(v) a decrease of Ch$ 22 billion in other collections from operating activities, due to the non-recurrence of a 2018 VAT refund, relating to the construction of the Cerro Pabellón project; and

(vi) an increase of Ch$ 40 billion in payments by Enel X Chile for electric buses to lease to third parties and Enel Distribution to construct public lighting to lease to local municipalities.

For further information regarding our operating results in 2020, 2019, and 2018, please see “Item 5. Operating and Financial Review and Prospects — A. Operating Results — 2. Analysis of Results of Operations for the Years Ended December 31, 2020 and 2019” and “— 3. Analysis of Results of Operations for the Years Ended December 31, 2019 and 2018.”

For the year ended December 31, 2020, net cash flows used in investing activities were outflows amounting to Ch$ 555 billion, representing an increase of 78% or Ch$ 243 billion, compared to the same period in 2019. The aggregate investment in 2020 was mainly explained by:

(i) Ch$ 515 billion in fixed assets investments carried out by our subsidiaries, mainly explained by Ch$ 282 billion by EGP Chile in developing renewable projects, Ch$ 140 billion by Enel Generation, mainly due to the construction of the Los Cóndores power plant, and Ch$ 93 billion by Enel Distribution to improve its networks; and

(ii) Ch$ 40 billion in investments in intangible assets, explained by Ch$ 18 billion by Enel Distribution, Ch$ 12 billion by EGP Chile, and Ch$ 9 billion by Enel Generation, mainly due to software purchases and concessions.

For the year ended December 31, 2019, net cash flows used in investing activities decreased 83% compared to the same period of 2018. The lower investment in 2019 was mainly due to the non-recurrence of the 2018 Reorganization completed on April 2, 2018, when we invested Ch$ 1,624 million related to our tender offer for our additional equity

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interest in Enel Generation, which was offset by net cash inflows in 2018 in the net collection from related companies of Ch$ 38.4 billion.

For the year ended December 31, 2020, net cash flows used in financing activities were Ch$ 128 billion compared to the cash flows used in financing activities of Ch$ 440 billion in 2019.

The aggregate cash payments associated with financing activities in 2020 were primarily due to:

(i) Ch$ 312 billion in dividend payments, of which Ch$ 187 billion was paid to Enel, our controlling shareholder;

(ii) Ch$ 151 billion in loan and bond payments (including Ch$ 119 billion by EGP Chile and Ch$ 32 billion by Enel Generation); and

(iii) Ch$ 139 billion in interest payments (Ch$ 58 billion paid by Enel Generation, Ch$ 24 billion paid by EGP Chile, and Ch$ 57 billion paid by Enel Chile), partially offset by

(iv) aggregate cash inflows from financing activities in 2020, primarily from a Ch$ 485 billion loan provided to Enel Chile by Enel Finance International N.V., a related company.

For the year ended December 31, 2019, net cash flows used in financing activities amounted to Ch$ 440 billion compared to the cash flows provided by financing activities of Ch$ 967 in 2018, mainly to finance the 2018 Reorganization.

The aggregate cash payments associated with financing activities in 2019 were primarily due to:

(i) Ch$ 315 billion in payments of loans and bonds (including Ch$ 214 billion by Enel Chile on a stand-alone basis related to the 2018 Reorganization, and Ch$ 70 billion by EGP Chile);

(ii) Ch$ 236 billion in dividend payments, of which Ch$ 134 billion was paid to Enel, our controlling shareholder; and

(iii) Ch$ 134 billion in interest payments (Ch$ 51 billion paid by Enel Generation, Ch$ 38 billion paid by EGP Chile, and Ch$ 45 billion paid by Enel Chile).

These payments were partially offset by aggregate cash inflows from financing activities in 2019, primarily from a loan of Ch$ 284 billion provided to Enel Chile by Enel Finance International N.V., an affiliated finance company.

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

We coordinate the overall financing strategy of our subsidiaries. However, our subsidiaries independently develop their capital expenditure plans and finance their capital expansion programs through internally generated funds, intercompany financings, or direct financings. In recent years, we have adopted a preference to incur debt at the parent company level in Enel Chile and to finance most of the obligations of our subsidiaries through intercompany loans. Among the advantages to this financing strategy is the mitigation of structural subordination risk arising from subsidiary debt, with its favorable consequences for us from the perspective of rating agency credit ratings. Furthermore, we as a holding company can frequently access liquidity from several sources on better terms and conditions than some of our subsidiaries. However, we have no legal obligations or other commitments to support our subsidiaries financially. For information regarding our commitments for capital expenditures, see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures and Divestitures” and our contractual obligations table set forth below under “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations.”

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As of December 31, 2020, our consolidated interest-bearing debt totaled Ch$ 2.9 trillion, including Ch$ 1.2 trillion in debt that EGP Chile and Enel Chile incurred with Enel Finance International N.V., and had the following maturity profile:

Maturity Profile of Our Consolidated Interest-Bearing Debt
2021	2022-2023	2024-2025	After 2025
(in billions of Ch$)
159	383	608	1,690

Our American Depositary Shares have been listed and traded on the NYSE since April 26, 2016. In the future, we may again tap the international equity capital markets (including SEC-registered ADS offerings). We also issued bonds in the United States (“Yankee Bonds”) in 2018 and may issue Yankee Bonds in the future depending on liquidity needs.

The following table lists the Yankee Bonds issued by us and the aggregate principal amount outstanding as of December 31, 2020:

				Aggregate Principal Amount
Issuer	Term	Maturity	Coupon	Issued	Outstanding
				(in millions of US$)
Enel Chile	10 years	June 2028	4.875%	1,000	1,000

The following table lists the Yankee Bonds issued by our subsidiary, Enel Generation, and the aggregate principal amount outstanding as of December 31, 2020:

					Aggregate Principal Amount
Issuer	Term	Maturity	Coupon		Issued	Outstanding
					(in millions of US$)
Enel Generation	10 years	April 2024	4.250%		400	400
Enel Generation(1)	30 years	February 2027	7.875%		230	206
Enel Generation(2)	40 years	February 2037	7.325%		220	71
Enel Generation(1)	100 years	February 2097	8.125%		200	40
Total			5.813%	(3)	1,050	717

(1) Enel Generation repurchased some of these bonds in 2001.

(2) Holders of the Enel Generation 7.325% Yankee Bonds due 2037 exercised a put option on February 1, 2009, for a total amount of US$ 149.2 million. The remaining US$ 70.8 million principal amount of the Yankee Bonds matures in February 2037.

(3) Weighted-average coupon by outstanding amount.

We also have access to the Chilean domestic capital markets. Our subsidiary, Enel Generation, has issued debt instruments that have been primarily sold to Chilean pension funds, life insurance companies, and other institutional investors.

The following table lists UF-denominated Chilean bonds issued by Enel Generation that are outstanding on December 31, 2020:

			Coupon (inflation		Aggregate Principal Amount
Issuer	Term	Maturity	adjusted rate)		Issued	Outstanding
					(in millions of UF)	(in millions of UF)	(in billions of Ch$)
Enel Generation Series H	25 years	October 2028	6.20%		4.00	1.71	49.77
Enel Generation Series M	21 years	December 2029	4.75%		10.00	8.18	237.85
Total			5.00%	(1)	14.00	9.89	287.62

(1) Weighted-average coupon by outstanding amount.

For a complete description of local bonds issued by Enel Generation, see “Unsecured liabilities detailed by currency and maturity” in Note 21.2 of the Notes to our consolidated financial statements.

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We may also participate in the international and local commercial bank markets through syndicated or bilateral senior unsecured loans, including fixed-term and revolving credit facilities. In 2020, we entered into a bilateral revolving loan for up to US$ 290 million with Enel Finance International N.V. The amounts outstanding or available under our syndicated and revolving loans as of December 31, 2020, are summarized in the table below.

Borrower	Type	Maturity	Facility Amount	Amount Drawn
			(in millions of US$)	(in millions of US$)
Enel Chile	Syndicated Revolving Loan	June 2024	100	—
Enel Chile	Bilateral Revolving Loan	June 2024	50	—
Enel Chile	Bilateral Revolving Loan	June 2021	290	—
Total			440	—

The syndicated revolving credit facilities are governed by the laws of the State of New York. The disbursement is not subject to the compliance of conditions precedent regarding the non-occurrence of a “Material Adverse Effect” (or MAE, as defined contractually), thus allowing us complete flexibility for a drawdown, under any circumstances including situations involving an MAE, for up to US$ 440 million as of December 31, 2020, and were undrawn as of March 31, 2021.

We may also borrow from banks in Chile under fully committed facilities, under which a potential MAE would not impede this source of liquidity. In 2019, Enel Chile entered into a 5-year bilateral revolving loan for an aggregate amount of Ch$ 34,000 million, as outlined in the table below.

Borrower	Type	Maturity	Facility Amount	Amount Drawn
			(in millions of Ch$)	(in millions of Ch$)
Enel Chile	Syndicated Revolving Loan	June 2024	34,000	—

As a result, we have access to fully committed undrawn revolving loans, both international and domestic, for up to Ch$ 347 billion in the aggregate as of December 31, 2020, and as of March 31, 2021.

We and our subsidiaries also borrow routinely from uncommitted Chilean bank facilities with approved lines of credit for approximately Ch$ 48 billion in the aggregate, none of which are currently drawn. Unlike the committed lines described above, which are not subject to an MAE condition precedent to disbursements, these facilities are subject to a greater risk of not being disbursed in the event of an MAE. Our liquidity could be limited under such circumstances.

On December 21, 2018, we entered into a 4-year revolving credit line with Enel Finance International N.V. for up to US$ 400 million. This loan was drawn entirely in June 2019 and became a bilateral term loan with maturity in December 2022. Additionally, on January 3, 2020, we entered into a loan agreement with Enel Finance International N.V. for a US dollar-denominated loan for a total of US$ 200 million, with a maturity in July 2023. On March 11, 2020, we entered into a loan agreement with Enel Finance International N.V. for a US dollar-denominated loan of US$ 400 million, with a maturity in March 2030.

EGP Chile has also accessed the Chilean bank market through a bilateral loan agreement, which as of December 31, 2020, totaled US$ 150 million, with a final maturity in December 2021. EGP Chile also entered into a loan agreement with Enel Finance International N.V. for a US dollar-denominated loan, which as of December 31, 2020, had US$ 644 million outstanding, with a maturity in December 2027. EGP Chile also entered into subsidized financing with Interamerican Development Bank through a US dollar-denominated loan, which as of December 31, 2020, had US$ 30 million outstanding, with a maturity in November 2022.

In March 2018, we registered a 30-year local bond program with the CMF for UF 15 million (Ch$ 436 billion as of December 31, 2020). As of December 31, 2020, and as of the date of this Report, there have been no issuances of bonds under this program.

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Only Enel Generation’s outstanding debt facilities, except their Yankee Bonds, include financial covenants. The types of financial covenants, and their respective limits, vary from one kind of debt to another. As of December 31, 2020, the most restrictive financial covenant affecting Enel Generation was the debt-to-equity ratio in connection with the UF-denominated Chilean bonds. As of December 31, 2020, and as of the date of this Report, we comply with the financial covenants contained in our debt instruments.

As is customary for certain credit and capital market debt facilities, a significant portion of our financial indebtedness is subject to cross-default provisions. Each of the UF-denominated Chilean bonds described above, and Yankee Bonds issued by us and Enel Generation has cross default provisions with different definitions, criteria, materiality thresholds, and applicability as to the subsidiaries that could give rise to a cross-default.

Our subsidiaries’ debt may trigger the cross-default provision of our Yankee Bonds. A matured default of Enel Generation or any of its subsidiaries could result in a cross-default to the Yankee Bonds issued by Enel Generation and by us if such matured default, on an individual basis, has a principal exceeding certain materiality thresholds. Enel Generation’s subsidiaries do not currently have any financial obligations. In the case of a matured default above the materiality threshold, holders of Yankee Bonds would have the option to accelerate if either the trustee or bondholders representing at least 25% of the aggregate debt of a particular series then outstanding chose to do so. Enel Generation’s local bonds do not have cross-default provisions arising from its subsidiaries.

The UF-denominated Chilean bonds provide that the cross-default can be triggered only by default of the issuer itself, in cases where the amount in default exceeds US$ 50 million in individual debt or its equivalent in other currencies. However, the acceleration must be requested in a meeting of bondholders by at least 50% of the bondholders of the affected series.

The payment of dividends and distributions by our subsidiaries and affiliates represents an essential source of funds. The payment of dividends and distributions by certain subsidiaries and affiliates are potentially subject to legal restrictions, such as legal reserve requirements, capital and retained earnings criteria, and other contractual conditions. We are currently in compliance with the legal restrictions, and therefore, they now do not affect the payment of dividends or distributions to us. Certain credit facilities and investment agreements of our subsidiaries may restrict dividends or distributions in certain exceptional circumstances. For instance, one of Enel Generation’s UF-denominated Chilean bonds limits intercompany loans that Enel Generation and its subsidiaries can lend to related parties. The threshold for such aggregate restriction of intercompany loans is currently US$ 500 million. For a description of liquidity risks resulting from our company status, see “Item 3. Key Information — D. Risk Factors— We depend on payments from our subsidiaries to meet our payment obligations.”

Our estimated capital expenditures for 2021 through 2023 are expected to amount to Ch$ 1,674 billion, which includes maintenance capital expenditures, investment in expansion projects under execution, as well as water rights and expansion projects that are still under evaluation, in which case we would undertake them only if deemed profitable.

We do not currently anticipate liquidity shortfalls affecting our ability to satisfy the material obligations described in this Report. We expect to refinance our consolidated indebtedness as it becomes due, fund our purchase obligations with internally generated cash, and fund capital expenditures with a mixture of internally generated cash and borrowings.

LIBOR Transition

The U.K. Financial Conduct Authority found that the London Interbank Offered Rate (“LIBOR”) had inconsistencies in its calculations and recommended that it be based on actual transactions. As a result, the authority agreed to stop requiring banks to comply with the submission of interbank rates to calculate LIBOR as of December 31, 2021. On March 5, 2021, LIBOR succession dates (December 31, 2021, for EUR, CHF, JPY, and GBP LIBOR for all tenors and one week and two-month USD LIBOR and June 30, 2023, for all other USD LIBOR tenors) were announced. LIBOR will be discontinued, and alternative benchmark rates are expected to replace it. Currently, there is no clear opinion about the benchmark rate that will replace LIBOR. Still, market participants expect that a risk-free rate, such as the Secured Overnight Financing Rate (“SOFR”), a broad measure of the cost of borrowing overnight collateralized by U.S. Treasury securities, to replace it, in the context of operations involving U.S. banks.

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This reform may affect us in the following ways:

(vii) Interest payments on loans and derivatives: Financial risks arising from using a new benchmark rate, where interest payments previously based on LIBOR may increase or decrease. There is also a risk concerning data availability relating to the timely disclosure of market information, which may also affect the effectiveness of hedges.

(viii) Financial systems: Operational risk arising from the necessity to modify and adapt our financial systems to report, evaluate, or calculate payments under the new required benchmark rates.

(ix) Fair value measurement: Financial risks arising from how changes to benchmark rates in our debt obligations could adversely affect fair value measurements.

(x) Contracts: Legal and financial risk relating to the renegotiation of ISDA and local derivative contracts.

As of March 31, 2021, our total debt exposure to LIBOR was US$ 550 million. Although we have debt obligations that refer to LIBOR that expire after 2021, all of them include provisions to transition from LIBOR to an alternative benchmark rate. However, at this time, we cannot determine the extent these changes will affect us.

Enel Chile has intercompany debt obligations that stipulate that if LIBOR is not available, a replacement rate quoted by reference banks chosen by lenders that are leaders in the European interbank market for deposits in U.S. dollars and a period comparable to the corresponding interest period may be used. Under a line of credit, intragroup operations must be promptly determined at market conditions. The proposed new reference rates will probably differ from LIBOR.

In 2020, we executed a Revolving Credit Facility Agreement (“RFA”) for up to US$ 290 million with Enel Finance International N.V. that provides for a replacement rate for LIBOR quoted by reference banks chosen by lenders that are leaders in the European interbank market. As of March 31, 2021, the agreement was undrawn.

In 2019, we executed a Senior Unsecured Revolving Credit Agreement (“SURCA”) for up to US$ 100 million that includes specific language regarding the replacement of LIBOR for an alternative rate of interest that accounts for the prevailing market convention for determining a rate of interest for syndicated loans in the United States at that later time. We also executed an RFA for up to US$ 50 million with Enel Finance International N.V. that stipulates a replacement rate for LIBOR quoted by reference banks chosen by lenders that are leaders in the European interbank market. As of March 31, 2021, the SURCA and RFA were undrawn.

Additionally, we have a term loan for US$ 400 million from Enel Finance International N.V. that stipulates a replacement rate for LIBOR quoted by reference banks chosen by lenders that are leaders in the European interbank market.

Our subsidiary EGP Chile has a bank loan for US$ 150 million with specific clauses providing for an alternative specified rate to replace LIBOR as a result of the reforms under discussion in the United Kingdom as of the date of the contract. The loan is due before December 31, 2021.

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

None.

D. Trend Information.

Our subsidiaries engage in the generation, transmission, and distribution of electricity in Chile. These sectors experience more restrictive government regulations, the introduction of new technologies and business models, and more competition. Our businesses depend on a wide range of conditions that may result in significant variability in our

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earnings and cash flows from year to year. We seek to establish a conservative and well-balanced commercial policy aimed at controlling relevant variables, reducing risks, and providing stability to our results of operations.

Generation

Sales prices and energy costs are among the main drivers of our electricity generation business results. The quantity of electricity sold has been generally stable over time, with increases reflecting economic and demographic growth. Our profits from contracted sales rely on our ability to generate or buy electricity at a cost lower than contracted prices. However, the applicable price for electricity sales and purchases in the spot market is much harder to predict because the spot generation price is influenced by several factors, including hydrology and fuel prices. Abundant hydrological conditions generally lower spot prices while dry conditions increase them. However, NCRE generation may partly mitigate this effect on prices.

Our operating income might not be adversely impacted even when we must buy electricity at high prices in the spot market if our commercial policy is appropriately managed. Our goal is to have a conservative and well-balanced commercial policy that controls relevant variables, stabilizes our profits and mitigates our exposure to the spot market's volatility. We do so by contracting a significant portion of our expected electricity generation through long-term electricity supply contracts. The optimal level of electricity supply commitments protects us against low marginal cost conditions, such as those existing during a rainy season, while still taking advantage of high marginal cost conditions, such as higher spot market prices during dry years. To determine the optimal mix of long-term contracts and sales in the spot market, we project our aggregate generation considering our diversified generation mix and incorporating new projects under construction under dry hydrology. We then create demand estimates using standard economic theory and forecast the system’s marginal cost using proprietary stochastic models. We may also participate in the energy forward derivatives market, allowing us to negotiate volumes and future prices to ensure demand and avoid buying in the spot market, which has high volatility and risk.

Our sales contracts to customers not subject to regulated prices are not standardized, and the contractual terms and conditions are individually negotiated. When negotiating these contracts, we try to set the price at a premium over future expected spot prices to mitigate the risk of increases in future spot prices. However, the premium can vary substantially depending on several conditions such as node values, load profile, and the term of the contract. Our contracted sales with regulated customers represented approximately 50% of our sales in 2020, allowing us to maintain steady prices for more extended periods, typically 10 to 15 years, which, combined with our balanced commercial policy, generally provides a stable profit.

With the consolidation of EGP Chile as of April 2018, we added 1,189 MW of NCRE installed capacity. We expect that NCRE will boost growth in our generation business.

We expect the Los Cóndores hydro plant to be completed by 2023, adding an average of 600 GWh of annual generation to our consolidated generation capacity. In 2022 and 2024, we expect significant price decreases, mainly due to the start of operations of projects tendered in 2016 and 2017, respectively, including our Campos del Sol, Cerro Pabellón extension, and Renaico II projects.

In 2022, distribution company contracts awarded to Enel Generation in the auction of August 2016 will come into effect. Therefore, we expect the tariffs of our regulated agreements will decrease due to the lower prices offered by NCRE providers. In 2024, contracts awarded in the November 2017 auction will come into effect with an average price of the total allocated energy of US$ 32.5 per MWh, 32% lower than the average price of the previous tender process. The total amount of energy tendered was based on NCRE offers, representing a milestone in the industry. We were awarded 54% of the tender of 2,200 GWh per annum, corresponding to 1,180 GWh per annum at an average price of US$ 34.7 per MWh with a mix of wind, solar, and geothermal generation which will be provided through NCRE projects supported by conventional energy.

We regularly 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 projected new capacity and allow us to stabilize our income. Some of the latest long-term power purchase agreements awarded are with the mining companies BHP Billiton (for 3 TWh per annum), Collahuasi (1 TWh per

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annum), and Anglo American (3 TWh per annum). Considering the last two tenders' results for regulated customers, we expect increased competition in the NCRE market. As a result, offered prices may continue to decrease, but at a lower rate than previous years.

During the last few years, NCRE generation has grown much faster than expected, mainly due to the technological improvement in wind and solar technologies and the associated declining amount of capital required to deploy them. The government also established a regulated tender framework that allows the energy market to access this price reduction in the medium and long term. Currently, solar, wind and geothermal installed capacity represents approximately 23% of the total installed capacity in Chile, according to the monthly CEN report for December 2020. EGP Chile has a competitive pipeline of projects with a short time-to-market, which is possible because of commercial opportunities through PPA contracts.

With respect to the development of new projects to increase our installed capacity, our strategy focuses on creating synergies with plants in operation and obtaining economies of scale by combining existing plants with new NCRE projects to achieve greater competitiveness. We expect to continue competing in the future through PPA contracts, partly associated with the migration of regulated customers from the distribution business, mainly mining and large industries, who demand NCRE sources to reduce their energy costs and carbon footprint. The continuous addition of NCRE power plants to the grid will require further transmission network reinforcement and market flexibility and focus on operational efficiency to combine the different technologies while maintaining the security and the system’s supply reliability. Wind and solar sources are the most widely used NCRE sources. They have higher intermittency than other non-NCRE facilities because they can only generate electricity when the wind blows or the sun shines. Battery energy storage solutions will likely play a vital role in the next decade, providing a crucial solution for frequency control and grid stability in the context of significant wind and solar penetration.

Distribution

Distribution customers who can choose between regulated and unregulated tariffs continue to switch to unregulated tariffs, thereby becoming direct generation company customers and paying tolls to distribution companies. These customers tender their energy needs, either directly or in association with other customers, because unregulated tariffs are currently lower than regulated tariffs based on contracts previously tendered at higher prices. We expect this trend may continue in the future until lower-cost agreements are recognized in the regulated tariffs. Based on the latest tender processes, this difference in tariffs may last until 2024 with the recognition of the 2017 tendered prices in the regulated tariff.

We expect organic growth in the distribution business, mainly from the digitalization of the network. We plan to invest in new technologies that will automate our systems to achieve better operational and economic efficiency. New technology includes smart meters, which allow bi-directional communication, digitized and interconnected networks, and enable our consumers to improve their energy efficiency. We will continue investing in this technology since it will allow us to reduce costs in meter reading without an on-site inspection, remotely manage the disconnection and reconnection processes, and improve response times to better address extreme weather emergencies by significantly reducing failure recognition time. These instruments will also facilitate efficient maintenance and provide a necessary technical tool through which residential customers may inject their future excess energy into the electrical system.

Adverse Effects of the Covid-19 Pandemic

In February 2021, Chile began to implement a widespread vaccination program starting with a priority for the elderly, those with a greater health hazard, and those with greater exposure risk, such as those who work in health services. We expect that in 2021, the severe impact of Covid-19 will subside in relation to 2020 and anticipate a trend that at least partly reverses the negative consequences experienced last year. However, increases in infection rates as of March 2021 indicate a potential second wave of Covid-19. As a result, the Chilean government established new quarantine measures, placing more than 80% of the population in complete lockdown, including the entire Santiago metropolitan region. The government also announced the tightening of Chile’s borders through the month of April 2021. Chilean citizens and residents may enter Chile but are not allowed to depart from the country unless they qualify for exceptional consideration. Non-resident foreigners will not be allowed to enter Chile but will be permitted to depart from the country. We may also experience virus strains for which there are no known antibodies yet.

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Tariffs Stabilization Mechanism: Deferral of Electricity Distribution Tariffs

Due to the social crisis in October 2019, the Chilean government began implementing measures to address protesters’ social concerns. One of these measures established a mechanism for stabilizing electricity prices for regulated customers, the “Tariff Stabilization Mechanism.” It is related to Law No. 21,185 of the Ministry of Energy. The new law provides that regulated customer tariffs between July 1, 2019, and December 31, 2020, will remain at the levels prevailing as of June 30, 2019, and will not benefit from any indexation until December 31, 2020. This stabilized tariff is known as “Regulated Customer Stabilized Price” (“PEC” in its Spanish acronym).

From January 1, 2021, until the end of the Tariff Stabilization Mechanism, the tariffs will be those defined in the semi-annual decrees referred to in Article 158 of the Electricity Law but may not be higher than the PEC adjusted according to the consumer price index (the “adjusted PEC”). The difference between PEC or adjusted PEC and the rate that should have been charged under the applicable PPAs will create accounts receivable in favor of the generation companies. A price stabilization funding program was implemented by the CNE and is effectively financed by companies in the generation industry, including our subsidiary Enel Generation, through accounts receivable that are generated by the differences between the contractual rates and the stabilized rates, which are expected to enable the generation companies to recover the lost revenues by December 31, 2027. We may suffer a financial loss due to this revenue deferral because generation companies are being asked to finance such deferral. An agreement to sell up to US$ 290 million of the accounts receivables generated through this mechanism was executed with Goldman Sachs and the Inter-American Development Bank. Please see Note 9 of the Notes to our consolidated financial statements for further information.

The tariff deferral directly affects electricity generation companies by decreasing revenues, affecting their cash flows, and increasing the need to finance their operations. The maximum accounts receivable for the Tariff Stabilization Mechanism will be US$ 1,350 million, and the balance will be paid beginning July 1, 2023, through tariffs set above the PPA rates and must be collected no later than December 31, 2027. The regulator will issue semi-annual decrees that will identify the price of the contractual conditions of the PPAs, and the differences not collected under the PPAs, in their equivalent in U.S. dollars. These differences, in the form of accounts receivable, will not accrue interest, except that the balances not collected as of January 1, 2026, will accrue interest at the rate of six-month LIBOR, or the equivalent rate that replaces it, plus a spread corresponding to the country risk at the date of application.

Reduction of the Profitability of Distribution Companies

The Ministry of Energy’s Law No. 21,194, published on December 21, 2019, lowered distribution companies’ profitability by (i) reducing the rate of return allowed on investment costs from a 10% annual rate in real terms to a rate in the range of 6-8% per annum; and (ii) forcing the after-tax rate of return of distribution companies not to differ by more than two percentage points above and three percentage points below the rate defined by the CNE.

Voluntary Retirement Program

In April 2021, the Company announced a Voluntary Retirement Program, open to men of at least 60 and women of at least 55 years old, with an incentive for qualifying employees who voluntarily anticipate their retirement. The program is one of the initiatives that the Group is promoting in the context of its digitization strategy in 2021-2024, enabling the adoption of new work and operation models, and demands new skills and knowledge to make processes more efficient and effective at a time when the transformation of the Company’s platforms and business processes is becoming increasingly relevant to the Company’s clients and stakeholders. As a consequence of this restructuring plan, the Company will account for an expense of approximately Ch$ 17.5 billion in 2021.

E. Off-balance Sheet Arrangements.

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

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F. Tabular Disclosure of Contractual Obligations.

The table below sets forth our cash payment obligations as of December 31, 2020:

	Payments Due by Period
Ch$ billion	Total	2021	2022-2023	2024-2025	After 2025
Purchase obligations(1)	8,769	3,227	3,000	1,856	686
Interest expense	936	132	235	178	392
Yankee bonds	1,221	—	—	284	936
Local bonds(2)	270	30	61	54	125
Lease obligations	68	9	15	6	38
Pension and post-retirement obligations(3)	76	10	11	10	45
Bank debt(2)	1,297	107	448	229	513
Total contractual obligations	12,637	3,515	3,770	2,617	2,736

1) Includes generation and distribution business purchase obligations, comprised mainly of electricity purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of Ch$ 8,769 billion, 60% corresponds to electricity purchased for distribution, 18% primarily to fuel supply, maintenance of medium- and low-voltage lines, cable and utility poles, and electricity purchased for generation. The remaining 22% corresponds to miscellaneous services, such as LNG regasification, fuel transportation, and coal handling.

2) Represents net value, including derivatives.

3) Our pension and post-retirement benefit plans are unfunded. Cash flow estimates in the table are based on such obligations, including certain estimated variable factors such as interest. Cash flow estimates in the table relating to our unfunded plans are based on future discounted payments necessary to meet all of our pension and post-retirement obligations.

G. Safe Harbor.

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

Item 6.      Directors, Senior Management, and Employees

A. Directors and Senior Management.

Directors

Our board of directors consists of seven members elected for a three-year term at the Ordinary Shareholders’ Meeting (“OSM”). Following the end of their term, they may be re-elected or replaced. If a vacancy occurs in the interim, the board of directors will elect a temporary director to fill the vacancy until the next OSM, at which time the entire board of directors will be elected for new three-year terms. Our executive officers are appointed and hold office at the discretion of the board of directors.

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The members of our board of directors as of December 31, 2020, were as follows:

Directors	Position	Age(1)	Current Position Held Since
Herman Chadwick P.	Chairman	76	2016
Salvatore Bernabei	Director	47	2016
Pablo Cabrera G.	Director	73	2016
Daniele Caprini	Director	47	2018
Giulio Fazio	Director	50	2016
Fernán Gazmuri P.	Director	76	2016
Juan Gerardo Jofré M.	Director	71	2016

(1) As of April 30, 2021.

A new board of directors was elected at the OSM held on April 28, 2021, for a three-year term that ends in April 2024.

Set forth below are brief biographical descriptions of the members of our board of directors, three of whom reside outside Chile and four of whom live in Chile, as of December 31, 2020.

Herman Chadwick P.

Mr. Chadwick is a law partner at Chadwick & Cía. and a director of several companies unrelated to us, including Inversiones Aguas Metropolitanas, a Chilean holding company that owns a water utility company, Viña Santa Carolina, a Chilean winery, Centro de Estudios Públicos, a public policy think tank, and Carola, a mining company. Mr. Chadwick is chairman of the board and arbitrator at Centro de Arbitraje y Mediación de la Cámara de Comercio de Santiago, an association that provides arbitration services. He is also vice-chairman of Intervial Chile, a highway concession company. Mr. Chadwick holds a law degree from Pontificia Universidad Católica de Chile.

Salvatore Bernabei

Mr. Bernabei has been the head of global procurement of Enel since May 2017. He was head of renewable energy Latin America of Enel Green Power (2016-2017) and country manager for Chile and the Andean Countries (2013-2016). He joined Enel in 1999 and has held several positions in engineering, construction, operation & maintenance, safety environment and quality of life. Mr. Bernabei holds a degree in industrial engineering from Università degli Studi di Roma “Tor Vergata” and an MBA from Politecnico di Milano.

Pablo Cabrera G.

Mr. Cabrera is a member of the Sociedad Chilena de Derecho Internacional. Mr. Cabrera was director of Academia Diplomática Andrés Bello (2010-2014) and served concurrently as ambassador to the Holy See, the Sovereign Military Order of Malta and Albania (2006-2010), the People’s Republic of China (2004-2006), Russia and Ukraine (2000-2004) and the United Kingdom and Ireland (1999-2000). He also headed the Subsecretaría de Marina de Chile (1995-1999). Mr. Cabrera holds a law degree from Pontificia Universidad Católica de Chile and is a certified career diplomat from Academia Diplomática Andrés Bello.

Daniele Caprini

Mr. Caprini has been the head of Planning and Control for Enel SpA since 2018. He was the CFO of Enel Colombia (2016-2017). He headed Enel’s Financial Valuation and Investment Control (2013-2015) and Strategic Planning M&A and Financial Valuation (2009-2013) of Enel Green Power S.A. Mr. Caprini holds a degree in economics from the Università degli Studi di Siena and an MBA from Roma Università LUISS.

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Giulio Fazio

Mr. Fazio has been the head of Enel’s Legal and Corporate Affairs since January 2016. Previously he held a similar position at Enel Green Power S.p.A. (2008-2014). Since 2004, he has worked in finance and antitrust operations in Enel’s legal department. Mr. Fazio first joined an Enel affiliate in 1996. He holds a degree in law and a Ph.D. from Università degli Studi di Palermo.

Fernán Gazmuri P.

Mr. Gazmuri has served on the boards of companies unrelated to us. He is currently vice-chairman of Invexans S.A., a holding company that owns NEXANS, a French telecom and maritime cable company, and chairman of Citroën Chile S.A.C. He has been chairman of the Asociación Chilena de Seguridad and vice-chairman of the Sociedad de Fomento Fabril. From 2013-2016, he was director of Empresa Nacional del Petróleo, the Chilean state-owned oil company. He was vice-chairman of the International Chamber of Commerce of Chile from 2005-2009. In 2016, Mr. Gazmuri was awarded the Jorge Alessandri Rodríguez distinction by the Asociación de Industriales Metalúrgicos y Metalmecánicos, due to his outstanding professional and business career. In 2014, Mr. Gazmuri was awarded the Ordre national du Mérite by the Republic of France. He holds a degree in business administration from Pontificia Universidad Católica de Chile.

Juan Gerardo Jofré M.

Mr. Jofré is a director of CAP S.A., a mining and steel company, and a member of the self-regulatory council of the Asociación de Aseguradores de Chile, the insurance companies association. From 2010-2014, he was chairman of the board of Codelco, the Chilean state-owned copper mining company. He has been a director of Enel Generation and several unrelated companies, including Latam Airlines S.A., D&S S.A., Viña San Pedro S.A. and Sociedad Química y Minera de Chile, S.A., Banco Santander Chile, among others. He has held several managerial positions, primarily with Santander Chile Group. He holds a degree in business administration from Pontificia Universidad Católica de Chile.

Executive Officers 

Set forth below are our executive officers as of December 31, 2020:

Executive Officers	Position	Age(1)	Joined Enel or Affiliate in	Current Position Held Since
Paolo Pallotti	Chief Executive Officer	58	1990	2018
Giuseppe Turchiarelli	Chief Financial Officer	50	1998	2019
Eugenio Belinchon	Internal Audit Officer	44	1998	2020
Liliana Schnaidt H.	Human Resources Officer	41	2009	2018
Domingo Valdés P.	General Counsel	57	1993	2016

(1) As of April 28, 2021.

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

Paolo Pallotti: Mr. Pallotti was the CFO of Enel Américas until 2018. He played a crucial role in various Enel corporate reorganization processes. He served as CFO of Enel’s Italian businesses (2014-2018), financial director of Enel’s Infrastructure & Networks division (2012), and director of Enel Energia S.p.A. (2015-2018) and Enel Italia S.r.L (2017-2018). He holds a degree in electronic engineering from Università degli Studi di Ancona.

Giuseppe Turchiarelli: Mr. Turchiarelli has held prominent financial positions in Enel since 1998, among which he served as CFO of Enel Latin America BV (2009-2011), CFO for renewable generation in Italy and Europe (2001-2012), head of Planning and Control of the Enel Green Power group (2012-2013), CFO for Iberia and Latin America (2013-2015), head of Planning and Control in Italy (2015-2017), and CFO for Europe and North Africa (2017-2019). He holds a degree in business administration from Università degli Studi di Cagliari and an executive MBA from LUISS Business School.

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Eugenio Belinchon: Mr. Belinchon has held various responsibilities in the Internal Audit function for Enel in Europe and Latin America since 1998. He served as head of Enterprise Risk Management for the Iberia-Latam region (2009-2013). In 2014, he returned to Internal Audit, serving in different capacities at the Latin American level. He served as an audit manager and compliance officer in Colombia (2016-2019). He holds a degree in economics from Complutense University, an executive MBA from Instituto de Empresa.

Liliana Schnaidt H.: Ms. Schnaidt held positions in Enel Green Power business development, focusing on solar energy (2009-2018). She holds a degree in civil engineering from Pontificia Universidad Católica de Chile.

Domingo Valdés P.: Mr. Valdés is the general counsel of Legal and Corporate Affairs for both Enel Américas and Enel Chile and serves as secretary of both their boards of directors. He is a tenured professor of economic and antitrust law at Universidad de Chile and graduated summa cum laude from its law school. Mr. Valdés also holds an LL.M. from the University of Chicago.

B. Compensation.

At the OSM held on April 28, 2021, our shareholders approved our board of directors’ compensation policy. Director compensation consists of a monthly fixed compensation of UF 216 per month and an additional fee of UF 79.2 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings, within the respective fiscal year. The chairman of the board is entitled to double the compensation of other directors.

Our Directors Committee members are paid a monthly fixed compensation of UF 72 per month and an additional fee of UF 26.4 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings.

If a director serves on one or more boards of directors of the subsidiaries or associate companies or serves as director of other companies or corporations where the group holds an interest directly or indirectly, the director can only receive compensation from one of these boards.

Our Company’s, subsidiaries’, or affiliates’ executive officers will not receive compensation if they serve as directors of any other affiliate. However, the officer may receive compensation to the extent that it is expressly and previously authorized as an advance payment of the variable portion of the wage to be paid by the affiliate with which the officer signed a contract.

In 2020, the total compensation paid to each of our directors, including fees for attending Directors Committee meetings, was as follows:

Director	Fixed Compensation	Ordinary and Extraordinary Session	Directors Committee (Fixed Compensation)	Ordinary and Extraordinary Session (Directors Committee)	Variable Compensation	Total
	(in ThCh$)
Herman Chadwick P.	148,808	59,109	—	—	—	207,918
Salvatore Bernabei(1)	—	—	—	—	—	—
Pablo Cabrera G.	74,404	29,555	24,801	9,852	—	138,612
Daniele Caprini(1)	—	—	—	—	—	—
Giulio Fazio(1)	—	—	—	—	—	—
Fernán Gazmuri P.	74,404	29,555	24,801	9,852	—	138,612
Juan Gerardo Jofré M.	74,404	29,555	24,801	9,852	—	138,612
Total	372,021	147,774	74,404	29,555	—	623,753

(1) Messrs. Bernabei, Caprini, and Fazio waived their compensation as directors of the Company due to their positions as employees of other companies in Enel.

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We do not disclose any information about an individual executive officer’s compensation. Executive officers are eligible for variable compensation under a bonus plan. The yearly bonus plan is paid to our executive officers for achieving company-wide objectives and for their contribution to our results and goals. The annual bonus plan provides a range of bonus amounts according to seniority level and consists of a certain multiple of gross monthly salaries. For the year ended December 31, 2020, the aggregate gross compensation, paid and accrued, for all of our executive officers, attributable to the fiscal year 2020, was Ch$ 2.6 billion, including Ch$ 419 million in variable compensation and benefits.

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

We did not pay severance indemnity to our executive officers in 2020. There are no other amounts set aside or accrued to provide for pension, retirement or similar benefits for our executive officers.

C. Board Practices.

Our current board of directors was elected at the OSM held on April 28, 2021, for three years. For information about the directors in office as of December 31, 2020, and the year they began their service on the board of directors, see “Item 6. Directors, Senior Management and Employees — A. Directors and Senior Management” above. Members of the board of directors do not have service contracts with us or with any of our subsidiaries that provide them benefits upon the termination of their service.

Corporate Governance

We are managed by a board of directors, following our bylaws, consisting of seven directors elected by our shareholders at the OSM, each serving for a three-year term. Following the end of their terms, they may be re-elected indefinitely or replaced. Staggered terms are not permitted under Chilean law. If a vacancy occurs on the board of directors during the three-year term, the board of directors may appoint a temporary director to fill the vacancy. A vacancy triggers an election for every seat on the board of directors at the next OSM.

Chilean corporate law provides that a company’s board of directors is responsible for managing and representing a company in all matters concerning its corporate purpose, subject to its bylaws’ provisions of , and the shareholders’ resolutions. In addition to the bylaws, our board of directors has adopted regulations and policies that guide our corporate governance principles.

Our corporate governance policies are mainly included in the following policies or procedures: the Manual for the Management of Information of Interest to the Market (the “Manual”), the Human Rights Policy (Política de Derechos Humanos), the Code of Ethics, the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Penal Risk Prevention Model, the Enel Global Compliance Program on Corporate Criminal Liability (the “Enel Global Compliance Program”), the Risk Management and Control System, and procedures issued in compliance with General Norm Regulation 385 (“NCG 385” in its Spanish Acronym), issued by the CMF, which deals with corporate governance matters.

To ensure compliance with Securities Market Law 18,045 and CMF regulations, our board of directors approved the Manual at its meeting held on February 29, 2016. It ratified such decision at its meeting held on March 23, 2016. This document addresses applicable standards regarding the information in connection with transactions of our securities and those of our affiliates, entered into by directors, management, principal executives, employees, and other related parties, the existence of blackout periods for such transactions undertaken by directors, principal executives and other related parties, the presence of mechanisms for the continuous disclosure of information that is of interest to the market and tools that protect confidential information. The Manual is posted on our website at www.enelchile.cl. The provisions of this Manual apply to our board members and our executives and employees who have access to confidential information, especially those who work in areas related to the securities markets.

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Our board of directors approved a procedure for relationships between Politically Exposed People (Procedimiento Personas Políticamente Expuestas y Conexas) and our Company, which established a specific regulation for their commercial and contractual relationships. The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into corporate reality.

Our board of directors also approved the Code of Ethics and the ZTAC Plan to supplement the aforementioned corporate governance regulations. The Code of Ethics is based on general principles such as impartiality, honesty, integrity, and other ethical standards of equal importance, all of which are expected from our employees. The ZTAC Plan reinforces the Code of Ethics principles, emphasizing avoiding corruption through bribes, preferential treatment, and other similar matters.

Our board of directors approved the Penal Risk Prevention Model and the Enel Global Compliance Program. The Penal Risk Prevention Model satisfies the standards imposed by Chilean Law 20,393, which imposes criminal responsibility for legal entities for certain crimes, including money laundering, financing of terrorism, and bribery of public officials. The law encourages companies to adopt this model, whose implementation involves compliance with managerial and supervision duties. The adoption of the Penal Risk Prevention Model mitigates, and in some cases relieves, the effects of criminal responsibility even when a crime is committed. In turn, the Enel Global Compliance Program is designed as a tool to reinforce the group’s commitment to the highest ethical, legal, and professional standards for enhancing and preserving the group’s reputation. It sets several preventive measures for corporate criminal liability.

We follow the Risk Management and Control System guidelines defined by Enel for the standards, procedures, and systems applied at different levels of our companies to identify, analyze, evaluate, manage, and communicate risks.  Each of our companies defines its risk management, control, and management policy, which is reviewed and approved at the beginning of each year by its Board of Directors, observing and applying local requirements in terms of risk culture, specific procedures concerning certain risks, corporate functions, or group businesses. The policies include limits and indicators that are subsequently monitored. 

The Risk Control area is ISO 31000:2018 (G31000) certified and acts under the guidelines of these international standards. The primary objective is to identify internal and external risks preemptively and to analyze, evaluate, and quantify the probability of their occurrence and impact on our companies. Each area manages risks using mitigation measures stipulated in action plans. In the risk management phase, necessary actions determined by internal policies and procedures are considered. The strict observance of ISO and OHSAS international standards and governmental regulations may require risk management actions to be documented to guarantee good governance practices and ensure business continuity.

In 2015, the CMF issued NCG 385 to enhance transparency standards and introduce corporate social responsibility practices by promoting, among other things, management diversity. All publicly held limited liability corporations are required to provide the CMF, on an annual basis, with answers to a survey related to the board’s functions and composition; relationships between the company, shareholders and public in general; third-party assessments; and internal control and risk management. The Appendix of NCG 385 is divided into the following four sections concerning which companies must report the corporate practices that have been adopted: (i) the functioning and composition of the board, (ii) relations between the company, shareholders and the general public, (iii) risk management and control, and (iv) assessment by a third party. Publicly held limited liability corporations should send the information concerning corporate governance practices to the CMF, no later than March 31 every year, using the Appendix’s contents to this regulation as criteria. If none of them is adopted, the company must explain its reasons to the CMF. The information should refer to December 31 of the calendar year that just ended. Simultaneously, such information should also be at the public’s disposal on the company’s website and must be sent to the stock exchanges.

In 2018, the board of directors approved a policy dealing with environmental and biodiversity issues. Environmental, social, and corporate governance criteria (“ESG”) are integrated into our business model. In compliance with NCG 385, the board periodically receives reports by management to identify and assess of all risks associated with ESG and climate change issues, including compliance with board policies.

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Compliance with the New York Stock Exchange Listing Standards on Corporate Governance

The following summarizes the significant differences between our corporate governance practices and those applicable to U.S. domestic issuers under the NYSE’s corporate governance rules.

Independence and Functions of the Directors Committee (Audit Committee)

Chilean law requires that at least two-thirds of the Directors Committee be independent directors. The CMF may, by a general norms’ regulation, set forth the requirements and conditions that must be met by board members to be independent directors. Notwithstanding the above, according to Article 50 bis of Law No. 18,046, a member would not be considered independent if, at any time, within the last 18 months he: (i) had any relationship of a relevant nature and amount with the company, with other companies of the same group, with its controlling shareholder, or with the principal officers of any of them or has been a director, manager, administrator, or officer of any of them (being the CMF authorized to set forth the criteria of what will be deemed “relevant nature and amount”); (ii) had a family relationship with any of the members described in (i) above; (iii) has been a director, manager, administrator or principal officer of a non-profit organization that has received contributions from (i) above; (iv) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of an entity that has provided consulting or legal services for a relevant consideration or external audit services to the persons listed in (i) above; and (v) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator, or principal officer of the top competitors, suppliers, or customers. In case there are not enough independent directors on the board to serve on the Directors Committee, Chilean law determines that the independent director nominates the rest of the Directors Committee members among the remaining board members that do not meet the Chilean law independence requirements. Chilean law also requires that all publicly held limited liability stock corporations that have a market capitalization of at least UF 1.5 million (Ch$ 43.6 billion as of December 31, 2020) and at least 12.5% of its voting shares are held by shareholders that individually control or own less than 10% of such shares, must have at least one independent director and a Directors Committee.

Under the NYSE corporate governance rules, all members of the Audit Committee must be independent. The Audit Committee of a U.S. company must perform the functions detailed in, and otherwise comply with, the requirements of NYSE Listed Company Manual Rules 303A.06 and 303A.07. As of July 31, 2005, non-U.S. companies have been required to comply with Rule 303A.06, but not with Rule 303A.07. Since our incorporation on March 1, 2016, we have complied with the independence and the functional requirement of Rule 303A.06.

Under our bylaws, all Directors Committee members must satisfy the requirements of independence, as stipulated by the NYSE. The Directors Committee comprises three members of the board. It complies with Article 50 bis of Law No. 18,046 and the criteria and requirements of independence prescribed by the Sarbanes-Oxley Act (“SOX”), the SEC, and the NYSE. As of this Report date, the Directors Committee complies with the Audit Committee’s conditions as required by the SOX, the SEC, and the NYSE corporate governance rules. As a result, we have a single Committee, the Directors Committee, which includes the duties performed by an Audit Committee among its functions.

Our Directors Committee performs the following functions:

● reviews of financial statements and the reports of the external auditors before their submission for shareholders’ approval;

● presents proposals to the board of directors, who then undertake their recommendations to shareholders meetings, for the selection of external auditors and private rating agencies;

● reviews information related to our transactions with related parties and reports the opinion of the Directors Committee to the board of directors;

● proposes to the board of directors a general policy on conflicts of interests, as well as reviews the related-party policy;

● examines the compensation framework and plans for managers, executive officers, and employees;

● prepares an Annual Management Report, including recommendations to shareholders;

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● provides information to the board of directors about the convenience of recruiting external auditors to provide non-auditing services, when such services are not prohibited by law, depending on whether such services might affect the external auditors’ independence;

● oversees the work of external auditors;

● reviews and approves of the annual auditing plan by the external auditors;

● evaluates the qualifications, independence, and quality of the auditing services;

● elaborates policies regarding the employment of former members of the external auditing firm;

● reviews and discusses problems or disagreements between management and external auditors regarding the auditing process;

● establishes procedures for receiving and dealing with complaints regarding accounting, internal controls, and auditing matters;

● carries out other functions mandated to the Committee by the bylaws, our board of directors, or our shareholders.

Corporate Governance Guidelines

The NYSE’s corporate governance rules require U.S.-listed companies to adopt and disclose corporate governance guidelines. Chilean law provides for this practice through the procedures related to NCG 385 and the Manual. We have also adopted the Code of Ethics. Our bylaws include provisions that govern the creation, composition, attributions, functions, and compensation of the Directors Committee described above, including among its functions the duties performed by an Audit Committee.

D. Employees.

The following table sets forth the total number of our personnel (permanent and temporary employees) in Enel Chile and our subsidiaries as of December 31, 2020, 2019, and 2018:

Company	2020	2019	2018
Enel Distribution(1)	755	733	681
Enel Generation(2)	668	700	678
Enel Chile	494	480	451
EGP Chile(3)	285	212	163
Enel X	15	6	—
Pehuenche	2	2	2
GasAtacama(2)	—	—	87
Total Personnel(4)	2,219	2,133	2,062

(1) Includes Enel Colina S.A.

(2) GasAtacama S.A. and GasAtacama merged into Enel Generation in October 2019.

(3) We have consolidated EGP Chile and its subsidiaries since April 2, 2018.

(4) The total number of temporary employees was not significant.

The Chilean Labor Code entitles all employees in Chile who are fired for reasons other than misconduct to a severance indemnity payment. In most cases, contracted employees are entitled to a legal minimum severance indemnity payment of one month’s salary for each year (and every fraction thereof beyond six months) worked, subject to a maximum of 11 months’ salary.

Our employment contracts typically provide severance indemnity payments higher than those required by the Chilean Labor Code. In most cases, we respect seniority as the time that the employee first joined us or an affiliate. Therefore, employees hired by one of our Chilean affiliates or predecessor companies maintain their seniority in the company and are treated contractually as if we had hired them. Under such employment contracts, severance indemnity payments for most of our employees consist of one month’s salary for each full year worked (and every fraction thereof beyond six months), subject to a maximum of 25 months. Under our collective bargaining agreements and other employment contracts not covered by such agreements, we are typically obligated to make severance indemnity

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payments to all covered employees in cases of voluntary resignation or death in specified amounts that increase according to seniority and often exceed the amounts required under Chilean law.

We have the following collective bargaining agreements:

	In Force
Company	From	To
Enel Chile - Collective Bargaining Agreement 1	July 2019	July 2022
Enel Chile - Collective Bargaining Agreement 2	January 2020	December 2022
Enel Chile - Collective Bargaining Agreement 3(1)	January 2020	December 2022
Enel Generation - Collective Bargaining Agreement 1	July 2020	June 2023
Enel Generation - Collective Bargaining Agreement 2	July 2020	June 2023
Enel Generation - Collective Bargaining Agreement 3	January 2021	December 2023
Enel Generation - Collective Bargaining Agreement 4	July 2019	June 2022
Enel Distribution - Collective Bargaining Agreement 1	January 2021	December 2023
Enel Distribution - Collective Bargaining Agreement 2	January 2021	December 2023
Enel Distribution - Collective Bargaining Agreement 3	January 2021	December 2023
EGP Chile - Collective Bargaining Agreement 1	October 2020	September 2023
EGP Chile (Panguipulli) - Collective Bargaining Agreement 2	January 2021	December 2023
Enel Colina	November 2019	October 2022
GasAtacama Chile	January 2021	December 2023

(1) This collective bargaining agreement was transferred from ICT Servicios Informáticos Ltda., a former subsidiary that merged into us.

E. Share Ownership.

To the best of our knowledge, none of our directors or officers owns more than 0.1% of our shares or holds any stock options. It is not possible to confirm whether any of our directors or officers has a beneficial, rather than direct, interest in our shares. Any share ownership by all our directors and officers amounts to significantly less than 10% of our outstanding shares.

Item 7.      Major Shareholders and Related-Party Transactions

A. Major Shareholders.

We have one class of capital stock, and Enel, our controlling shareholder, has the same voting rights as our other shareholders. As of December 31, 2020, 6,298 shareholders of record held 69,166,557,220 shares of our outstanding common stock. Enel owned 44,334,165,152 common shares and 11,457,799 ADS equivalent to 572,889,949 shares, aggregating a 64.9% ownership interest in us. There were five record holders of our ADS, as of such date.

It is not practicable for us to determine the number of our ADS or our common shares beneficially owned in the United States. The depositary for our ADS only registers the record holders, including the Depositary Trust Company and its nominees. As a result, we are not able to ascertain the domicile of the ultimate beneficial holders represented by the five ADS record holders in the United States, nor are we able to determine the domicile of any of our foreign shareholders who hold our common stock, either directly or indirectly.

As of December 31, 2020, Chilean private pension funds (“AFPs”) owned 14.2% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 16.8% of our shares. ADR holders owned 3.0% of our shares, and 6,137 minority shareholders held the remaining 1.1% of our shares.

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The following table sets forth information concerning ownership of the common stock as of December 31, 2020, for the only stockholder known by us to own more than 5% of the outstanding shares of common stock:

	Number of Shares Owned	Percentage of Shares Outstanding
Enel S.p.A. (Italy)	44,907,055,101	64.9%

Enel, our ultimate controlling shareholder, 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.

B. Related-Party Transactions.

Article 146 of Law No. 18,046 (the “Chilean Corporations Law”) defines related-party transactions as those involving a company and any entity belonging to the corporate group, its parent companies, controlling companies, subsidiaries or related companies, board members, managers, administrators, senior officers or company liquidators, including their spouses, some of their relatives, and all entities controlled by them, in addition to individuals who may appoint at least one member of the company’s board of directors or who hold 10% or more of voting capital, or companies in which a board member, manager, administrator, senior officer or company liquidator has been serving in the same position within the last 18 months.

Article 147 of the Chilean Corporation Law (“Article 147”) requires that related-party transactions must consider the corporate interest, as well as the prices, terms, and conditions prevailing in the market at the time of their approval. Article 147 provides that board members, managers, administrators, senior officers, or company liquidators having a personal interest or acting on negotiations of a related-party transaction must immediately inform the board of directors. Such a transaction shall only be approved if an absolute majority of the directors (excluding interested directors) consider the transaction beneficial for the corporate interest. Chilean law requires an interested director to abstain from voting on such a transaction. If an absolute majority of the directors are obliged to abstain from voting on any particular transaction, it shall only be approved if authorized unanimously by the independent directors or during an ESM. Board resolutions approving related-party transactions must be reported to the company’s shareholders at the next shareholders’ meeting.

The law described above, which also applies to our affiliates, provides for some exceptions. In some instances, the board’s approval would suffice for related-party transactions, under certain transaction thresholds when the transactions are conducted with another entity in which we hold 95% or more of their capital, or when such transactions are conducted in compliance with the related-party policies defined by the company’s board. At its meeting held on July 30, 2019, our board of directors updated our related-party transaction policy. This policy is available on our website at www.enelchile.cl.

If a transaction is not in compliance with Article 147, this will not affect its validity. Still, our shareholders or we may demand compensation for damages from the individual associated with the infringement as provided by law.

Our internal procedure contemplates that all our subsidiaries’ cash inflows and outflows are managed through a centralized cash management mechanism. It is common practice in Chile to transfer surplus funds from one company to another affiliate that has a cash deficit. These transfers are executed through either short-term transactions or structured inter-company loans. Under Chilean laws and regulations, such transactions must be conducted on an arms-length basis. All of these transactions are subject to the supervision of our Directors Committee. As of April 1, 2021, the peso-denominated transactions were priced at TAB 1m (a Chilean interbank interest rate published daily) plus 1.44% when

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lending to affiliates and TAB 1m plus 0.01% when accepting deposits of cash surpluses from affiliates. The US$-denominated transactions were priced at LIBOR 1m plus 1.72% when lending to affiliates and LIBOR 1m plus 0.28% when accepting deposits of cash surpluses from affiliates.

The following are related-party transactions conducted between January 1, 2020, and April 1, 2021.

● On January 3, 2020, we entered into and drew down a US$-denominated term loan with Enel Finance International N.V. for US$ 200 million at a fixed annual interest rate of 2.60%. As of April 1, 2021, the outstanding balance of the loan was US$ 200 million.

● On March 11, 2020, we signed a US$-denominated term loan with Enel Finance International N.V. for US$ 400 million at a fixed annual interest rate of 3.30%. As of April 1, 2021, the outstanding balance of the loan was US$ 400 million.

● On June 8, 2020, we signed a US$-denominated fixed-term revolving credit line with Enel Finance International N.V. for US$ 290 million at a variable rate of LIBOR plus 1.40%. As of April 1, 2021, the credit line was terminated.

● On January 1, 2021, we granted a Ch$-denominated term loan to our subsidiary Enel Transmission Chile for Ch$ 42.1 billion at a fixed annual interest rate of 3.20%. As of April 1, 2021, the outstanding balance of the loan was Ch$ 42.1 billion.

● On February 10, 2021, we granted a US$-denominated term loan to our subsidiary EGP Chile for US$ 200 million at a fixed annual interest rate of 2.88%. As of April 1, 2021, the outstanding balance of the loan was US$ 200 million.

● On April 1, 2021, we signed a Sustainable Development Goals (SDGs)-linked US$-denominated revolving facility agreement with Enel Finance International N.V. for US$ 290 million at a variable rate of LIBOR plus 1.00%. As of April 1, 2021, the credit line was undrawn.

● On April 1, 2021, we signed a Sustainable Development Goals (SDGs)-linked US$-denominated loan facility agreement with Enel Finance International N.V. for US$ 300 million at a fixed annual interest rate of 2.5%. As of April 1, 2021, the outstanding balance of the loan was US$ 300 million.

● We granted short-term intercompany loans to our subsidiaries Almeyda Solar SpA, EGP Chile, Enel Colina, Enel Distribution, Enel Transmission, Geotérmica del Norte S.A., and Sociedad Agrícola De Cameros Ltda. As of April 1, 2021, the total outstanding balance of the loans was Ch$ 227 billion.

● Under our cash management contracts, Enel Generation, Enel X Chile, Empresa de Transmisión Chena S.A., Parque Talinay Oriente S.A, and Pehuenche all transferred cash surpluses to us. As of April 1, 2021, the total outstanding balance of these transfers was Ch$ 303 billion.

All these aforementioned intercompany cash flows help meet the working capital needs of our subsidiaries.

We have various contractual relationships with Enel Generation, Enel Distribution, Enel X Chile, and EGP Chile to provide-intercompany services. We entered into intercompany agreements under which we provide services directly and indirectly to Enel Generation and its subsidiaries, Enel Distribution and its subsidiaries, and our other subsidiaries. The services to be rendered by us include specific legal, finance, treasury, insurance, capital markets, financial and documentary compliance, accounting, human resources, communications, security, relations with contractors, purchases, IT, tax, corporate affairs, and other corporate support and administrative services. The services rendered vary depending on the company receiving the service. These services are provided and charged at market prices if there is a comparable reference service. If there are no similar services in the market, they will be provided at cost plus a specified percentage. The intercompany services contracts are valid for five years, with renewable terms as of January 1, 2017.

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The 2018 Reorganization consolidated Enel’s conventional and non-conventional renewable energy businesses in Chile. Under Chilean law, the 2018 Reorganization was deemed a related-party transaction, subject to the statutory requirements and protections of the Title XVI of the Chilean Corporations Law. For additional information on the 2018 Reorganization, see “Item 4. Information on the Company — A. History and Development of the Company — The 2018 Reorganization.”

As of the date of this Report, the transactions above have not experienced material changes. As of December 31, 2020, there were some commercial transactions with related parties. Please see Note 13 of the Notes to our consolidated financial statements for more information regarding related-party transactions.

C. Interests of Experts and Counsel.

Not applicable.

Item 8. Financial Information.

A. Consolidated Statements and Other Financial Information.

See “Item 18. Financial Statements.”

Legal Proceedings

Our subsidiaries and we are parties to legal proceedings arising in the ordinary course of business. We believe it is unlikely that any loss associated with pending lawsuits will significantly affect the normal development of our business.

Please refer to Note 36.3 of the Notes to our consolidated financial statements for detailed information as of December 31, 2020, on the status of the pending material lawsuits filed against us.

Concerning the legal proceedings reported in the Notes to our consolidated financial statements, we use the criterion of disclosing lawsuits above a minimum threshold of US$ 10 million of potential impact to us, and, in some cases, qualitative criteria according to the materiality of the plausible effect on the conduct of our business. The lawsuit status includes a general description, the process status, and the estimate of the amount involved in each lawsuit.

Dividend Policy

Our board of directors presents an annual proposal for approval to the OSM for a final dividend payable each year. The dividend is accrued in the prior year and cannot be less than the legal minimum of 30% of annual net income. Our board of directors also informs the dividend policy for the current fiscal year. Additionally, our board of directors generally establishes an interim dividend for the current fiscal year, payable in January of the following year and deducted from the final dividend payable in May of the next year. The board of directors establishes the interim dividend, which is not subject to restrictions under Chilean law.

For dividends accrued in the fiscal year 2019, on November 26, 2019, the board of directors agreed to distribute an interim dividend of Ch$ 0.447231 per share of common stock on January 31, 2020, 15% of consolidated net income as of September 30, 2019. At the OSM held on April 29, 2020, our shareholders approved a final dividend equivalent to Ch$ 2.569047 per share of common stock for the fiscal year 2019, of which Ch$ 2.121816 per share of common stock was distributed on May 27, 2020, after deducting the interim dividend paid in January 2020. The final dividend amounted to a payout ratio of 60% of annual consolidated net income for fiscal year 2019. At that OSM held on April 29, 2020, our shareholders also approved a dividend equivalent to Ch$ 1.660963 per share of common stock, which was distributed simultaneously with the final dividend for the fiscal year 2019 and charged to retained earnings from prior fiscal years.

Considering our financial results as of September 30, 2020, and the 2020 dividend policy presented to our shareholders at the OSM on April 29, 2020, the interim dividend of 15% of accumulated earnings as of such date was

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not distributed. Our board of directors approved a dividend equivalent to Ch$ 3.0774017 per share of common stock against retained earnings from prior years to offset the impairment charge resulting from our subsidiary Enel Generation’s decarbonization process. The dividend was approved at the OSM held on April 28, 2021.

For dividends relating to the fiscal year 2021, our board of directors presented to the OSM held on April 28, 2021, the following proposed dividend policy:

● An interim dividend, accrued in the fiscal year 2021 and amounting to 15% of consolidated net income as of September 30, 2021, to be paid in January 2022.

● A final dividend payout equal to 50% of annual net income for the fiscal year 2021, to be paid in May 2022, from which the interim dividend to be paid in January 2022 will be deducted.

This dividend policy is conditional on generating net profits in each period, expectations of future profit levels, and other conditions that may exist at the time of such dividend declaration. The proposed dividend policy is subject to our board of directors’ right to change the amount and timing of the dividends under prevailing circumstances at the time of the payment.

Dividend payments are potentially subject to legal restrictions, such as the requirement to pay dividends from either net income or retained earnings of the fiscal year. There may also be other contractual restrictions, such as non-default on credit agreements. However, these potential legal and contractual restrictions do not currently affect our ability or any of our subsidiaries’ ability to pay dividends. Please see “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources” for additional information.

Shareholders of each subsidiary and affiliate agree on the final dividend payments. Dividends are paid to shareholders of record as of midnight of the fifth business day before the payment date. Holders of ADS on the applicable record dates will be entitled to receive dividend payments.

Dividends

For each of the years indicated, the table below sets forth the dividends distributed by us in Chilean pesos per common share and U.S. dollars per ADS. For additional information, see “Item 10. Additional Information — D. Exchange Controls.”

	Dividends Distributed(1)
Year	Ch$ per Share	US$ per ADS(2)
2020	4.23	0.30
2019	3.14	0.21
2018	2.99	0.22
2017	3.23	0.26

(1) This table shows dividends paid rather than dividends accrued within any given year. These amounts do not reflect a reduction for Chilean withholding taxes, if applicable. Figures have been rounded.

(2) The U.S. dollar per ADS amount was calculated by applying the exchange rate as of December 31 of each year. One ADS = 50 shares of common stock.

For a discussion of Chilean withholding taxes and access to the formal currency market in Chile in connection with the payment of dividends and sales of ADS and the underlying common stock, see “Item 10. Additional Information — E. Taxation” and “Item 10. Additional Information — D. Exchange Controls.”

B. Significant Changes

None.

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Item 9.      The Offer and Listing

A. Offer and Listing Details.

Our shares of common stock 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.”

B. Plan of Distribution.

Not applicable.

C. Markets.

In Chile, our common stock is traded on the following stock exchanges: the Bolsa de Santiago (Santiago Stock Exchange or “SSE”) and the Bolsa Electrónica de Chile (Electronic Stock Exchange or “ESE”). As of December 31, 2020, more than 200 companies had shares listed on the SSE. As of December 31, 2020, the SSE accounted for 95% of our total equity traded in Chile. Also, 5% of our equity trading was conducted on the ESE, an electronic trading market created by banks and non-member brokerage houses.

Equities, closed-end funds, fixed-income securities, short-term and money market securities, gold, U.S. dollars, and futures contracts for stock indices and U.S. dollars trade on the SSE. It operates on business days from 9:30 a.m. to 4:00 p.m., which may differ from New York City time by up to two hours, depending on the season.

In August 2016, the SSE and the S&P Dow Jones Indices (“S&P DJI”) signed an Operating Agreement and Index Licensing. The alliance between the SSE and the S&P DJI, the leading global provider of concepts, data, and research on indices, includes international methodological standards and integrating operational processes and business strategies that enhance the visibility, governance, and transparency of the existing indices. The agreement also enables the development, granting of licenses, distribution, and administration of current and future indices, which are developed as innovative and practical tools at the service of local and international investors. The SSE indices will use the shared brand “S&P/CLX” and may be used as underlying liquid financial products, thereby contributing to the Chilean capital markets' expansion and depth. Under this agreement, S&P DJI assumed the calculation, production, maintenance, licensing, and distribution of the indices on August 6, 2018. Since that date, the IGPA and the IPSA, the former general and selective stock indices, are referred to as the SPCLXIGPA and the SPCLXIPSA, respectively.

The SPCLXIGPA is calculated considering, among other things, the prices of the shares traded during at least 25% of the days of the year, with a total of annual transactions exceeding UF 10,000 (approximately US$ 409,000 as of December 31, 2020) and a free float of at least 5%. The SPCLXIGPA index is rebalanced annually after the close of the third Friday in March. The number of shares per component of the index is updated quarterly after the close of the third Friday in June, September, and December. On December 31, 2020, the SPCLXIGPA index closed at 21,007.46 points.

The SPCLXIPSA is calculated considering, among other things, the prices of the 30 shares with the highest trading volume during the previous six months, market trading on at least 90% of trading days, and a market capitalization above Ch$ 200 billion (US$ 281 million as of December 31, 2020). The SPCLXIPSA index is rebalanced every six months after the closing of the third Friday of March and September and is re-weighted quarterly after the close of the third Friday in June and December. On December 31, 2020, the SPCLXIPSA index closed at 4,177.22 points.

Our common stock trades in the United States in the form of ADS on the NYSE by way of “when-issued” trading since April 21, 2016, under the trading symbol “ENIC WI” and regular-way trading since April 27, 2016, under the trading symbol “ENIC.” Each ADS represents 50 shares of common stock, with the ADS in turn evidenced by American Depositary Receipts (“ADRs”). The ADRs were issued under a Deposit Agreement dated April 26, 2016, between us, Citibank, N.A. acting as Depositary (the “Depositary”), and the holders and beneficial owners from time to time of ADRs issued thereunder, which was amended on February 14, 2018 (the “Deposit Agreement”). The Depositary treats only persons in whose names ADRs are registered on the books of the Depositary as owners of ADRs.

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As of December 31, 2020, ADRs evidencing 42,045,947 ADSs (equivalent to 2,102,297,374 shares of common stock) were outstanding, representing 3.0% of the total number of outstanding shares. It is not practicable for us to determine the proportion of ADS beneficially owned by U.S. final beneficial holders. The trading volume of our ADS on the NYSE and other exchanges during 2020 amounted to 145 million ADS, equivalent to US$ 570 million.

The NYSE is open for trading Monday through Friday from 9:30 a.m. to 4:00 p.m., except for holidays declared in advance by the NYSE. On the trading floor, the NYSE trades in a continuous auction format, where traders can execute stock transactions on behalf of investors. Specialist brokers act as auctioneers in an open outcry auction market to bring buyers and sellers together and manage the actual auction. Customers can also send orders for immediate electronic execution or route orders to the floor for trade in the auction market. The NYSE works with U.S. regulators, such as the SEC and the Commodity Futures Trading Commission, to coordinate risk management measures in the electronic trading environment by implementing mechanisms such as circuit breakers and liquidity replenishment points.

The following table contains information regarding the amount of total traded shares of common stock and the corresponding percentage traded per market during 2020:

	Number of Common Shares Traded	Percentage of Shares Traded
Market
Chile(1)	21,571,116,360	75%
United States (One ADS = 50 shares of common stock)(2)	7,236,204,550	25%
Total	28,807,320,910	100%

(1) Includes SSE and ESE.

(2) Includes the NYSE and over-the-counter trading.

D. Selling Shareholders.

Not applicable.

E. Dilution.

Not applicable.

F. Expenses of the Issue.

Not applicable.

Item 10.      Additional Information

A. Share Capital.

Not applicable.

B. Memorandum and Articles of Association.

Description of Share Capital

Set forth below is certain information concerning our share capital and a summary of certain significant Chilean law provisions and our bylaws.

General

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Shareholders’ rights in Chilean companies are governed by the company’s bylaws (estatutos), which have the same purpose as the articles or the certificate of incorporation and the bylaws of a company incorporated in the United States and by the Chilean Corporations Law. Under the Chilean Corporations Law, legal actions by shareholders to enforce their rights as shareholders of the company must be brought in Chile in arbitration proceedings or, at the option of the plaintiff, before Chilean courts. Members of the board of directors, managers, officers, and principal executives of the company, or shareholders who individually own shares with a book value or stock value higher than UF 5,000 (approximately Ch$ 145 million as of December 31, 2020) do not have the option to bring the procedure to the courts.

The CMF regulates the Chilean securities markets under the Securities Market Law (Law No. 18,045) and the Chilean Corporations Law. These two laws state the disclosure requirements, restrictions on insider trading and price manipulation, and protect minority shareholders. The Securities Market Law sets forth requirements for public offerings, stock exchanges, and brokers and outlines disclosure requirements for companies that issue publicly offered securities. The Chilean Corporations Law and the Securities Market Law, both as amended, state rules regarding takeovers, tender offers, transactions with related parties, qualified majorities, share repurchases, directors committees, independent directors, stock options, and derivative actions.

Public Register

We are a publicly held stock corporation incorporated under the laws of Chile. We were incorporated by public deed issued on January 8, 2016, by the Santiago Notary Public, Mr. Iván Torrealba A., and registered on January 19, 2016, in the Commercial Register (Registro de Comercio del Conservador de Bienes Raíces y Comercio de Santiago) on pages 4288 No. 2570. Our registry in the Securities Registry of the CMF was approved by the CMF on April 13, 2016, under entry number 1139. We also registered with the United States Securities and Exchange Commission under the commission file number 001-37723 on March 31, 2016.

Reporting Requirements Regarding Acquisition or Sale of Shares

Under Article 12 of the Securities Market Law and General Rule No. 269 of the CMF, certain information regarding transactions in shares of a publicly held stock corporation or in contracts or securities whose price or financial results depend on, or are conditioned in whole or in a significant part on the price of such shares, must be reported to the CMF and the Chilean Stock Exchanges. Since ADS are deemed to represent the shares of common stock underlying the ADRs, transactions in ADRs will be subject to these reporting requirements and those established in Circular No. 1375 of the CMF. Shareholders of publicly held stock corporations are required to report to the CMF and the Chilean Stock Exchanges:

● any direct or indirect acquisition or sale of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held stock corporation’s subscribed capital;

● any direct or indirect acquisition or sale of contracts or securities whose price or financial results depend on or are conditioned in whole or in a significant part on the price of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held stock corporation’s subscribed capital;

● any direct or indirect acquisition of shares made by a holder who, due to a purchase of shares of such publicly held stock company, results in the holder acquiring, directly or indirectly, at least 10% of a publicly held stock corporation’ssubscribed capital;

● any direct or indirect acquisition or sale of shares in any amount, made by a director, receiver, principal executive, general manager, or manager of a publicly held stock corporation; and

● any direct or indirect acquisition or sale of contracts or securities whose price or financial results depend on or are conditioned in whole or in a significant part on the price of shares made by a director, receiver, principal executive, general manager, or manager of a publicly held stock corporation.

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The majority shareholders of a publicly held stock corporation must inform the CMF and the Chilean stock exchanges if such acquisitions are entered into to acquire control of the company or make a passive financial investment instead.

Under Article 54 of the Securities Market Law and General Rule No. 104 enacted by the CMF, unless the tender offer regulation applies, any person who directly or indirectly intends to take control of a publicly held stock corporation must disclose this intent to the market at least ten business days in advance of the proposed change of control and, in any event, as soon as the negotiations for the change of control have taken place or reserved information of the publicly held stock corporation has been provided.

Corporate Objectives and Purposes

Article 4 of our bylaws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transformation, or sale of energy in Chile in any form, directly or through other companies, as well as to provide engineering consulting services related to these objectives and to make loans to related companies, subsidiaries, and affiliates.

Board of Directors

Our board of directors consists of seven members appointed by shareholders at an OSM and are elected for a three-year term, at the end of which they will be re-elected or replaced. The seven directors elected at the OSM are the seven individual nominees who receive the highest majority of the votes, provided one of those individuals must be an independent director. Each shareholder may vote his shares in favor of one nominee or may apportion his shares among any number of nominees. The effect of these voting provisions is to ensure that a shareholder owning more than 12.5% of our shares is guaranteed to be able to elect a member of the board. Depending on the distribution of the rest of the votes at the OSM, a director may in some cases be elected with the votes of less than 12.5% of our shares. This number is derived from the reciprocal of the number of directors plus one. In our case, there are seven directors, and the reciprocal of eight is equal to 12.5%.

The compensation of the directors is established annually at the OSM. See “Item 6. Directors, Senior Management and Employees — B. Compensation.”

Agreements entered into by us with related parties can only be executed when such agreements serve our interest, and their price, terms, and conditions are consistent with prevailing market conditions at the time of their approval and comply with all the requirements and procedures indicated in Article 147 of the Chilean Corporations Law.

Certain Powers of the Board of Directors

As of the date of this Report, our bylaws provide that every agreement or contract that we enter into with our controlling shareholder, our directors or executives, or their related parties, must be previously approved by two-thirds of the board of directors and be included in the board meetings, and must comply with the provisions of the Chilean Corporations Law.

Our bylaws do not contain provisions relating to:

● the directors’ power, in the absence of an independent quorum, to vote on compensation for themselves or any members of their body;

● borrowing powers exercisable by the directors and how such borrowing powers can be changed;

● retirement or non-retirement of directors under an age limit requirement; or

● the number of shares, if any, required for directors’ qualification.

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Certain Provisions Regarding Shareholder Rights

As of the date of this Report, our capital comprises only one class of shares, all of which are common shares and have the same rights.

Our bylaws do not contain any provisions relating to:

● redemption provisions;

● sinking funds; or

● liability for capital reductions by us.

Under Chilean law, the rights of our shareholders may only be modified by an amendment to the bylaws that complies with the requirements explained below under “Item 10. Additional Information — B. Memorandum and Articles of Association. — Shareholders’ Meetings and Voting Rights.”

Capitalization

Under Chilean law, only the shareholders of a company acting at an ESM have the power to authorize a capital increase. When an investor subscribes shares, these are officially issued and registered under his name. The subscriber is treated as a shareholder for all purposes, except the receipt of dividends and return of capital if the shares have been subscribed but not paid. The subscriber becomes eligible to receive dividends only for the shares that he has paid for or, if the subscriber has paid for only a portion of such shares, the pro-rata portion of the dividends declared with respect to such shares unless the company’s bylaws provide otherwise. If a subscriber does not fully pay for shares for which the subscriber has subscribed on or before the date agreed upon for payment, notwithstanding the actions intended by the company to collect payment, the company is entitled to auction on the stock exchange where such shares are traded, for the account and risk of the debtor, the number of shares held by the debtor necessary for the company to pay the outstanding balances and disposal expenses. However, until such shares are sold at auction, the subscriber continues to hold all the rights of a shareholder, except the right to receive dividends and return of capital. The Chief Executive Officer, or the person replacing him, will reduce the number of shares in the name of the debtor shareholder in the shareholders’ register to the number of shares that remain, deducting the shares sold by the company and settling the debt in the amount necessary to cover the result of such disposal after related expenses.

When there are authorized and issued shares for which full payment has not been made within the period fixed by shareholders at the same ESM at which the subscription was authorized (which may not exceed three years from the date of such meeting, unless a stock option plan is approved, in which case the period to pay for the shares under such program may be up to five years), these shall be reduced in the non-subscribed amount until that date. Concerning the shares subscribed and not paid following the term mentioned above, the board must proceed to collect payment, unless the shareholders’ meeting authorizes the board not to do so (by two-thirds of the voting shares), in which case the capital shall be reduced by force of law to the amount effectively paid. Once collection actions have been exhausted, the board should propose to the shareholders’ meeting the approval by a simple majority of the write-off of the outstanding balance and the reduction of capital to the amount effectively collected.

As of December 31, 2020, our subscribed and fully paid capital totaled Ch$ 3.9 trillion and consisted of 69,166,557,220 shares.

Preemptive Rights and Increases of Share Capital

Except for capital increases needed to carry out a merger, Chilean law requires Chilean publicly held stock corporations to grant shareholders preemptive rights to purchase a sufficient number of shares, or any other securities convertible into shares or that confer future rights over shares, to maintain their existing ownership percentage of such company whenever such company issues new shares, or any other securities convertible into shares or that confer future rights over shares.

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Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders for 30 days. The options to subscribe for shares in capital increases of the company or of any other securities convertible into shares or that confer future rights over these shares should be offered at least once to the shareholders pro-rata based on the number of shares held registered in their name at midnight on the fifth business day before the date of the start of the preemptive rights period. The preemptive rights offering and the beginning of the 30 days for exercising them shall be communicated through the publication of a prominent notice, at least once, in the newspaper used for notifications of shareholders’ meetings. During such 30 days, and for an additional period of at least 30 days immediately following the initial 30 days, if any, publicly held stock corporations are not permitted to offer any unsubscribed shares to third parties under more favorable terms than those provided to their shareholders. At the end of the second 30 days, a Chilean publicly held stock corporation is authorized to sell unsubscribed shares to third parties under any terms, provided they are sold on one of the Chilean Stock Exchanges.

Shareholders’ Meetings and Voting Rights

An OSM must be held within the first four months following the end of our fiscal year. Our last OSM was held on April 28, 2021. An ESM may be summoned by the board of directors when deemed appropriate. An ESM or an OSM, as the case may be, must be summoned when requested by shareholders representing at least 10% of the issued shares with voting rights, or by the CMF. To convene an OSM or an ESM, notice must be given three times in a newspaper located in our corporate domicile, at least ten days in advance of the scheduled meeting. The newspaper designated by our shareholders is El Mercurio de Santiago. Notice must also be mailed to each shareholder, the CMF, the Chilean Stock Exchanges, and the Depositary for our ADRs.

The OSM or ESM shall be held on the day stated in the notice and should remain in session until all the matters stated in the notice have been addressed. However, once constituted, upon the proposal of the Chairman or shareholders representing at least 10% of the shares with voting rights, the majority of the shareholders present may agree to suspend it and to continue it within the same day and place, with no new constitution of the meeting or qualification of powers being necessary, recorded in one set of minutes. Only those shareholders who were present or represented may attend the recommencement of the meeting with voting rights.

Under Chilean law, a quorum for a shareholders’ meeting is established by the presence, in person or by proxy, of shareholders representing at least a majority of the issued shares with voting rights of a company. If a quorum is not present at the first meeting, a reconvened meeting can occur at which the shareholders present are deemed to constitute a quorum regardless of the percentage of the shares represented. This second meeting must take place within 45 days following the scheduled date for the first meeting. Shareholders’ meetings adopt resolutions by the affirmative vote of a majority of those shares present or represented at the meeting unless a qualified majority is required.

Regardless of the quorum present, a vote of at least two-thirds majority of the outstanding shares with voting rights is required to adopt any of the following:

● a transformation of the company into a form other than a publicly held stock corporation under the Chilean Corporations Law, a merger or split-up of the company;

● an amendment to the term of duration or early dissolution of the company;

● a change in the company’s domicile;

● a decrease of corporate capital;

● an approval of capital contributions in kind and non-monetary assessments;

● a modification of the authority reserved to shareholders or limitations on the board of directors;

● a reduction in the number of members of the board of directors;

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● a disposition of 50% or more of the assets of the company, whether it includes the disposition of liabilities or not, as well as the approval or the amendment of the business plan that contemplates the disposition of assets in an amount greater than such percentage;

● the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the corporation, as well as any disposition of its shares that results in the parent company losing its position as controlling shareholder;

● the form of distributing corporate benefits;

● issue of guarantees for third-party liabilities which exceed 50% of the assets, except when the third party is a subsidiary of the company, in which case approval of the board of directors is deemed sufficient;

● the purchase of the company’s own shares;

● other actions established by the bylaws or the laws;

● certain remedies for the nullification of the company’s bylaws;

● inclusion in the bylaws of the right to purchase shares from minority shareholders, when the controlling shareholders reach 95% of the company’s shares through a tender offer for all of the company’s shares, where at least 15% of the shares have been acquired from unrelated shareholders; and

● approval or ratification of acts or contracts with related parties.

Certain amendments to our bylaws require the affirmative vote of 75% of the outstanding shares with voting rights.

Bylaw amendments for creating a new class of shares, or an amendment to or an elimination of those classes of shares that already exist, must be approved by at least two-thirds of the outstanding shares of the affected series.

Chilean law does not require a publicly held stock corporation to provide its shareholders the same level and type of information required by the U.S. securities laws regarding proxies’ solicitation. However, shareholders are entitled to examine the financial statements and corporate books of a publicly held stock corporation and its subsidiaries within the 15 days before its scheduled shareholders’ meetings. Under Chilean law, publicly held stock corporations must also inform, at least ten days in advance of the scheduled meeting and in the manner to be established by the CMF, that an ESM or an OSM has been summoned, indicating the date, the matters to be discussed, and how complete copies of the documents that support the issues submitted for voting can be obtained, which must also be made available to shareholders on the company’s website. In the case of an OSM, our annual report of activities, which includes audited financial statements, must also be made available to shareholders and published on our website at: www.enelchile.cl.

The Chilean Corporations Law provides that, upon the request by the Directors Committee or by shareholders representing at least 10% of the issued shares with voting rights, a Chilean company’s annual report must include, in addition to the materials provided by the board of directors to shareholders, such shareholders’ comments and proposals concerning the company’s affairs. Under Article 136 of the Chilean Corporations Regulation (Reglamento de Sociedades Anónimas), the shareholder(s) holding or representing at least 10% of the shares issued with voting rights, may:

● make comments and proposals relating to the progress of the corporate businesses in the corresponding year, no shareholder can make individually or jointly more than one presentation. These observations should be presented in writing to the company concisely, responsibly, and respectfully. The respective shareholder(s) should state their willingness to be included as an appendix to the annual report. The board shall include in an appendix to the annual report of the year a faithful summary of the pertinent comments and proposals the

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interested parties had made, provided they are presented during the year or within 30-days after its ending; or

● make comments and proposals on matters that the board submits for the shareholders’ knowledge or voting. The board shall include a faithful summary of those comments and proposals in all information it sends to shareholders, provided the shareholders’ proposal is received at the offices of the company at least ten days before the date of dispatch of the information by the company.

The shareholders should present their comments and proposals to the company, expressing their willingness to be included in the appendix to the respective annual report or in information sent to shareholders, as the case may be. The observations referred to in Article 136 may be made separately by each shareholder holding at least 10% of the shares issued with voting rights or shareholders who together hold that percentage, who should act as one.

Similarly, the Chilean Corporations Law provides that whenever the board of directors of a publicly held stock corporation convenes an OSM or ESM and solicits proxies for the meeting, or circulates information supporting its decisions or other similar material, it is obligated to include the pertinent comments and proposals that may have been made by the Directors Committee or by shareholders owning at least 10% of the shares with voting rights who request that such comments and proposals be so included.

Only shareholders registered as such with us as of midnight on the fifth business day before the meeting date are entitled to attend and vote their shares. A shareholder may appoint another individual, who does not need to be a shareholder, as his proxy to attend the meeting and vote on his behalf. Proxies for such representation shall be given for all the shares held by the owner. The proxy may contain specific instructions to approve, reject, or abstain concerning any of the matters submitted for voting at the meeting and included in the notice. Every shareholder entitled to attend and vote at a shareholders’ meeting shall have one vote for every share subscribed.

There are no limitations imposed by Chilean law or our bylaws on the right of nonresidents or foreigners to hold or vote shares of common stock. However, the registered holder of the shares of common stock represented by ADS, and evidenced by outstanding ADS, is the custodian for Citibank, N.A. as Depositary, currently Banco Santander-Chile, or any successor custodian. Accordingly, holders of ADS are not entitled to receive notice of shareholders’ meetings directly or to vote the underlying shares of common stock represented by ADS directly. The Deposit Agreement contains provisions under which the Depositary has agreed to request instructions from registered holders of ADS regarding the exercise of the voting rights of the shares of common stock represented by the ADS. Subject to compliance with the requirements of the Deposit Agreement and receipt of such instructions, the Depositary has agreed to endeavor, insofar as practicable and permitted under Chilean law and the provisions of the bylaws, to vote or cause to be voted (or grant a discretionary proxy to the Chairman of the Board of Directors or to a person designated by the Chairman of the Board of Directors to vote) the shares of common stock represented by the ADS under any such instruction. The Depositary shall not itself exercise any voting discretion over any shares of common stock underlying ADS. If the Depositary receives no voting instructions from a holder of ADS concerning the shares of common stock represented by the ADS, on or before the date established by the Depositary for such purpose, the shares of common stock represented by the ADS may, in some situations, be voted in the manner directed by the Chairman of the Board, or by a person designated by the Chairman of the Board, subject to limitations outlined in the Deposit Agreement.

Dividends and Liquidation Rights

According to the Chilean Corporations Law, unless otherwise decided by a unanimous vote of its issued shares eligible to vote, all publicly held stock corporations must distribute a cash dividend in an amount equal to at least 30% of their consolidated net income, unless and except to the extent we have carried forward losses. The law provides that the board of directors must agree to the dividend policy and inform such policy to the shareholders at the OSM.

For any dividend above 30% of net income, publicly held stock corporations may grant their shareholders an option to receive those dividends, in cash, or shares issued by such publicly held stock corporation, or in shares of publicly held corporations owned by such company. Shareholders who do not expressly elect to receive a dividend other than cash are legally presumed to have decided to accept the dividend in cash.

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Dividends declared but not paid within the appropriate period provided in the Chilean Corporations Law (30 days after declaration for the minimum dividend, and the date set for payment at the time of declaration for additional dividends) are adjusted to reflect the change in the value of the UF from the date set for payment to the date such dividends are paid. Such dividends also accrue interest at the prevailing rate for UF-denominated deposits during such period. The right to receive a dividend lapses if it is not claimed within five years from the date such dividend is payable. Payments not collected in such a period are transferred to the Chilean volunteer fire department.

In the event of our liquidation, the shareholders would participate in the assets available in proportion to the number of paid-in shares held by them, after payment to all creditors.

Approval of Financial Statements

The board of directors is required to submit our consolidated financial statements to the shareholders annually for their approval. If the shareholders at the shareholders’ meeting reject the financial statements by a vote of a majority of shares present (in person or by proxy), the board of directors must submit new financial statements no later than 60 days from the date of such meeting. If the shareholders reject the new financial statements, the entire board of directors is deemed removed from office, and a new board is elected at the same meeting. Directors who individually approved such financial statements are disqualified for reelection for the following period. Our shareholders have never rejected the financial statements presented by the board of directors.

Change of Control

The Capital Markets Law establishes a comprehensive regulation related to tender offers. The law defines a tender offer as the offer to purchase shares of companies that publicly offer their shares or convertible securities. This offer is made to shareholders to purchase their shares under conditions that allow the bidder to reach a certain percentage of ownership of the company within a fixed period. These provisions apply to both voluntary and hostile tender offers.

Acquisition of Shares

No provision in our bylaws discriminates against any existing or prospective holder of shares due to such shareholder owning a substantial number of shares. However, no person may directly or indirectly own more than 65% of our stock’s outstanding shares. The preceding restriction does not apply to the depositary as record owner of shares represented by ADRs, but it does apply to each beneficial ADS holder. Additionally, our bylaws currently prohibit any shareholder from exercising voting power concerning more than 65% of the common stock owned by such shareholder or on behalf of others representing more than 65% of the outstanding issued shares with voting rights.

Right of Dissenting Shareholders to Tender Their Shares

The Chilean Corporations Law provides that upon adopting any of the resolutions enumerated below at a shareholders’ meeting, dissenting shareholders acquire the right to withdraw from the company and compel the company to repurchase their shares, subject to the fulfillment of specific terms and conditions. To exercise such withdrawal rights, holders of ADRs must first withdraw the shares represented by their ADRs under the Deposit Agreement’s terms. In case of a bankruptcy proceeding, the withdrawal right from an adopted resolution is suspended until the existing debt has been paid.

“Dissenting” shareholders are defined as those at a shareholders’ meeting who vote against a resolution that results in the withdrawal right or who, if absent from such meeting, state in writing their opposition to the respective resolution within the 30 days following the shareholders’ meeting. Shareholders present or represented at the meeting and who abstain from exercising their voting rights shall not be considered dissenting. The right to withdraw should be exercised for all the shares that the dissenting shareholder had registered in their name on the date on which the right is determined to participate in the meeting at which the resolution is adopted that motivates the withdrawal and which remains on the date on which their intention to withdraw is communicated to the company.

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The price paid to a dissenting shareholder of a publicly held stock corporation whose shares are quoted and actively traded on one of the Chilean stock exchanges is the weighted average of the sales prices for the shares as reported on the Chilean stock exchanges on which the shares are quoted for the 60 trading days between the ninetieth and the thirtieth trading day before the shareholders meeting giving rise to the withdrawal right. If the CMF determines that the shares are not actively traded on a stock exchange, the dissenting shareholder’s price shall be the book value. Book value for this purpose is equal to the company’s equity attributable to the parent company, divided by the total number of subscribed shares, whether entirely or partially paid. To make this calculation, the last consolidated statement of financial position is used, as adjusted to reflect inflation up to the date of the shareholders meeting which gave rise to the withdrawal right.

Article 126 of the Chilean Corporations Regulation establishes that in cases where the right to withdraw arises, the company shall be obliged to inform the shareholders of this situation, the value per share paid to shareholders exercising their right to withdraw, and the term for exercising it. Such information should be given to shareholders at the same meeting at which the resolutions are adopted, giving rise to the right of withdrawal, before its voting. A special communication should be given to the shareholders with rights within two days following the date on which the rights to withdraw arise. In the case of publicly held companies, such information shall be communicated by a prominent notice in a newspaper with a wide national circulation and on its website, plus a written communication addressed to the shareholders with rights at the address they have registered with the company. The notice of the shareholders meeting that to vote on a matter that could give rise to withdrawal rights should mention this circumstance.

The resolutions that result in a shareholder’s right to withdraw include, among others, the following:

● the transformation of the company into an entity which is not a publicly held stock corporation governed by Chilean Corporations Law;

● the merger of the company with another company;

● disposition of 50% or more of the assets of the company, whether it includes the disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater than such percentage;

● the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the company, as well as any disposition of its shares that results in the parent company losing its position of controlling shareholder;

● issue of guarantees for third-party liabilities that exceed 50% of the assets (if the third party is a subsidiary of the company, the approval of the board of directors is sufficient and will not give rise to the right to withdraw);

● the creation of preferential rights for a class of shares or an amendment to the existing ones. In this case, the right to withdraw only accrues to the dissenting shareholders of the class or classes of shares adversely affected;

● certain remedies for the nullification of the corporate bylaws; and

● such other causes as may be established by the law or by the company’s bylaws.

Investments by AFPs

The Pension Fund System Law permits AFPs to invest their funds in companies subject to Title XII of such law, and these companies are subject to greater restrictions than other companies. The determination of which stocks may be purchased by AFPs is made by the Risk Classification Committee. The Risk Classification Committee establishes investment guidelines and is empowered to approve or disapprove those companies that are eligible for AFP

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investments. We are and have been subject to Title XII provisions and are approved by the Risk Classification Committee.

Companies subject to Title XII provisions are required to have bylaws that:

● limit the ownership of any shareholder to a specified maximum percentage, currently 65%;

● require that certain actions be taken only at a meeting of the shareholders; and

● give the shareholders the right to approve certain investment and financing policies.

Registrations and Transfers

Shares issued by us are registered with an administrative agent, which is DCV Registros S.A. This entity is also responsible for our shareholders’ registry. In the case of jointly-owned shares, an attorney-in-fact must be appointed to represent the joint owners in dealing with us.

C. Material Contracts.

None.

D. Exchange Controls.

The Central Bank of Chile is responsible for, among other things, monetary policies and exchange controls in Chile. Currently, applicable foreign exchange regulations are provided in the Compendium of Foreign Exchange Regulations (the “Compendium”) approved by the Central Bank of Chile.

a) Chapter XIV

The following is a summary of certain provisions of Chapter XIV of the Compendium that apply to all existing shareholders (and ADS holders). This summary does not intend to be complete and is qualified in its entirety by reference to Chapter XIV. Chapter XIV regulates the following type of investments: credits, deposits, investments, and equity contributions. A Chapter XIV investor may at any time repatriate an investment made in us upon selling our shares, and the profits derived therefrom, with no monetary ceiling, are subject to the regulations in effect at the time, which must be reported to the Central Bank of Chile.

Except for compliance with tax regulations and some reporting requirements, currently there are no rules in Chile affecting repatriation rights, except that the remittance of foreign currency must be made through a Formal Exchange Market entity. However, the Central Bank of Chile has the authority to change such rules and impose exchange controls.

b) The Compendium and International Bond Issuances

Chilean issuers may offer bonds internationally, subject to the reporting requirements outlined in Chapter XIV of the Compendium.

E. Taxation.

Chilean Tax Considerations

The following discussion summarizes material Chilean income and withholding tax consequences to foreign holders from the ownership and disposition of shares and ADS. The summary that follows does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a decision to purchase, own or dispose of shares or ADS, if any, and does not purport to deal with the tax consequences applicable to all categories of investors,

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some of which may be subject to special rules. Holders of shares and ADS are advised to consult their own tax advisors concerning the Chilean and other tax consequences of the ownership of shares or ADS.

The summary that follows is based on Chilean law, in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions in statutes such as tax rates applicable to foreign investors, the computation of taxable income for Chilean purposes, and how Chilean taxes are imposed and collected may be amended only by another law. The Chilean tax authorities also enact rulings and regulations of either general or specific application and interpret the Chilean Income Tax Law provisions. Chilean tax may not be assessed retroactively against taxpayers who act in good faith, relying on such rulings, regulations, and interpretations but, Chilean tax authorities may change their rulings, regulations, and interpretations in the future. The discussion that follows is also based, in part, on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreements will be performed under its terms. As of this date, there is currently no applicable income tax treaty in effect between the United States and Chile. However, in 2010 the United States and Chile signed an income tax treaty that will enter into force once the treaty is ratified by both countries, which has not happened as of the date of this Report. There can be no assurance that either country will ratify the treaty. The following summary assumes that there is no applicable income tax treaty in effect between the United States and Chile.

As used in this Report, the term “foreign holder” means either:

●In the case of an individual holder, a person who is not a resident of Chile. For purposes of Chilean taxation, (a)  any person who remains in Chile, uninterrupted or not, for a period or periods that in total exceed 183 days, within any period of twelve months; or (b) an individual is domiciled in Chile if he resides in Chile and has the intention of remaining in Chile (such intention to be evidenced by circumstances such as the acceptance of employment in Chile or the relocation of the individual’s family to Chile), or

● in the case of a legal entity holder, an entity that is not organized under Chile’s laws, unless the shares or ADS are assigned to a branch, agent, representative, or permanent establishment of such entity in Chile.

Taxation of Shares and ADS

Taxation of Cash Dividends and Property Distributions

Cash dividends paid concerning the shares or ADS held by a foreign holder will be subject to Chilean withholding tax, which is withheld and paid by the company. The amount of the Chilean withholding tax is determined by applying a 35% rate to a “grossed-up” distribution amount (such amount equal to the sum of the actual distribution amount and the correlative Chilean corporate income tax (“CIT”), paid by the issuer), and then subtracting as a credit 65% of such Chilean CIT paid by the issuer, in case the residence country of the holder of shares or ADS does not have a tax treaty with Chile. If there is a tax treaty between both countries (in force or signed before January 1, 2020), the Foreign Holder can apply 100% of the CIT as a credit. For 2020, the Chilean CIT applicable to us is a rate of 27%, and depending on the circumstances mentioned above, the Foreign Holder may apply 100% or 65% of the CIT as a credit.

In February 2020, tax reform contemplating only a partially integrated tax regime was enacted. Under the current Chilean Income Tax Law, publicly held stock corporations, such as we, are subject to this regime, consisting of a cash basis shareholder taxation.

Under the cash basis regime (or partially integrated regime), a company pays CIT on its annual income tax result. Foreign and local individual shareholders will only pay in Chile the relevant tax on effective profit distributions. They will be allowed to use the CIT paid by the distributing company as credit, with certain limitations. Only 65% of the CIT is creditable against the 35% shareholder-level tax. However, in those cases where tax treaties between Chile and the jurisdiction of the shareholder’s residence were signed before January 1, 2020 (even if not yet in effect), the CIT is entirely creditable against the 35% withholding tax. This is the case with the tax treaty signed between Chile and the United States, which was signed before this date, but which is not in effect as of the date of this Report. In the case of treaties signed before January 1, 2020, but not ratified as of December 31, 2026, the shareholder may apply 100% of the CIT as a credit if a dividend distribution is made before December 31, 2026, on a transitional basis. Under the Chilean

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Tax Law in force at the date of this Report, the transitional treatment of applying the full 100% of the CIT as a credit against withholding tax of the U.S. Holders in case of dividend distributions will terminate on December 31, 2026, if the tax treaty between the United States and Chile is not ratified by that date. In that particular case, effective as of January 1, 2027, only 65% of the CIT will be creditable against the 35% U.S. Holders’ tax. On the other hand, if a tax treaty with a foreign jurisdiction is ratified by December 31, 2026, shareholders from that particular jurisdiction can continue to apply 100% of the CIT as a credit beyond such date.

The example below illustrates the effective Chilean withholding tax burden on a cash dividend received by a Foreign Holder, assuming a Chilean withholding tax base rate of 35%, an effective Chilean CIT rate of 27% (the CIT rate for 2020 under cash basis regime) and a distribution of 50% of the net income of the company distributable after payment of the Chilean CIT:

Line	Concept and calculation assumptions	Amount Tax Treaty Resident	Amount Non-Tax Treaty Resident
1	Company taxable income (based on Line 1 = 100)	100	100
2	Chilean corporate income tax: 27% x Line 1	27	27
3	Net distributable income: Line 1—Line 2	73	73
4	Dividend distributed (50% of net distributable income): 50% of Line 3	36.5	36.5
5	Withholding tax: (35% of (the sum of Line 4 and 50% of Line 2))	17.5	17.5
6	Credit for 50% of Chilean corporate income tax : 50% of Line 2	13.5	13.5
7	CIT partial restitution (Line 6 x 35%)(1)	—	4.7
8	Net withholding tax: Line 5 - Line 6 + Line 7	4	8.7
9	Net dividend received: Line 4 - Line 8	32.5	27.8
10	Effective dividend withholding rate: Line 8 / Line 4	11.0	23.9

(1) Only applicable to non-tax treaty jurisdiction residents. From a practical standpoint, the foregoing means that the CIT is only partially creditable (65%) against the withholding tax (i.e., CIT of 8.7%).

However, for purposes of the foregoing, the tax authority has not clarified whether the taxpayer residence will be the ADS holder’s address or the depository’s address.

Taxation on sale or exchange of ADS outside of Chile

Gains obtained by a foreign holder from the sale or exchange of ADS outside Chile are not subject to Chilean taxation.

Taxation on sale or exchange of Shares

The Chilean Income Tax Law includes a tax exemption on capital gains from the sale of shares of listed companies traded in stock markets. Although there are certain restrictions, in general terms, the law provides that in order to qualify for the capital gain exemption: (i) the shares must be of a publicly held stock corporation with a “sufficient stock market liquidity” status in the Chilean Stock Exchanges; (ii) the sale must be conducted in a Chilean Stock Exchange authorized by the CMF, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law or as the consequence of a contribution to a fund as regulated in Section 109 of the Chilean Income Tax Law; (iii) the shares which are being sold must have been acquired on a Chilean Stock Exchange, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law, or in an initial public offering (due to the creation of a company or to a capital increase), or due to the exchange of convertible publicly offered securities, or due to the redemption of a fund’s quota as regulated in Section 109 of the Chilean Income Tax Law; and (iv) the shares must have been acquired after April 19, 2001. For purposes of considering the ADS as convertible publicly offered securities, they should be registered in the Chilean foreign securities registry (unless expressly excluded from such registry by the CMF).

Shares are considered to have a “high presence” in the Chilean Stock Exchanges when (i) they have been traded for a certain number of days at or beyond a volume threshold specified under Chilean law and regulations or (ii) in case the issuer has retained a market maker, under Chilean law and regulations. As of this date, our shares are considered to

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have a high presence in the Chilean Stock Exchanges, and we have not retained any market maker. Should our shares cease to have a “high presence” in the Chilean Stock Exchanges, a transfer of our shares may be subject to capital gains taxes from which holders of “high presence” securities are exempted, and which will apply at varying levels depending on the time of the transfer concerning the date of loss of sufficient trading volume to qualify as a “high presence” security. If our shares regain a “high presence,” the tax exemptions will again be available to holders thereof.

If the shares do not qualify for the exemption, capital gains on their sale or exchange of shares (as distinguished from sales or exchanges of ADS representing such shares of common stock) could be subject to the general tax regime, with a 27% Chilean CIT, the rate applicable during 2020, and a 35% Chilean withholding tax, the former being creditable against the latter.

The date of acquisition of the ADS is the date of purchase of the shares for which the ADS are exchanged.

Taxation of Share Rights and ADS Rights

For Chilean tax purposes and to the extent we issue any share rights or ADS rights, the receipt of share rights or ADS rights by a Foreign Holder of shares or ADS under a rights offering is a nontaxable event. Also, there are no Chilean income tax consequences to Foreign Holders upon the exercise or the expiration of the share rights or the ADS rights.

Any gain on the sale, exchange, or transfer of any ADS rights by a Foreign Holder is not subject to taxes in Chile.

Any gain on the sale, exchange, or transfer of the share rights by a Foreign Holder is subject to a 35% Chilean withholding tax.

Other Chilean Taxes

There is no gift, inheritance, or succession tax applicable to foreign holders’ ownership, transfer, or disposition of ADS. Still, such taxes will generally apply to the transfer at death or by a gift of the shares by a foreign holder. There is no Chilean stamp, issue, registration, or similar taxes or duties payable by holders of shares or ADS.

Material U.S. Federal Income Tax Considerations

This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary, and proposed Treasury regulations, all as of the date of this Report. These authorities are subject to change, possibly with retroactive effect. This discussion assumes that the depositary’s activities are clearly and appropriately defined to ensure that the tax treatment of ADS will be identical to the tax treatment of the underlying shares.

The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning, and disposing of shares or ADS. Still, it does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a particular person’s decision to hold such securities and is based on the assumption stated above under “― Chilean Tax Considerations” that there is no applicable income tax treaty in effect between the United States and Chile. The discussion applies only if the beneficial owner holds shares or ADS as capital assets for U.S. federal income tax purposes. It does not describe all the tax consequences that may be relevant in light of the beneficial owner’s particular circumstances. For instance, it does not describe all the tax consequences that may be relevant to:

● certain financial institutions;

● insurance companies;

● dealers and traders in securities who use a mark-to-market method of tax accounting;

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● persons holding shares or ADS as part of a “straddle” integrated transaction or similar transaction;

● persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

● partnerships or other entities classified as partnerships for U.S. federal income tax purposes or partners in such partnerships;

● persons liable for the alternative minimum tax;

● tax-exempt organizations;

● persons holding shares or ADS that own or are deemed to own ten percent or more of our stock; or

● persons holding shares or ADS connected with a trade or business conducted outside of the United States.

Persons or entities described above, including partnerships holding shares or ADS and partners in such partnerships, should consult their own tax advisors about the particular U.S. federal income tax consequences of holding and disposing of shares or ADS.

You will be a “U.S. Holder” for purposes of this discussion if you become a beneficial owner of our shares or ADS and if you are, for U.S. federal income tax purposes:

● a citizen or an individual resident of the United States; or

● a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or any political subdivision thereof; or

● an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or

● a trust (i) that validly elects to be treated as a U.S. person for U.S. federal income tax purposes or (ii) if (A) a court within the United States can exercise primary supervision over the administration of the trust and (B) one or more U.S. persons have the authority to control all substantial decisions of the trust.

For U.S. federal income tax purposes, it is generally expected that a U.S. Holder of ADS will be treated as the beneficial owner of the underlying shares represented by the ADS. The remainder of this discussion assumes that a U.S. Holder of our ADS will be treated in this manner for U.S. federal income tax purposes. Accordingly, deposits or withdrawals of shares for ADS will generally not be subject to U.S. federal income tax.

The U.S. Treasury has expressed concerns that parties to whom ADS are released before shares are delivered to the depositary (pre-release) or intermediaries in the chain of ownership between beneficial owners and the issuer of the security underlying the ADS may be taking actions that are inconsistent with the claiming of foreign tax credits for beneficial owners of depositary shares. Such actions would also be inconsistent with claiming the reduced tax rate, described below, applicable to dividends received by certain non-corporate beneficial owners. Accordingly, the analysis of the creditability of Chilean taxes, and the availability of the reduced tax rate for dividends received by certain non-corporate holders, each described below, could be affected by actions taken by such parties or intermediaries.

This discussion assumes that we will not be a passive foreign investment company, as described below. The discussion below does not address the effect of any U.S. state, local, estate, or gift tax law or non-U.S. tax law or tax considerations that arise from rules of general application to all taxpayers on a U.S. Holder of the shares or ADS or of any future administrative guidance interpreting provisions thereof. U.S. Holders should consult their tax own advisors concerning their particular tax consequences of owning or disposing of shares or ADS, including the applicability and effect of state, local, non-U.S., and other tax laws and the possibility of changes in tax laws, including the effects of any future administrative guidance interpreting provisions thereof.

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Taxation of Distributions

The following discussion of cash dividends and other distributions is subject to the discussion below under “Passive Foreign Investment Company Rules.” Distributions received by a U.S. Holder on shares or ADS, including the amount of any Chilean taxes withheld, other than certain pro-rata distributions of shares to all shareholders, will constitute foreign-source income to the extent paid out of our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported to U.S. Holders as dividends. The amount of dividend income paid in Chilean pesos that a U.S. Holder will be required to include in income will equal the U.S. dollar value of the distributed Chilean peso, calculated by reference to the exchange rate in effect on the date the payment is received, regardless of whether the payment is converted into U.S. dollars on the date of receipt. If the dividend is converted into U.S. dollars on the date of receipt, a U.S. Holder will generally not be required to recognize foreign currency gain or loss regarding the dividend income. A U.S. Holder may have foreign currency gain or loss if the dividend is converted into U.S. dollars after the date of its receipt, which would be ordinary income or loss and would be treated as income from U.S. sources for foreign tax credit purposes. Dividends will be included in a U.S. Holder’s income on the date of the U.S. Holder’s, or in the case of ADS, the depositary’s, receipt of the dividend.

Subject to certain exceptions for short-term and hedged positions, the discussion above regarding concerns expressed by the U.S. Treasury and the discussion below regarding rules intended to be promulgated by the U.S. Treasury, the U.S. dollar amount of dividends received by a non-corporate U.S. Holder in respect of shares or ADS generally will be subject to taxation at preferential rates if the dividends are “qualified dividends.” Dividends paid on the ADS generally will be treated as qualified dividends if (i) the ADS are readily tradable on an established securities market in the United States (ii) we were not, in the year before the year in which the dividend was paid, and is not, in the year in which the dividend is paid, a passive foreign investment company (“PFIC”) and (iii) the holder thereof has satisfied certain holding period requirements. The ADS are listed on the New York Stock Exchange and generally will qualify as readily tradable on an established securities market in the United States so long as they are so listed. We do not expect that we will be treated as having been a PFIC for U.S. federal income tax purposes concerning our 2019 taxable year. In addition, based on our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for our 2020 taxable year. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any current, prior or future taxable year.

Based on existing guidance, it is not entirely clear whether dividends received concerning shares will be treated as qualified dividends because they are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules under which holders of ADS and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to establish that dividends are treated as qualified dividends. Because such procedures have not yet been issued, it is not clear whether we will comply with them. U.S. Holders should consult their own tax advisors to determine whether the favorable rate will apply to dividends they receive and whether it is subject to any special rules limiting its ability to be taxed at this favorable rate.

The amount of a dividend generally will be treated as foreign-source dividend income to a U.S. Holder for foreign tax credit purposes. As discussed in more detail below under “—Foreign Tax Credits,” it is not free from doubt whether Chilean withholding taxes imposed on distributions on shares or ADS will be treated as income taxes eligible for a foreign tax credit for U.S. federal income tax purposes. If a Chilean withholding tax is treated as an eligible foreign income tax, subject to generally applicable limitations, you may claim a credit against your U.S. federal income tax liability for the eligible Chilean taxes withheld from distributions on shares or ADS. If the dividends are taxed as qualified dividend income (as discussed above), special rules will apply in determining the amount of the dividend taken into account to calculate the foreign tax credit limitation. The rules relating to foreign tax credits are complex. U.S. Holders are urged to consult their own tax advisors regarding the treatment of Chilean withholding taxes imposed on distributions on shares or ADS.

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Sale or Other Disposition of Shares or ADS

If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or ADS will be a capital gain or loss, and will be a long term capital gain or loss if the beneficial holder has held the shares or ADS for more than one year. The amount of a beneficial owner’s gain or loss will equal the difference between the beneficial owner’s tax basis in the shares or ADS disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. Such gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. In addition, certain limitations exist on the deductibility of capital losses by both corporate and individual taxpayers.

In certain circumstances, Chilean taxes may be imposed upon the sale of shares (but not ADS). See “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADS.” If a Chilean tax is imposed on the sale or disposition of shares, a beneficial owner that is a U.S. Holder may be eligible to claim a credit against its U.S. federal income tax liability for the eligible Chilean taxes withheld pursuant to a sale or disposition of shares or ADS as discussed in “— Foreign Tax Credits” below.

Foreign Tax Credits

Subject to applicable limitations that may vary depending upon a U.S. Holder’s circumstances and subject to the discussion above regarding concerns expressed by the U.S. Treasury, you may be eligible to claim a credit against your U.S. tax liability for Chilean income taxes (or taxes imposed in lieu of an income tax) imposed in connection with distributions on and proceeds from the sale or other disposition of our shares or ADS. Chilean dividend withholding taxes generally are expected to be income taxes eligible for the foreign tax credit. The Chilean capital gains tax is likely to be treated as an income tax (or a tax paid in lieu of an income tax) and thus eligible for the foreign tax credit; however, you generally may claim a foreign tax credit only after taking into account any available opportunity to reduce the Chilean capital gains tax, such as the reduction for the credit for Chilean corporate income tax that is taken into account when calculating Chilean withholding tax. If a Chilean tax is imposed on the sale or disposition of our shares or ADS, and a U.S. Holder does not receive significant foreign source income from other sources, such U.S. Holder may not be able to credit such Chilean tax against its U.S. federal income tax liability. If a Chilean tax is not treated as an income tax (or a tax paid in lieu of an income tax) for U.S. federal income tax purposes, a U.S. Holder would be unable to claim a foreign tax credit for any such Chilean tax withheld; however, a U.S. Holder may be able to deduct such tax in computing its U.S. federal income tax liability, subject to applicable limitations. In addition, instead of claiming a credit, a U.S. Holder may, at the U.S. Holder’s election, deduct such Chilean taxes in computing the U.S. Holder’s taxable income, subject to generally applicable limitations under U.S. law. An election to deduct foreign taxes instead of claiming foreign tax credits applies to all taxes paid or accrued in the taxable year to foreign countries and possessions of the U.S. The calculation of foreign tax credits and, in the case of a U.S. Holder that elects to deduct foreign income taxes, the availability of deductions, involves the application of complex rules that depend on such U.S. Holder’s particular circumstances. U.S. Holders are urged to consult their own tax advisors regarding the availability of foreign tax credits in their particular circumstances.

Passive Foreign Investment Company Rules

We were not a “passive foreign investment company” or PFIC for U.S. federal income tax purposes for our 2020 taxable year. We do not anticipate being a PFIC for our 2021 taxable year. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any current, prior or future taxable year. If we were to become a PFIC for any taxable year during which a beneficial owner held shares or ADS, certain adverse consequences could apply to the U.S. Holder, including the imposition of higher amounts of tax than would otherwise apply, and additional filing requirements. In addition, if we were treated as a PFIC in a taxable year in which we pay a dividend or in the prior taxable year, the favorable dividend rates discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply (see “— Taxation of Distributions” above). U.S. Holders should consult their own tax advisors regarding the consequences to them if we were to become a PFIC and the availability and advisability of making any election that might mitigate the adverse consequences of PFIC status.

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Required Disclosure with Respect to Foreign Financial Assets

Certain U.S. Holders are required to report information relating to an interest in our shares or ADS, subject to certain exceptions (including an exception for our shares or ADS held in accounts maintained by certain financial institutions), by attaching a completed IRS Form 8938, Statement of Specified Foreign Financial Assets, with their tax return for each year in which they hold an interest in our shares or ADS. U.S. Holders are urged to consult their own U.S. tax advisors regarding information reporting requirements relating to their ownership of our shares or ADS.

Information Reporting and Backup Withholding

Payments of dividends and sales proceeds that are made within the United States or through certain U.S.- related financial intermediaries generally are subject to information reporting and to backup withholding unless: (i) the U.S. Holder is an exempt recipient or (ii) in the case of backup withholding, the beneficial owner provides a correct taxpayer identification number and certifies that the U.S. Holder is not subject to backup withholding.

The amount of any backup withholding from a payment to a beneficial owner will be allowed as a credit against the beneficial owner’s U.S. federal income tax liability and may entitle the U.S. Holder to a refund, provided that the required information is furnished in a timely fashion to the U.S. Internal Revenue Service.

Medicare Contribution Tax

A U.S. Holder that is an individual or estate, or a trust that does not meet certain requirements for an exemption, is subject to a tax of 3.8% on its “net investment income.” Among other items, net investment income generally includes gross income from dividends and net gain attributable to the disposition of certain property, like the shares or ADS, less certain deductions. A U.S. Holder should consult the holder’s own tax advisor regarding the applicability of the “net investment income” tax in respect of such beneficial owner’s particular circumstances.

U.S. Holders should consult their own tax advisors with respect to the particular consequences to them of owning or disposing of shares or ADS.

F. Dividends and Paying Agents.

Not applicable.

G. Statement by Experts.

Not applicable.

H. Documents on Display.

We are subject to the information requirements of the Exchange Act, except that as a foreign issuer, we are not subject to SEC proxy rules (other than general anti-fraud rules) or the short-swing profit disclosure rules of the Exchange Act. Under these statutory requirements, we file or furnish reports and other information with the SEC. Reports, information statements and other information we file with or furnish to the SEC are available electronically on the SEC’s website, which can be accessed at http://www.sec.gov and on our website www.enelchile.cl. Copies of such material may also be inspected at the offices of the New York Stock Exchange, at 11 Wall Street, New York, New York 10005, on which our ADS are listed.

I. Subsidiary Information.

For information on our principal subsidiaries, see “Item 4. Information on the Company — C. Organizational Structure — Principal Subsidiaries and Affiliates.”

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Item 11.      Quantitative and Qualitative Disclosures About Market Risk

We are exposed to risks arising from volatility in commodity prices, interest rates, and foreign exchange rates that affect the generation, distribution, and transmission businesses in Chile.

Commodity Price Risk

In our electricity generation business segment, we are exposed to market risks from the price volatility of electricity, natural gas, diesel oil, and coal. We seek to ensure our fuel supply by securing long-term contracts with our suppliers for periods expected to match our generation assets’ lifetime. These contracts generally have provisions that allow us to purchase natural gas with a pricing formula that combines Henry Hub natural gas and Brent diesel oil at market prices.

Enel Generation has designed a commercial policy that aligns sale commitment levels with its generation capacity during a dry year by including risk mitigation clauses with unregulated clients in some contracts to reduce risk under extreme drought conditions. In the case of regulated clients subject to long-term tender processes, indexed polynomials are determined to minimize commodity exposure.

Considering the operating conditions faced in the electricity generation market in Chile, drought, and the volatility of commodity prices in international markets, we continually evaluate if it is in our best interests to engage in hedging to mitigate the impact of price changes on profits.

As of December 31, 2020, we held the following swaps: 1,782 kBbl of Brent oil to be settled in 2021 and 16.8 TBtu of Henry Hub gas to be settled in 2021. As of December 31, 2019, we held the following swaps: 1,412 kTon of Coal API2 to be settled in 2020; 1,059 kBbl of Brent oil to be settled in 2020, and 4.79 TBtu of Henry Hub gas to be settled in 2020.

Depending on the operating conditions that are updated continuously, these hedging measures may be modified or included in other commodities.

We continually analyze strategies to hedge commodity price risk, including transferring commodity price variations to customers’ contract prices, permanently adjusting commodity indexed price formulas for new PPAs according to our exposure, or analyzing ways to mitigate risk through hydrological insurance in dry years. We may consider using price-sensitive instruments in the future.

Interest Rate and Foreign Currency Risk

As of December 31, 2020, the carrying values according to maturity and the corresponding fair value of our interest-bearing debt are detailed below. The amounts do not include derivatives. The rates in the table below are the result of the weighted average of the effective interest rates of each obligation, including expenses associated with financing and withholding taxes on interest payments related to financing obtained outside the country of domicile of each company.

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	Expected Maturity Date
For the year ended December 31,	2021	2022	2023	2024	2025	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
Fixed Rate
Ch$/UF	39	18	18	17	—	—	93	93
Weighted average interest rate	3.7%	5.8%	5.8%	6.2%	—	—	5.0%	n.a.
US$	2,647	24,146	147,374	399,049	114,669	1,451,070	2,138,954	2,452,335
Weighted average interest rate	6.5%	2.1%	2.8%	4.0%	2.9%	4.9%	4.4%	n.a.
Other currencies	455	649	649	649	649	4,395	7,446	7,446
Weighted average interest rate	4.8%	4.7%	4.7%	4.7%	4.7%	4.8%	4.8%	n.a.
Total fixed rate	3,141	24,813	148,041	399,715	115,318	1,455,465	2,146,493	2,459,875
Weighted average interest rate	6.2%	2.2%	2.9%	4.0%	3.0%	4.9%	4.5%	n.a.
Variable Rate
Ch$/UF	35,152	34,544	34,208	34,123	33,973	146,591	318,591	402,802
Weighted average interest rate	4.8%	4.8%	4.9%	4.9%	4.9%	4.7%	4.8%	n.a.
US$	106,643	284,380	—	—	—	—	391,023	391,023
Weighted average interest rate	2.9%	2.2%	—	—	—	—	2.4%	n.a.
Total variable rate	141,794	318,924	34,208	34,123	33,973	146,591	709,613	793,824
Weighted average interest rate	3.3%	2.5%	4.9%	4.9%	4.9%	4.7%	3.5%	n.a.
Total	144,935	343,738	182,249	433,837	149,291	1,602,056	2,856,107	3,253,699

(1) Calculated based on the Observed Exchange Rate as of December 31, 2020, which was Ch$ 710.95 per US$ 1.00.

(2) Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

As of December 31, 2019, the carrying values according to maturity and the corresponding fair value of our interest-bearing debt are detailed below. The amounts do not include derivatives. The rates in the table below are the result of the weighted average of the effective interest rates of each obligation, including expenses associated with

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financing and withholding taxes on interest payments related to financing obtained outside the country of domicile of each company.

	Expected Maturity Date
For the year ended December 31,	2020	2021	2022	2023	2024	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
Fixed Rate
Ch$/UF	1,950	1,728	1,410	1,399	1,399	21,653	29,539	29,539
Weighted average interest rate	2.7%	2.7%	3.1%	3.1%	3.1%	3.2%	3.1%	n.a.
US$	2,718	2,806	25,440	5,470	420,270	1,349,576	1,806,280	2,033,341
Weighted average interest rate	6.5%	6.5%	2.1%	6.5%	4.8%	5.8%	5.5%	n.a.
Other currencies	333	579	579	579	579	4,540	7,189	7,189
Weighted average interest rate	3.8%	3.8%	3.8%	3.8%	3.8%	3.8%	3.8%	n.a.
Total fixed rate	5,001	5,112	27,429	7,448	422,249	1,375,769	1,843,008	2,070,069
Weighted average interest rate	4.8%	4.9%	2.2%	5.6%	4.8%	5.8%	5.5%	n.a.
Variable Rate
Ch$/UF	31,625	31,625	31,625	31,625	31,625	153,594	311,718	421,668
Weighted average interest rate	7.9%	7.9%	7.9%	7.9%	7.9%	7.8%	7.8%	n.a.
US$	112,311	112,311	299,496	—	—	—	524,118	524,118
Weighted average interest rate	4.3%	4.5%	3.3%	—	—	—	3.8%	n.a.
Total variable rate	143,936	143,936	331,121	31,625	31,625	153,594	835,836	945,786
Weighted average interest rate	5.0%	5.2%	3.8%	7.9%	7.9%	7.8%	5.3%	n.a.
Total	148,937	149,048	358,549	39,073	453,873	1,529,364	2,678,844	3,015,854

(1) Calculated based on the Observed Exchange Rate as of December 31, 2019, which was Ch$ 748.74 per US$ 1.00.

(2) Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

Interest Rate Risk

Our policy aims to minimize the average cost of debt and reduce the volatility of our financial results. Depending on our estimates and the debt structure, we sometimes manage interest rate risk by using interest rate derivatives.

As of December 31, 2020, and 2019, 99% and 98% of our total outstanding debt had fixed interest rates, and 1% and 2%, respectively, were subject to variable interest rates. Because of the exposure to variable interest rate risks, we engage in derivative hedging instruments.

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As of December 31, 2020, the carrying values for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest-bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2021	2022	2023	2024	2025	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
Variable to fixed rates	106,643	284,380	—	—	—	—	391,023	(14,893)
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	106,643	284,380	—	—	—	—	391,023	(14,893)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2020, which was Ch$ 710.95 per US$ 1.00.

(2) Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

As of December 31, 2019, the carrying values for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest-bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2020	2021	2022	2023	2024	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
Variable to fixed rates	112,311	112,311	299,496	—	—	—	524,118	(7,411)
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	112,311	112,311	299,496	—	—	—	524,118	(7,411)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2019, which was Ch$ 748.74 per US$ 1.00.

(2) Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

Foreign Currency Risk

Our policy seeks to maintain a balance between the currencies in which cash flows are indexed and each company’s debt. Most of our subsidiaries have access to funding in the same currency as their revenues, reducing the exchange rate volatility impact. In some cases, we cannot fully benefit from this. Therefore, we try to manage the exposure with financial derivatives such as cross-currency swaps or currency forwards. However, this may not always be available under reasonable terms due to market conditions.

As of December 31, 2020, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest-bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2021	2022	2023	2024	2025	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
UF to US$	—	—	—	504,391	95,130	—	599,521	12,764
US$ to Ch$/UF	—	—	—	—	—	—	—	—
Ch$ to US$	—	—	—	—	—	—	—	—
Total	—	—	—	504,391	95,130	—	599,521	12,764

(1) Calculated based on the Observed Exchange Rate as of December 31, 2020, which was Ch$ 710.95 per US$ 1.00.

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(2) Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

As of December 31, 2019, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest-bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2020	2021	2022	2023	2024	Thereafter	Total	Fair Value(2)
	(in millions of Ch$)(1)
UF to US$	—	—	—	—	517,638	—	517,638	(9,530)
US$ to Ch$/UF	—	—	—	—	—	—	—	—
Ch$ to US$	—	—	—	—	—	—	—	—
Total	—	—	—	—	517,638	—	517,638	(9,530)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2019, which was Ch$ 748.74 per US$ 1.00.

(2) Fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

Please refer to Note 22 of the Notes to our consolidated financial statements for further detail.

(d) Safe Harbor

The information in this “Item 11. Quantitative and Qualitative Disclosures About Market Risk,” contains information that may constitute forward-looking statements. See “Forward-Looking Statements” in the Introduction of this Report for safe harbor provisions.

Item 12.      Description of Securities Other Than Equity Securities

A. Debt Securities.

Not applicable.

B. Warrants and Rights.

Not applicable.

C. Other Securities.

Not applicable.

D. American Depositary Shares.

Depositary Fees and Charges

Our ADS program’s Depositary is Citibank, N.A. The Depositary collects fees for delivery and surrender of ADS directly from investors depositing shares or surrendering ADS for withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. For non-cash distributions, the Depositary will invoice the applicable ADS record date holders. The Depositary may generally refuse to provide the requested services until its fees for those services are paid. Under the terms of the Deposit Agreement, an ADS holder may have to pay the following service fees to the Depositary:

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Service Fees	Fees
(1) Issuance of ADS upon deposit of shares (excluding issuances as a result of distributions described in paragraph (4) below)	Up to US$ 5 per 100 ADS (or fraction thereof) issued
(2) Delivery of deposited securities against surrender of ADS	Up to US$ 5 per 100 ADS (or fraction thereof) surrendered
(3) Distribution of cash dividends or other cash distributions (i.e., sale of rights and other entitlements)	Up to US$ 5 per 100 ADS (or fraction thereof) held
(4) Distribution of ADS pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADS	Up to US$ 5 per 100 ADS (or fraction thereof) held
(5) Distribution of securities other than ADS or rights to purchase additional ADS (i.e., a spin-off of shares)	Up to US$ 5 per 100 ADS (or fraction thereof) held
(6) Depositary services	Up to US$ 5 per 100 ADS (or fraction thereof) held on the applicable record date(s) established by the Depositary

The Depositary collects fees for delivery and surrender of ADS directly from investors depositing shares or surrendering ADS for withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. For non-cash distributions, the Depositary will invoice the applicable ADS record date holders, and such fees may be deducted from distributions.

Depositary Payments for Fiscal Year 2020

The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2020, the Depositary reimbursed us for expenses related primarily to investor relations’ activities for approximately US$ 1 million (after the deduction of applicable U.S. taxes).

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PART II

Item 13.      Defaults, Dividend Arrearages and Delinquencies

None.

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

None.

Item 15.      Controls and Procedures

(a) Disclosure Controls and Procedures

We carried out an evaluation under the supervision and with the participation of our senior management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2020.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, our disclosure controls and procedures are designed to provide reasonable assurance of achieving their control objectives.

Based upon our evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that, as a result of the material weakness in internal control over financial reporting as described below, our disclosure controls and procedures were not effective as of December 31, 2020. In light of the material weakness, management performed additional analysis and other procedures, and concluded that 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, in conformity with IFRS, as issued by the IASB.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with IFRS, as issued by the IASB.

Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that the controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim consolidated financial statements will not be prevented or detected on a timely basis.

The Company’s management, with participation of the Chief Executive Officer and the Chief Financial Officer, under the oversight of our Board of Directors, assessed the effectiveness of our internal control over financial reporting as of December 31, 2020 based on criteria established in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that the Company did not establish effective general information technology controls (GITCs), specifically program change controls, that support the consistent operation of the Company’s information technology (IT) operating system, database and IT application layers of technology over the electricity distribution business revenue process. These

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deficiencies also affected the effectiveness of business process automated controls, manual controls with an automated component, and the database of the reports that were used to execute certain automated and manual controls. As a result, we were unable to maintain effective control activities over the electricity distribution business revenue process. Furthermore, the control deficiencies described above created a reasonable possibility that a material misstatement to the consolidated financial statements would not be prevented or detected on a timely basis. Therefore, we concluded that the deficiencies represent a material weakness in the Company’s internal control over financial reporting and our internal control over financial reporting was not effective as of December 31, 2020.

The material weakness did not result in any identified misstatements to the Company’s consolidated financial statements and there were no changes to previously released financial results.

Our independent registered public accounting firm, KPMG Auditores Consultores SpA, who audited the consolidated financial statements included in this Annual Report on Form 20-F, issued an adverse opinion on the effectiveness of the Company’s internal control over financial reporting, which is on pages F-3 and F-4 of this Annual Report on Form 20-F.

(c) Management’s Remediation Plan

We are committed to making further progress in our remediation efforts during 2021. In order to remediate the material weakness described above, we have been implementing and will continue to implement actions to revise and enhance our GITCs to ensure, for the affected IT application, full enforcement of procedures related to the tracking of changes, including through (i) integrating the affected IT application with additional tools to improve the tracking of changes, (ii) additional training to increase awareness of control operators, and (iii) control design reviews related to the tracking of changes. 

The material weakness will not be considered remediated until the applicable controls have been fully designed, documented, implemented and operate for a sufficient period of time for management to conclude, through testing, that these controls are operating effectively.

(d) Changes in Internal Control Over Financial Reporting

Except as noted above with respect to the implementation of the remediation plan, there were no changes in our internal control over financial reporting identified in connection with the evaluation required by Rules 13a-15(d) or 15d-15(d) under the Exchange Act that occurred during 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We are in the process of implementing the remediation plan described above to address the identified material weakness in our internal control over financial reporting.

Item 16.      Reserved

Item 16A.      Audit Committee Financial Expert

As of December 31, 2020, the Directors Committee performs the Audit Committee’s functions, and the committee’s financial expert was Mr. Fernán Gazmuri P., as determined by the board of directors. Mr. Gazmuri is an independent member of the Directors Committee under the requirements of both Chilean law and NYSE corporate governance rules.

Item 16B.      Code of Ethics

Our standards of ethical conduct are governed using the following five corporate rulings or policies: the Code of Ethics, the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Human Rights Policy, the Manual for the Management of Information of Interest to the Market (the “Manual”) and the Diversity Policy.

The Manual, adopted by our board of directors, addresses the following issues: applicable standards and blackout periods regarding the information in connection with transactions of our securities or those of our affiliates, entered into

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by directors, management, principal executives, employees, and other related parties; the existence of mechanisms for the continuous disclosure of information that is of interest to the market; and procedures that protect confidential information.

In addition to the corporate governance rules described above, our board adopted the Code of Ethics, the ZTAC Plan, and the Human Rights Policy. The Code of Ethics is based on general principles such as impartiality, honesty, integrity, among others, translated into detailed behavioral criteria. The ZTAC Plan reinforces the Code of Ethics principles, emphasizing avoiding corruption such as bribes, preferential treatment, and other similar matters. The Human Rights Policy incorporates and adapts the general human rights principles championed by the United Nations into corporate reality.

The board of directors approved the Diversity Policy on August 30, 2016. This policy defines the key principles required to spread a culture focused on diversity and respect, preventing arbitrary discrimination, and encouraging equal opportunities and inclusion, all fundamental values in developing the Company’s activities. Through this policy, the Company seeks to improve the work environment and the quality of life. The Company is committed to creating an inclusive work environment where workers can develop their potential and maximize their contribution.

A copy of these documents is available on our webpage at www.enelchile.cl as well as upon request, free of charge, by writing or calling us at:

Enel Chile S.A.

Investor Relations Department

Av. Santa Rosa 76, Piso 15

Comuna de Santiago, Santiago, Chile

(56-2) 2353-4400

In the fiscal year 2020, there have been no amendments to any provisions of the documents described above. No waivers from any provisions of the Code of Ethics, the ZTAC Plan, or the Manual were expressly or implicitly granted to the Chief Executive Officer, the Chief Financial Officer, or any other senior financial officers in the fiscal year 2020.

Item 16C.      Principal Accountant Fees and Services

In 2020, our shareholders appointed KPMG Auditores Consultores SpA (“KPMG”) as the Company’s new independent registered public accounting firm to replace EY Audit SpA (“EY”).

The following table provides information on the aggregate fees for approved services billed by our independent registered accounting firm KPMG, EY, and their respective affiliates by type of service for the periods indicated.

Services Rendered	2020	2019
	(in millions of Ch$)
Audit fees	905	968
Audit-related fees	127	104
Tax fees	—	—
All other fees	—	—
Total	1,032	1,072

All the fees disclosed under audit-related fees and all other fees were pre-approved as required by the Directors Committee pre-approval policies and procedures.

The amounts included in the table above and the related footnotes have been classified in accordance with SEC guidance.

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Directors Committee Pre-Approval Policies and Procedures

Our shareholders appoint our external auditors at the OSM. Similarly, the shareholders of our subsidiaries appoint their external auditors according to applicable law and regulation.

The Directors Committee, which performs the functions of the Audit Committee, reviews engagement letters with external auditors, ensures quality control in respect of the services provided, reviews and controls independence issues and other related matters.

The Directors Committee has a pre-approval policy regarding the contracting of our external auditor, or any affiliate of the external auditor, for professional services. The professional services covered by such policy include audit and non-audit services provided to us.

Fees payable in connection with recurring audit services are pre-approved as part of our annual budget. Fees payable in connection with non-recurring audit services, once the Chief Financial Officer has examined them, are submitted to the Directors Committee for its final consideration.

The pre-approval policy established by the Directors Committee for non-audit services and audit-related fees is as follows:

● The business unit that has requested the service and the audit firm expected to perform the service must request that the Chief Financial Officer review the nature of the service to be provided.

● The Chief Financial Officer then analyzes the request and requires the selected audit firm to issue a certificate signed by the partner responsible for the audit of our consolidated financial statements confirming such an audit firm’s independence.

● Finally, the proposal is submitted to the Directors Committee for approval or denial.

The Directors Committee has designed, approved, and implemented the necessary procedures to fulfill the SEC requirements regarding the Audit Committee’s pre-approval of certain tax services.

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

Not applicable.

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

The following table sets forth, for each calendar month in 2020, the total number of shares of common stock purchased by the Company, or on the Company’s behalf, or by any affiliated purchaser, including Enel, the average price paid per share, and the number of shares purchased under a publicly announced plan or program.

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Purchases of Equity Securities

2020(1)	(a) Total Number Shares Purchased	(b) Average Price per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 1-31	—	—	—	—
February 1-29	—	—	—	—
March 1-31	—	—	—	—
April 1-30	—	—	—	—
May 1-31(2)	1,813,356,259	US$0.09	1,813,356,259	—
June 1-30	—	—	—	—
July 1-31(3)	261,640,450	US$0.07	261,640,450	—
August 1-31	—	—	—	—
September 1-30	—	—	—	—
October 1-31	—	—	—	—
November 1-30	—	—	—	—
December 1-31	—	—	—	—

(1) Reflects the settlement date of purchases.

(2) On December 5, 2019, Enel entered into two swap transactions relating to up to 1,763,747,209 shares of our common stock and up to 6,224,990 ADS. On May 5, 2020, Enel elected to settle the swap transaction for our common stock through an auction held on May 8, 2020. On May 12, 2020, Enel acquired 1,502,106,759 shares of our common stock at Ch$ 63.10 per share, and the swap transaction terminated. On May 13, 2020, Enel acquired 6,224,990 ADS at approximately US$ 4.59 per ADS, and the swap transaction terminated.

(3) On March 17, 2020, Enel entered into a second ADS swap transaction to acquire up to 5,232,809 ADS. On July 6, 2020, Enel acquired 5,232,809 ADS at approximately US$ 3.61 per ADS, and the swap transaction terminated.

As a result of the transactions described above, Enel increased its beneficial ownership in us from 61.9% as of December 31, 2019, to 64.9% as of December 31, 2020.

Item 16F.      Change in Registrant’s Certifying Accountant

There has been no change in independent accountants for the Company during the two most recent fiscal years or any subsequent interim period except as previously reported in the Company’s Annual Report on Form 20-F for the fiscal year ended December 31, 2019. There have been no disagreements required to be disclosed in Item 16F (b).

Item 16G.      Corporate Governance

Please see “Item 6. Directors, Senior Management and Employees — C. Board Practices” for a summary of the significant differences between our corporate governance practices and those applicable to domestic issuers under the corporate governance rules of the NYSE.

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Item  16H.      Mine Safety Disclosure

Not applicable.

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PART III

Item  17.      Financial Statements

Not Applicable.

Item   18.      Financial Statements

Enel Chile

Index to the Audited Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firms:

Report of KPMG Auditores Consultores SpA at December 31, 2020	F-1
Report of KPMG Auditores Consultores SpA – Enel Chile S.A. — Internal Control Over Financial Reporting 2020	F-3
Report of EY Audit S.p.A. – Enel Chile S.A. at December 31, 2019, and 2018	F-F-5
Consolidated Financial Statements:
Consolidated Statements of Financial Position at December 31, 2020, and 2019	F-8
Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019, and 2018	F-10
Consolidated Statements of Changes in Equity for the years ended December 31, 2020, 2019, and 2018	F-12
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019, and 2018	F-13
Notes to the Consolidated Financial Statements	F-14
Ch$          Chilean pesos
US$          U.S. dollars
UF            The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
ThCh$      Thousands of Chilean pesos
ThUS$      Thousands of U.S. dollars
EUREuro

Item  19.    Exhibits

Exhibit	Description
1.1	By-laws (Estatutos) of Enel Chile S.A. filed as Exhibit 1.1 to Enel Chile S.A.’s Annual Report on Form 20-F for the year ended December 31, 2019, is incorporated herein by reference.
2.1	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934.
8.1	List of Subsidiaries as of December 31, 2020.
12.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
12.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
13.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

We will furnish to the Securities and Exchange Commission, upon request, copies of any not filed instruments that define the rights of stakeholders of Enel Chile.

138

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	ENEL CHILE S.A.
	By:	/s/ Paolo Pallotti
	Name:	Paolo Pallotti
	Title:	Chief Executive Officer
Date: April 29, 2021

139

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Enel Chile S.A.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statement of financial position of Enel Chile S.A. and subsidiaries (the Company) as of December 31, 2020, the related consolidated statements of comprehensive income, changes in equity, and cash flows for the year ended December 31, 2020, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020, and the results of its operations and its cash flows for the year ended December 31, 2020, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated April 29, 2021 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-1

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Unbilled revenue

As discussed in Notes 3q and 28 to the consolidated financial statements, revenue from sales to customers includes estimates of energy provided and not billed as of December 31, 2020, amounting to ThCh$434,442,879 related to the distribution and generation entities in Chile. These estimates are made based on the quantity of energy consumed by customers during the period, at the prices stipulated in the electricity tariffs in accordance with the current regulation or, if applicable, contractual arrangements with customers.

We identified the revenue recognition of energy provided and not invoiced as a critical audit matter due to  the auditor judgment required to assess the complexity of the non-standardized determination of energy consumed by customers and the calculation of price formulas established in the contracts and regulations. In addition, auditor judgment was required to assess the adequacy of the nature and extent of the audit evidence obtained.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the unbilled revenue process for the generation entities. This included controls related to:

• the price used for estimation of unbilled sales to customers

• inputs used to estimate the quantity of energy consumed by customers, such as energy purchased from the Company and the customer´s historical consumption information, including the energy consumption by customers in the previous month

• the comparison between the estimate of unbilled revenue at the end of the month versus the actual volume of energy subsequently measured and billed to customers (back-testing) for the generation entities.

We compared the volume used in the estimate of unbilled revenue at the end of the year versus the actual volume of energy subsequently measured and billed to customers (back-testing) or to external data provided by the local regulator, as applicable. We reassessed a sample of the price used to calculate the unbilled sales to customers based on current contracts and decrees issued by the local regulator. We evaluated the reconciliation of the sales ledger to the actual sales report as of year end. In addition, we assessed the sufficiency of the nature and extent of the audit evidence obtained, as well as the Company’s disclosures of this matter in Note 28 to the consolidated financial statements.

/s/ KPMG

KPMG Auditores Consultores SpA

We have served as the Company’s auditor since 2020.

Santiago, Chile

April 29, 2021

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-2

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Enel Chile S.A.:

Opinion on Internal Control Over Financial Reporting

We have audited Enel Chile S.A. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, because of the effect of the material weakness, described below, on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statement of financial position of the Company as of December 31, 2020, the related consolidated statements of comprehensive income, changes in equity, and cash flows for the year ended December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated April 29, 2021 expressed an unqualified opinion on those consolidated financial statements.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. The Company did not establish effective general information technology controls, specifically program change controls, that support the consistent operation of the Company’s information technology (IT) operating system, database, and IT application layers of technology over the electricity distribution business revenue process. These deficiencies also affected the effectiveness of business process automated controls, manual controls with an automated component, and the database of the reports that were used to execute certain automated and manual controls.

The material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2020 consolidated financial statements, and this report does not affect our report on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-3

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG

KPMG Auditores Consultores SpA

Santiago, Chile

April 29, 2021

KPMG Auditores Consultores SpA, a Chilean joint-stock company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. All rights reserved.

F-4

.

EY Chile Avda. Presidente Riesco 5435, piso 4, Las Condes, Santiago Tel: +56 (2) 2676 1000 www.eychile.cl

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Enel Chile S.A.

Opinion on the Financial Statements

We have audited the accompanying consolidated statement of financial position of Enel Chile S.A. and subsidiaries (the Company) as of December 31, 2019, the related consolidated statements of comprehensive income, shareholders' equity and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

F-5

Goodwill Impairment Test

Description of the Matter

As of December 31, 2019, the Company’s consolidated financial statements present goodwill in the amount of Ch$917.35 billion. As discussed in Note 3 c) to the consolidated financial statements, goodwill is tested for impairment at least annually at the reporting unit level. The Company’s goodwill is initially assigned to its reporting units as of the acquisition date using a relative fair value allocation. The impairment tests require management to use significant assumptions to determine the fair value of the related reporting unit. Those assumptions are described in Note 3 e) to the Company´s consolidated financial statements, and include market evolution, future price estimations, discount rates and the consideration of risks specific to the relevant cash generating unit.

Auditing the Company´s goodwill impairment test is complex due to the significant estimation uncertainties involved in determining the fair values of the reporting units. Those fair value estimates are sensitive to changes in significant assumptions such as discount rate and projected cash flows that are affected by future market or economic conditions.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the goodwill impairment test. For example, we tested controls over the significant assumptions, such as discount rate and projected cash flows, used in the valuation process.

To test the fair values ​​of the reporting units, our audit procedures included, among others, evaluating the methodologies used by the Company with the assistance of our valuation specialists; testing the significant assumptions used to develop the prospective financial information; comparing those significant assumptions to historical results of the Company's business; benchmarking those assumptions against market participant data within the same industry and performing an independent calculation of the discount rate considering market information about the cost of capital from comparable energy companies.

We also evaluated the Company’s disclosure of this matter in Note 15 to the consolidated financial statements.

Effect of the 2019 Price Stabilization Law

Description of the Matter

As described in Notes 4 b) and 11 to the consolidated financial statements, the Company recognized revenues in the amount of Ch$182.07 billion and a corresponding payable to suppliers for energy purchases in the amount of Ch$53.94billion, as a result of a new law came into force corresponding to the price stabilization mechanism (PEC in Spanish), which caused delays in the billing process of the price adjustments and requires the use of significant assumptions and judgment by management to assess the financial and accounting effects.

Auditing the amounts related to the effects of the PEC is complex due to the significant effort to evaluate the effects of the tariff decrees and sales contracts as well as the judgment used to determine the present value of the unbilled revenue due to the entry into force of the PEC law.

F-6

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the effects of the PEC. For example, we tested controls over the prices obtained from the sales contracts and tariff decrees related to the significant assumptions, such as discount rate and estimated recovery date used to calculate the unbilled revenue and supplier accrual associated with the PEC.

To test the amounts resulting from the effects of the PEC by recalculating the prices of sales contracts; comparing significant inputs used by management, such as the future price of coal, gas, oil, forward US Dollar exchange rates, as well as the Consumer Price Index (CPI) with the tariff decrees issued by the regulator; comparing the energy price used in the sales contracts with the price obtained from the regulator; recalculating the estimation of unbilled energy already provided to customers, and involving our valuation specialist to assist in the evaluating the discount rate used by the Company to compute the present value of future price adjustments related to customers subject to the PEC.

We also evaluated the financial statements disclosures included in the Notes 4 b) and 9.

/s/ EY Audit SpA.                

EY Audit SpA.

We served as the Company’s auditor from 2011 to 2020.

Santiago, Chile

April 29, 2020

F-7

ENEL CHILE S.A.

Consolidated Statements of Financial Position

As of December 31, 2020 and 2019

(In thousands of Chilean pesos – ThCh$)

		12-31-2020	12-31-2019
ASSETS	Note	ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	6	332,036,013	235,684,500
Other current financial assets	7	3,352,404	1,310,595
Other current non-financial assets	8.a	19,801,573	34,634,563
Trade and other receivables, current	9	554,886,639	511,455,330
Current accounts receivable from related parties	10	57,976,125	68,182,133
Inventories	11	23,310,029	39,672,250
Current tax assets	12	35,038,413	127,273,289
TOTAL CURRENT ASSETS		1,026,401,196	1,018,212,660
NON-CURRENT ASSETS
Other non-current financial assets	7	20,660,450	7,220,620
Other non-current non-financial assets	8.a	65,787,215	38,050,184
Trade and other non-current receivables	9	445,016,566	313,574,385
Non-current accounts receivable from related parties	10	48,358,915	34,407,142
Investments accounted for using the equity method	13	12,992,803	7,928,588
Intangible assets other than goodwill	14	165,114,521	132,278,593
Goodwill	15	915,705,369	917,352,974
Property, plant and equipment	16	5,033,496,472	5,304,476,114
Investment property	17	7,421,940	6,795,155
Right-of-use assets	18	55,502,192	55,843,510
Deferred tax assets	19.b	108,013,945	21,848,239
TOTAL NON-CURRENT ASSETS		6,878,070,388	6,839,775,504
TOTAL ASSETS		7,904,471,584	7,857,988,164

The accompanying notes are an integral part of these consolidated financial statements.

F-8

ENEL CHILE S.A.

Consolidated Statements of Financial Position (continued)

As of December 31, 2020 and 2019

(In thousands of Chilean pesos – ThCh$)

		12-31-2020	12-31-2019
LIABILITIES AND EQUITY	Note	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	20	157,499,141	208,814,561
Current lease liabilities	21	7,007,711	5,842,015
Trade and other payables, current	24	627,958,022	599,263,208
Current accounts payable to related parties	10	130,053,962	159,809,887
Other current provisions	25	3,434,804	4,065,965
Current tax liabilities	12	72,359,944	17,995,833
Other current non-financial liabilities	8.b	47,166,581	45,508,383
TOTAL CURRENT LIABILITIES		1,045,480,165	1,041,299,852
NON-CURRENT LIABILITIES
Other non-current financial liabilities	20	1,483,589,126	1,692,604,245
Non-current lease liabilities	21	44,857,807	47,565,674
Trade and other payables non-current	24	117,210,059	56,250,085
Non-Current accounts payable to related parties	10	1,164,044,462	784,373,484
Other long-term provisions	25	210,241,671	171,860,282
Deferred tax liabilities	19.b	168,057,562	249,284,641
Non-current provisions for employee benefits	26	75,538,265	66,163,490
Other non-current non-financial liabilities	8.b	1,177,968	1,302,759
TOTAL NON-CURRENT LIABILITIES		3,264,716,920	3,069,404,660
TOTAL LIABILITIES		4,310,197,085	4,110,704,512
EQUITY
Share and paid-in capital	27.1	3,882,103,470	3,882,103,470
Retained earnings		1,747,437,805	2,008,103,651
Other reserves	27.5	(2,277,625,485)	(2,405,509,135)
Equity attributable to Enel Chile		3,351,915,790	3,484,697,986
Non-controlling interests	27.6	242,358,709	262,585,666
TOTAL EQUITY		3,594,274,499	3,747,283,652
TOTAL LIABILITIES AND EQUITY		7,904,471,584	7,857,988,164

The accompanying notes are an integral part of these consolidated financial statements.

F-9

ENEL CHILE S.A.

Consolidated Statements of Comprehensive Income, by Nature

For the years ended December 31, 2020, 2019 and 2018

(In thousands of Chilean pesos – ThCh$)

		2020	2019	2018
STATEMENTS OF PROFIT (LOSS)	Note	ThCh$	ThCh$	ThCh$
Revenues	28	2,548,384,317	2,624,576,323	2,410,360,459
Other operating income	28	37,017,880	146,258,037	46,800,967
Revenues and other operating income		2,585,402,197	2,770,834,360	2,457,161,426
Raw materials and consumables used	29	(1,374,445,639)	(1,421,205,251)	(1,292,177,116)
Contribution Margin		1,210,956,558	1,349,629,109	1,164,984,310
Other work performed by the entity and capitalized	16.b.2	25,539,316	17,610,861	16,710,963
Employee benefits expense	30	(137,226,748)	(129,604,956)	(123,130,334)
Depreciation and amortization expense	31.a	(229,957,019)	(236,627,387)	(215,187,300)
Reversal of impairment losses (impairment losses) recognized on non-financial assets	31.b	(697,806,441)	(280,762,652)	(779,825)
Profit from impairment and reversal of impairment losses (impairment losses) determined in accordance with IFRS 9	31.b	(15,167,707)	(10,047,000)	(4,783,072)
Other expenses, by nature	32	(190,593,334)	(184,143,140)	(167,210,021)
Operating Income		(34,255,375)	526,054,835	670,604,721
Other gains	33	9,488,815	1,793,201	3,410,379
Financial income	34	36,160,460	27,399,275	19,934,468
Financial costs	34	(127,408,771)	(164,897,900)	(122,184,189)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	13	3,509,392	366,089	3,190,240
Foreign currency exchange differences	34	(23,272,231)	(10,412,110)	(7,807,197)
Gains or loss from indexed assets and liabilities, net (*)	34	2,085,768	(2,982,268)	(818,146)
(Loss) Profit before taxes		(133,691,942)	377,321,122	566,330,276
Income tax expense	19.a	81,305,107	(61,227,904)	(153,482,519)
(LOSS) PROFIT		(52,386,835)	316,093,218	412,847,757
(Loss) Profit attributable to
(Loss) Profit attributable to owners of the parent		(50,860,313)	296,153,605	361,709,937
(Loss) Profit attributable to non-controlling interests	27.6	(1,526,522)	19,939,613	51,137,820
(Loss) Profit		(52,386,835)	316,093,218	412,847,757
Basic earnings per share
Basic (losses) earnings per share	Ch$/Share	(0.74)	4.28	5.66
Weighted average number of outstanding shares		69,166,557,220	69,166,557,220	63,913,359,484
Diluted earnings per share
Basic (losses) earnings per share	Ch$/Share	(0.74)	4.28	5.66
Weighted average number of outstanding shares		69,166,557,220	69,166,557,220	63,913,359,484

(*) Includes Argentina’s hyperinflationary effect (see Note 7).

The accompanying notes are an integral part of these consolidated financial statements.

F-10

ENEL CHILE S.A.

Consolidated Statements of Comprehensive Income, by Nature (continued)

For the years ended December 31, 2020, 2019 and 2018

(In thousands of Chilean pesos – ThCh$)

		2020	2019	2018
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	Note	ThCh$	ThCh$	ThCh$
Gains (losses)		(52,386,835)	316,093,218	412,847,757
Components of other comprehensive income that will not be reclassified subsequently to profit or loss, before taxes
(Loss) Profit from defined benefit plans	26.2.b	(8,545,834)	(7,777,204)	37,881
Other comprehensive loss that will not be reclassified subsequently to profit or loss		(8,545,834)	(7,777,204)	37,881
Components of other comprehensive income that will be reclassified subsequently to profit or loss, before taxes
(Losses) Gains from foreign currency translation difference		(69,218,245)	73,114,966	107,492,316
Losses on measuring Financial Asset at Fair Value of Other Comprehensive Income		(9,125)	(3,673)	(411)
Share of other comprehensive income (loss) from associates and joint ventures accounted for using the equity method	13.1.a	18,982	—	—
Gains (losses) from cash flow hedges		208,749,917	(160,828,497)	(244,271,689)
Adjustments from reclassification of cash flow hedges, transferred to profit or loss		58,790,411	21,654,376	22,364,834
Other comprehensive income that will be reclassified subsequently to profit or loss		198,331,940	(66,062,828)	(114,414,950)
Total components of other comprehensive income (loss) before taxes		189,786,106	(73,840,032)	(114,377,069)
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss
Income tax related to defined benefit plans		2,308,510	2,099,845	(10,228)
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss		2,308,510	2,099,845	(10,228)
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss
Income tax related to cash flow hedge		(72,741,119)	36,883,401	60,650,786
Income tax related to financial assets at fair value of other comprehensive income		2,464	992	111
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss		(72,738,655)	36,884,393	60,650,897
Total Other Comprehensive Income (Loss)		119,355,961	(34,855,794)	(53,736,400)
TOTAL COMPREHENSIVE INCOME		66,969,126	281,237,424	359,111,357
Comprehensive income (loss) attributable to:
Shareholders of Enel Chile		68,669,685	255,988,200	297,410,542
Non-controlling interests		(1,700,559)	25,249,224	61,700,815
TOTAL COMPREHENSIVE INCOME		66,969,126	281,237,424	359,111,357

The accompanying notes are an integral part of these consolidated financial statements.

F-11

ENEL CHILE S.A.

Consolidated Statements of Changes in Equity

For the years ended December 31, 2020, 2019 and 2018

(In thousands of Chilean pesos – ThCh$)

5
			Changes in Other Reserves
	Share and Paid-in Capital (1)	Treasury Shares	Translation Reserve (2)	Reserve for Cash Flow Hedges	Reserve for Defined Benefit Plans	Reserve for Gains and Losses on measuring Financial Asset at Fair Value of Other Comprehensive Income	Other Miscellaneous Reserves	Total Other Reserves (3)	Retained Earnings	Equity attributable to owners of the parent to Shareholders of Enel Chile	Non-Controlling Interests (4)	Total Equity
Consolidated Statement of Changes in Equity	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Equity at beginning of period 1-1-2020	3,882,103,470	—	166,116,569	(291,006,520)	—	8,384	(2,280,627,568)	(2,405,509,135)	2,008,103,651	3,484,697,986	262,585,666	3,747,283,652
Changes in equity						—	—	—	—	—	—	—
Comprehensive income	—	—	—	—	—	—	—	—	—	—	—	—
Profit (loss)	—	—	—	—	—	—	—	—	(50,860,313)	(50,860,313)	(1,526,522)	(52,386,835)
Other comprehensive income (loss)	—	—	(62,466,476)	188,060,425	(6,076,332)	(6,601)	18,982	119,529,998	—	119,529,998	(174,037)	119,355,961
Comprehensive income	—	—	—	—	—	—	—	—	—	68,669,685	(1,700,559)	66,969,126
Dividends	—	—	—	—	—	—	—	—	(203,729,201)	(203,729,201)	(18,163,142)	(221,892,343)
Increase (decrease) from other changes	—	—	—	—	6,076,332	—	2,277,320	8,353,652	(6,076,332)	2,277,320	(363,256)	1,914,064
Total changes in equity	—	—	(62,466,476)	188,060,425	—	(6,601)	2,296,302	127,883,650	(260,665,846)	(132,782,196)	(20,226,957)	(153,009,153)
Equity at end of period 12-31-2020	3,882,103,470	—	103,650,093	(102,946,095)	—	1,783	(2,278,331,266)	(2,277,625,485)	1,747,437,805	3,351,915,790	242,358,709	3,594,274,499

			Changes in Other Reserves
	Share and Paid-in Capital (1)	Treasury Shares	Translation Reserve (2)	Reserve for Cash Flow Hedges	Reserve for for Defined Benefit Plans	Reserve for Gains and Losses on measuring Financial Asset at Fair Value of Other Comprehensive Income	Other Miscellaneous Reserves	Total Other Reserves (3)	Retained Earnings	Equity attributable to owners of the parent to Shareholders of Enel Chile	Non-Controlling Interests (4)	Total Equity
Statements of Changes in Equity	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Equity at beginning of period 1-1-2019	3,954,491,479	(72,388,009)	101,654,836	(191,870,545)	—	11,041	(2,285,467,896)	(2,375,672,564)	1,914,797,613	3,421,228,519	252,935,262	3,674,163,781
Changes in equity
Comprehensive income
Profit (loss)	—	—	—	—	—	—	—	—	296,153,605	296,153,605	19,939,613	316,093,218
Other comprehensive income (loss)	—	—	64,461,733	(99,135,975)	(5,488,506)	(2,657)	—	(40,165,405)	—	(40,165,405)	5,309,611	(34,855,794)
Comprehensive income	—	—	—	—	—	—	—	—	—	255,988,200	25,249,224	281,237,424
Dividends	—	—	—	—		—		—	(197,359,062)	(197,359,062)	(16,578,349)	(213,937,411)
Increase (decrease) from other changes	(72,388,009)	72,388,009	—	—	5,488,506	—	4,840,328	10,328,834	(5,488,505)	4,840,329	979,529	5,819,858
Total changes in equity	(72,388,009)	72,388,009	64,461,733	(99,135,975)	—	(2,657)	4,840,328	(29,836,571)	93,306,038	63,469,467	9,650,404	73,119,871
Equity at end of period 12-31-2019	3,882,103,470	—	166,116,569	(291,006,520)	—	8,384	(2,280,627,568)	(2,405,509,135)	2,008,103,651	3,484,697,986	262,585,666	3,747,283,652

			Changes in Other Reserves
Consolidated Statement of Changes in Equity	Share and Paid-in Capital (1)	Treasury Shares	Translation Reserve (2)	Reserve for Cash Flow Hedges	Reserve for for Defined Benefit Plans	Reserve for Gains and Losses on measuring Financial Asset at Fair Value of Other Comprehensive Income	Other Miscellaneous Reserves	Total Other Reserves (3)	Retained Earnings	Equity attributable to owners of the parent to Shareholders of Enel Chile	Non-Controlling Interests (4)	Total Equity
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Equity at beginning of period 01/01/18	2,229,108,975	—	6,976,383	(32,849,736)	—	11,284	(971,468,479)	(997,330,548)	1,751,605,583	2,983,384,010	803,577,647	3,786,961,657
Increase (decrease) due changes in accounting policies (5)									(2,702,470)	(2,702,470)	(44,691)	(2,747,161)
Equity at beginning of period 1/1/2018 (As Restated)	2,229,108,975	—	6,976,383	(32,849,736)	—	11,284	(971,468,479)	(997,330,548)	1,748,903,113	2,980,681,540	803,532,956	3,784,214,496
Changes in equity
Comprehensive income:
Profit (loss)	—	—	—	—	—	—	—	—	361,709,937	361,709,937	51,137,820	412,847,757
Other comprehensive income (loss)	—	—	94,678,453	(159,020,809)	43,204	(243)	—	(64,299,395)	—	(64,299,395)	10,562,995	(53,736,400)
Comprehensive income	—	—	—	—	—	—	—	—	—	297,410,542	61,700,815	359,111,357
Share issuance	1,725,382,504	—	—	—	—	—	—	—	—	1,725,382,504	—	1,725,382,504
Dividends	—	—	—	—	—	—	—	—	(195,858,641)	(195,858,641)	(19,603,211)	(215,461,852)
Increase (decrease) from other changes	—	—	—	—	(43,204)	—	(403,562,193)	(403,605,397)	43,204	(403,562,193)	92,644,186	(310,918,007)
Increase (decrease) due to portfolio transactions	—	(72,388,009)	—	—	—	—	—	—	—	(72,388,009)	—	(72,388,009)
Increase (decrease) due to changes in subsidiary interests that do not lead to loss of control	—	—	—	—	—	—	(910,437,224)	(910,437,224)	—	(910,437,224)	(685,339,484)	(1,595,776,708)
Total changes in equity	1,725,382,504	(72,388,009)	94,678,453	(159,020,809)	—	(243)	(1,313,999,417)	(1,378,342,016)	165,894,500	440,546,979	(550,597,694)	(110,050,715)
Equity at end of period 12-31-2018	3,954,491,479	(72,388,009)	101,654,836	(191,870,545)	—	11,041	(2,285,467,896)	(2,375,672,564)	1,914,797,613	3,421,228,519	252,935,262	3,674,163,781

(1) See Note 27.1

(2) See Note 27.3

(3) See Note 27.5

(4) See Note 27.6

(5) Considers a charge in results for ThCh$3,411,631 due to application of IFRS 9 and a credit to retained earnings for ThCh$664,470 due to application of IAS 29, see notes 22.2 – Impairment – and 2.7.4, respectively.

The accompanying notes are an integral part of these consolidated financial statements

F-12

ENEL CHILE S.A.

Consolidated Statements of Cash Flows, Direct

For the years ended December 31, 2020, 2019 and 2018

		2020	2019	2018
Statements of Cash Flows - Direct Method	Note	ThCh$	ThCh$	ThCh$
Cash flows from (used in) operating activities
Types of collection from operating activities
Collections from the sale of goods and services		2,961,814,449	3,053,366,631	3,037,830,501
Collections from premiums and services, annual payments, and other obligations from policies held		6,846,414	30,131,403	9,201,388
Receipts from rents and subsequent sales of such assets		102,436,230	7,938,954	—
Other collections from operating activities		16,403,356	929,839	23,353,592
Types of payment in cash from operating activities
Payments to suppliers for goods and services		(1,935,080,572)	(1,923,705,670)	(1,921,809,622)
Payments to and on behalf of employees		(140,378,194)	(130,102,939)	(119,944,410)
Payments of premiums and services, annual payments, and other obligations from policies held		(25,114,326)	(16,828,690)	(15,704,586)
Payments to manufacture or acquire assets held for rental to others and subsequently held for sale		(56,489,776)	(39,625,028)	—
Other payments for operating activities		(170,290,593)	(154,500,049)	(137,352,099)
Cash flows from (used in) operating activities
Income taxes paid		(1,342,494)	(82,778,533)	(134,512,945)
Other cash outflows, net		(2,938,296)	(1,114,199)	(5,536,297)
Net cash flows from operating activities		755,866,198	743,711,719	735,525,522
Cash flows from (used in) investing activities
Cash flows from the loss or gains of control of subsidiaries or other businesses, net		—	—	(1,624,326,739)
Other collections from the sale of equity and debt instruments of other entities		(2,769,624)	(130,639)	—
Loans to related companies		—	—	(37,940,159)
Proceeds from the sale of property, plant and equipment		—	872,988	4,640,835
Purchases of property, plant and equipment		(514,807,265)	(300,346,362)	(300,538,836)
Purchases of intangible assets		(39,506,950)	(20,732,156)	—
Payments for future, forward, option and swap contracts		(3,260,921)	(7,551,080)	(1,475,713)
Collections from future, forward, option and swap contracts		22,229	2,737,887	352,734
Collections from related companies		—	—	76,307,192
Dividends received		—	6,455,840	1,520,979
Interest received		5,671,141	6,034,028	6,653,972
Other inflows (outflows) of cash		—	1,127,683	(6,753,959)
Net cash flows used in investing activities		(554,651,390)	(311,531,811)	(1,881,559,694)
Cash flows from (used in) financing activities
Payments proceeds from share Issuance		—	—	665,829,207
Payments for acquiring treasury shares	27.1.2	—	—	(72,388,009)
Payments for other equity interests		(519,943)	—	—
Proceeds from long-term loans	6.d	—	—	1,565,782,604
Loans from related companies	6.d	484,520,001	283,831,505	—
Payments of loans	6.d	(150,878,247)	(315,323,464)	(819,525,929)
Payments of borrowings and lease liabilities	6.d	(4,940,582)	(4,498,202)	(1,889,685)
Dividends paid		(312,714,789)	(236,478,649)	(231,392,743)
Interest paid	6.d	(139,251,404)	(134,429,754)	(116,540,891)
Other outflows of cash, net	6.d	(3,884,370)	(33,537,124)	(23,297,678)
Net cash flows from (used in) financing activities		(127,669,334)	(440,435,688)	966,576,876
Net increase (decrease) in cash and cash equivalents before effect of exchange rate changes		73,545,474	(8,255,780)	(179,457,296)
Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents		22,806,039	(1,231,644)	5,173,194
Net increase (decrease) in cash and cash equivalents		96,351,513	(9,487,424)	(174,284,102)
Cash and cash equivalents at beginning of year	6	235,684,500	245,171,924	419,456,026
Cash and cash equivalents at end of year	6	332,036,013	235,684,500	245,171,924

The accompanying notes are an integral part of these consolidated financial statements.

F-13

ENEL CHILE S.A

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contents	Page
1. BACKGROUND AND BUSINESS ACTIVITIES	F-17
2. BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS.	F-18
2.1 Basis of preparation	F-18
2.2 New accounting pronouncements	F-18
2.3 Responsibility for the information, judgments and estimates provided	F-23
2.4 Subsidiaries	F-25
2.4.1 Changes in the scope of consolidation	F-26
2.5 Investment in associates	F-26
2.6 Investment in joint arrangements	F-27
2.7 Basis of consolidation and business combinations	F-27
3. ACCOUNTING POLICIES APPLIED.	F-30
a) Property, plant and equipment	F-30
b) Investment property	F-31
c) Goodwill	F-32
d) Intangible assets other than goodwill	F-32
d.1) Research and development expenses	F-32
d.2) Other intangible assets	F-32
e) Impairment of non-financial assets	F-33
f) Leases	F-34
g) Financial instruments	F-36
g.1) Financial assets other than derivatives	F-36
g.2) Cash and cash equivalents	F-37
g.3) Impairment of financial assets	F-37
g.4) Financial liabilities other than derivatives	F-38
g.5) Derivative financial instruments and hedge accounting	F-38
g.6) Derecognition of financial assets and liabilities	F-40
g.7) Offsetting financial assets and liabilities.	F-40
g.8) Financial guarantee contracts	F-40
h) Measurement of fair value	F-40
i) Investments accounted for using the equity method	F-41
j) Inventories	F-42
k) Non-current assets (or disposal group of assets) held for sale or held for distribution to owners and discontinued operations	F-42
l)Treasury shares	F-43
m) Provisions	F-43
m.1) Provisions for post-employment benefits and similar obligations	F-44
n) Translation of foreign currency balances	F-44
o) Current/non-current classification	F-44
p) Income taxes	F-44
q) Revenue and expense recognition	F-45
r) Earnings per share	F-47
s) Dividends	F-47
t) Share issuance costs	F-47
u) Statement of cash flows	F-48
4. SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS.	F-48
a) Regulatory framework:	F-48
a.1 Generation Segment	F-49
a.2. Transmission Segment	F-50
a.3 Distribution segment	F-50
b) Regulatory Developments in 2019	F-51
c) Tariff Revisions:	F-55
5. BUSINESS COMBINATION UNDER COMMON CONTROL.	F-58
6. CASH AND CASH EQUIVALENTS.	F-60
7. OTHER FINANCIAL ASSETS.	F-61

F-14

8. OTHER NON-FINANCIAL ASSETS AND LIABILITIES.	F-61
9. TRADE AND OTHER RECEIVABLES.	F-63
10. BALANCES AND TRANSACTIONS WITH RELATED PARTIES.	F-67
10.1 Balances and transactions with related parties	F-68
10.2 Board of Directors and key management personnel	F-71
10.3 Compensation for key management personnel	F-73
10.4 Incentive plans for key management personnel	F-74
10.5 Compensation plans linked to share price	F-74
11. INVENTORIES.	F-74
12. CURRENT TAX ASSETS AND LIABILITIES.	F-75
13. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD.	F-76
13.1. Investments accounted for using the equity method	F-76
13.2. Investments with significant influence	F-77
13.3. Joint ventures	F-77
14. INTANGIBLE ASSETS OTHER THAN GOODWILL.	F-78
15. GOODWILL.	F-79
16. PROPERTY, PLANT AND EQUIPMENT.	F-81
17. INVESTMENT PROPERTY.	F-85
18. RIGHT-OF-USE-ASSETS.	F-86
19. INCOME TAX AND DEFERRED TAXES.	F-88
20. OTHER FINANCIAL LIABILITIES.	F-92
20.1 Interest-bearing borrowings	F-92
20.2 Unsecured liabilities	F-94
20.3 Secured liabilities	F-95
20.4 Hedged debt	F-95
20.5 Other information	F-96
20.6 Future Undiscounted debt flows.	F-96
21. LEASE LIABILITIES.	F-97
22. RISK MANAGEMENT POLICY.	F-100
22.1 Interest rate risk	F-100
22.2 Exchange rate risk	F-100
22.3 Commodities risk	F-101
22.4 Liquidity risk	F-101
22.5 Credit risk	F-102
22.6 Risk measurement	F-102
23. FINANCIAL INSTRUMENTS.	F-103
23.1 Financial instruments, classified by type and category	F-103
23.2 Derivative instruments	F-104
23.3 Fair value hierarchy	F-106
24. TRADE AND OTHER CURRENT PAYABLES.	F-107
25. PROVISIONS.	F-107
26. EMPLOYEE BENEFIT OBLIGATIONS.	F-108
26.1 General information	F-108
26.2 Details, changes and presentation in financial statements	F-109
26.3 Other disclosures	F-110
27. EQUITY.	F-112
27.1 Equity attributable to the shareholders of Enel Chile	F-112
27.2 Dividends	F-113
27.3 Foreign currency translation reserves	F-114
27.4 Restrictions on consolidated subsidiaries transferring funds to the parent	F-114
27.5 Other reserves	F-114
27.6 Non-controlling Interests	F-116
28. REVENUE AND OTHER OPERATING INCOME.	F-117
29. RAW MATERIALS AND CONSUMABLES USED.	F-118
30. EMPLOYEE BENEFITS EXPENSE.	F-118
31. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES.	F-119
32. OTHER EXPENSES.	F-119
33. OTHER GAINS (LOSSES).	F-120
34. FINANCIAL RESULTS.	F-120
35. INFORMATION BY SEGMENT.	F-122

F-15

35.1 Basis of segmentation	F-122
35.2 Generation, distribution and others	F-123
36. THIRD PARTY GUARANTEES, OTHER CONTINGENT ASSETS AND LIABILITIES, AND OTHER COMMITMENTS.	F-125
36.1 Direct guarantees	F-125
36.2 Indirect guarantees	F-125
36.3 Lawsuits and Arbitration Proceedings	F-125
36.4 Financial restrictions	F-130
37. PERSONNEL FIGURES.	F-133
38. SANCTIONS.	F-134
39. ENVIRONMENT.	F-135
40. SUMMARIZED FINANCIAL INFORMATION OF SUBSIDIARIES.	F-138
41. SUBSEQUENT EVENTS.	F-139
APPENDIX 1 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY	F-141
APPENDIX 2 ADDITIONAL INFORMATION OFICIO CIRCULAR (OFFICIAL BULLETIN) No. 715 OF FEBRUARY 3, 2012	F-143
APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES	F-145
APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY	F-147
APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS	F-148

F-16

ENEL CHILE S.A. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 2020 AND 2019 AND FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018.

(In thousands of Chilean pesos – ThCh$)

1. GENERAL INFORMATION

Enel Chile S.A. (hereinafter the “Parent Company” or the “Company”) and its subsidiaries comprise the Enel Chile Group (hereinafter the “Group”).

The Company is a publicly traded corporation with registered address and head office located at Avenida Santa Rosa, No. 76, in Santiago, Chile. Since April 13, 2016, the Company is registered with the securities register of the Financial Market Commission of Chile (“Comisión para el Mercado Financiero” or “CMF”) and since March 31, 2016 is registered with the Securities and Exchange Commission of the United States of America (hereinafter the “U.S. SEC”). On April 21, 2016, the Company’s shares began trading on the Santiago Stock Exchange and the Electronic Stock Exchange. In addition, the Company’s common stock began trading in the United States in the form of American Depositary Shares on the New York Stock Exchange  on a “when-issued” basis from April 21, 2016 to April 26, 2017 and on a“regular-way” basis since April 27, 2016.

Enel Chile is a subsidiary of Enel S.p.A. (hereinafter “Enel”), an entity that has direct and indirect ownership interests of 64.93%.

The Company was initially incorporated by public deed dated January 22, 2016 and came into legal existence on March 1, 2016 under the name of Enersis Chile S.A. The Company changed its name to Enel Chile S.A. effective October 4, 2016, when the Company’s name was changed by means of an amendment of the by-laws. For tax purposes, the Company operates under Chilean Tax identification number 76.536.353 5.

As of December 31, 2020, the Group had 2,219 employees. During the fiscal year ended December 31, 2020, the Group averaged a total of 2,202 employees (see Note 37).

The Company’s corporate purpose consists of exploring for, developing, operating, generating, distributing, transmitting, transforming, and/or selling energy of any kind or form, whether in Chile or abroad, either directly or through other companies. It is also engaged in telecommunications activities, and it provides engineering consulting services in Chile and abroad. The Company’s corporate purpose also includes investing in, and managing, its investments in subsidiaries and associates which generate, transmit, distribute, or sell electricity, or whose corporate purpose includes any of the following:

i) Energy of any kind or form,

ii) Supplying public services, or services whose main component is energy,

iii) Telecommunications and information technology services, and

iv) Internet-based intermediation business.

F-17

2. BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1. Accounting principles

The consolidated financial statements of Enel Chile as of December 31, 2020, approved by its Board of Directors at the meeting held on April 28, 2021, have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

These consolidated financial statements reflect faithfully the financial position of Enel Chile and its subsidiaries at December 31, 2020 and 2019, and the results of their operations, respectively and the changes in their equity and their cash flows for the year ended December 31, 2020, 2019 and 2018 and their related notes.

These consolidated financial statements have been prepared under going concern assumptions on a historical cost basis except when, in accordance with IFRS, those assets and liabilities that are measured at a fair value.

Appendix 1 – Detail of Assets and Liabilities in Foreign Currency; Appendix 2 – Additional Information Circular No. 715 of February 2, 2012; Appendix 2.1 – Supplementary Information on Trade Receivables; Appendix 2.2 – Estimates of Sales and Purchases of Energy, Power and Toll and Appendix 3 – Detail of Due Dates of Payments to Suppliers, form an integral part of these consolidated financial statements.

2.2.   New accounting pronouncements

a) The following accounting pronouncements have been adopted by the Group effective as of January 1, 2020:

Amendments and Improvements	Mandatory Effective Date:
Conceptual Framework (Revised)	Annual periods beginning on or after January 1, 2020
Amendment to IFRS 3: Definition of a Business	Annual periods beginning on or after January 1, 2020
Amendments to IAS 1 and IAS 8: Definition of Material	Annual periods beginning on or after January 1, 2020
Amendments to IFRS 9, IAS 39 and IFRS 7: Interest Rate Benchmark Reform (Phase 1)	Annual periods beginning on or after January 1, 2020

Conceptual Framework (Revised)

The IASB issued the Conceptual Framework (Revised) in March 2018. It incorporates some new concepts, provides updated definitions and recognition criteria for assets and liabilities and clarifies certain important matters. Revisions to the Conceptual Framework may affect the application of IFRS when no standard applies to a particular transaction or event.

The IASB has also issued a separate accompanying document, "Amendments to References to the Conceptual Framework in IFRS Standards," which establishes amendments to IFRSs in order to update references to the new Conceptual Framework.

F-18

The Conceptual Framework (Revised), as well as the Amendments to the References to the Conceptual Framework in IFRS, became effective beginning on January 1, 2020, with prospective application, with no impact generated in the Group’s consolidated financial statements.

Amendments to IFRS 3 Definition of a Business

IFRS 3 Business Combinations was amended by the IASB in October 2018, to clarify the definition of a business, in order to help entities, determine whether a transaction should be accounted for as a business combination or as the acquisition of an asset. To be considered as a business, an acquired integrated set of activities and assets must include, at least, an input and a substantive process that together contribute significantly to the ability to create output.

The amendment also adds guidance and illustrative examples to assess whether a substantial process has been acquired and introduces an optional fair value concentration test.

The amendment became effective beginning on January 1, 2020, with prospective application for business combinations and asset acquisitions carried out beginning on such date, with no impact generated in the consolidated financial statements of the Group.

Amendments to IAS 1 and IAS 8 Definition of Material

In October 2018, the IASB amended IAS 1 Presentation of Financial Statements and IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors, to improve the definition of “material” and the explanations accompanying the definition. The amendments ensure that the definition of material is consistent in all IFRSs.

Information is material if omitting, misstating or obscuring it could reasonably be expected to influence the decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.

The amendments became effective beginning on January 1, 2020, with prospective application, with no impact generated in the Group’s consolidated financial statements.

Amendments to IFRS 9, IAS 39 and IFRS 7 – Interest rate benchmark reform (Phase 1)

On September 26, 2019, the IASB issued amendments to IFRS 9 Financial Instruments, and IAS 39 Financial Instruments: Recognition and Measurement, and IFRS 7 Financial Instruments: Disclosures, in response to the reform that gradually eliminates benchmark interest rates, such as interbank offered rates (IBORs). The amendments provide temporary reliefs which enable hedge accounting to continue during the period of uncertainty before the replacement of an existing interest rate benchmark with an alternative nearly risk-free interest rate (an RFR). These amendments became effective beginning on January 1, 2020.

The amendments to IFRS 9 include a number of reliefs, which apply to all hedging relationships that are directly affected by the interest rate benchmark reform. A hedging relationship is affected if the reform gives rise to uncertainties about the timing and/or amount of benchmark-based cash flows of the hedged item or the hedging instrument.

The first three reliefs provide for:

- The assessment of whether a forecast transaction (or component thereof) is highly probable.

- Assessing when to reclassify the amount in the cash flow hedge reserve to profit and loss.  

- The assessment of the economic relationship between the hedged item and the hedging instrument.

F-19

For each of these reliefs, it is assumed that the benchmark on which the hedged cash flows are based (whether or not contractually specified) and/or, for relief three, the benchmark on which the cash flows of the hedging instrument are based, are not altered as a result of the reform.

A fourth relief provides that, for a benchmark component of interest rate risk that is affected by the reform, the requirement that the risk component is separately identifiable needs be met only at the inception of the hedging relationship.

The exceptions will continue to be applied indefinitely in the absence of any of the events described in the amendments. Upon the designation of a group of items as a hedged item or a combination of financial instruments, as a hedging instrument, the exceptions will cease being applied separately to each individual item or financial instrument, when there is no longer uncertainty arising from the interest rate benchmark reform.  

At the end of 2020, the Group has hedging relationships in force in which the interest rate has been designated as the hedged risk, specifically the London Interbank Offered Rate (LIBOR). These hedging relationships, classified as cash flow hedges, have been directly affected by the uncertainty arising from the interest rate benchmark reform.

In order to evaluate the economic relationship between the hedged items and the hedging instruments, in accordance with the exceptions established by the standard, the Group has assumed that LIBOR, the benchmark interest rate on which the hedged risks are based, has not been altered as a result of the reform.

The Group has contacted financial institutions in the domestic and international market, as well as with the counterparties of the current operations, in order to evaluate the best alternatives for the continuity of the contracts and their hedging relationship.

As of December 31, 2020, the nominal amount of hedging instruments, for hedging relationships to which the exceptions established in IFRS 9 have been applied, is US$400 million (ThCh$284,380,000).

b) Accounting pronouncements applicable beginning on January 1, 2021 and thereafter:

As of the date of issuance of these consolidated financial statements, the following accounting pronouncements had been issued by the IASB, but their application was not mandatory:

Amendments and Improvements	Mandatory application for annual periods beginning on:
Amendments to IFRS 16: COVID-19-Related Rent Concessions	June 1, 2020
Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16: Interest Rate Benchmark Reform – Phase 2	Annual periods beginning on or afterJanuary 1, 2021
Amendments to IFRS 3: References to the Conceptual Framework	Annual periods beginning on or after January 1, 2022
Amendments to IAS 16: Proceeds before Intended Use	Annual periods beginning on or after January 1, 2022
Amendments to IAS 37: Onerous Contracts – Cost of Fulfilling a Contract	Annual periods beginning on or after January 1, 2022
Annual improvements to IFRS: 2018-2020 Cycle -IFRS 1: First-time Adoption of IFRS -IFRS 9: Financial Instruments -Amendment to Illustrative Examples accompanying IFRS 16 -IAS 41: Agriculture	Annual periods beginning on or after January 1, 2022
Amendments to IAS 1: Classification of Liabilities as Current or Non-current	Annual periods beginning on or after January 1, 2023

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Amendments to IFRS 16 “COVID-19-Related Rent Concessions”

As a result of the COVID-19 pandemic, lessees in many countries have been granted rent payment concessions, such as grace periods and delaying of lease payments for a period of time, sometimes followed by an increase in the payment in future periods. Within this context, on May 28, 2020, the IASB issued amendments to IFRS 16 Leases, in order to provide a practical expedient for lessees, through which they can opt for not evaluating whether the rent concession is a modification of the lease. Lessees that elect this option, will account for such rent concessions as a variable payment.

The practical expedient is only applicable to rent concessions that occur as a direct consequence of the COVID-19 pandemic and only if they comply with all the following conditions:

i) the change in lease payments is the product of a revised lease payment that is substantially the same, or less than the lease payment immediately before the change;

ii) any reduction in lease payments affects only the payments originally due up to June 30, 2021; and

iii) there is no substantial change in the other terms and conditions of the lease.

The amendments are applicable to annual periods beginning on June 1, 2020. Early application is permitted. These amendments must be applied retroactively, recognizing the accumulated effect from initial application as an adjustment in the beginning balance of retained earnings (or other equity component, as applicable) at the beginning of the annual period in which the amendment is applied for the first time.

Management estimates that the application of these amendments will not have an impact on the Group's consolidated financial statements.

Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16: Interest Rate Benchmark Reform (Phase 2)

On August 27, 2020, the IASB issued the Interest Rate Benchmark Reform (Phase 2) which supplements the amendments to IFRS 9, IAS 39 and IFRS 7 issued in 2019, and additionally incorporates amendments to IFRS 4 and IFRS 16. This final phase of the project focuses on the effects on the financial statements when a company replaces the previous interest rate benchmark with an alternative interest rate benchmark as a result of the reform.

The amendments refer to:

- Changes in contractual cash flows: a company will not have to derecognize accounts or adjust the carrying amounts of financial instruments due to changes required by the reform, but rather will update the effective interest rate to reflect the change in the alternative interest rate benchmark;

- Hedge accounting: a company will not have to discontinue its hedge accounting solely because it makes the changes required by the reform, if the hedge complies with other hedge accounting criteria; and

- Disclosures: a company will be required to disclose information about new risks that arise from the reform and how it manages the transition to alternative interest rate benchmarks.

These amendments are effective for annual periods beginning on January 1, 2021, and early adoption is permitted. The amendments are applicable retroactively, with certain exceptions. Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements.

Amendments to IFRS 3 “References to the Conceptual Framework”

On May 14, 2020, the IASB issued a package of limited-scope amendments, including amendments to IFRS 3 Business Combinations. The amendments update references to the Conceptual Framework issued in 2018, in order to

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determine an asset or a liability in a business combination. In addition, the IASB added a new exception to IFRS 3 for liabilities and contingent liabilities, which specifies that, for certain types of liabilities and contingent liabilities, an entity that applies IFRS 3 must refer to IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”, or IFRIC 21 “Levies”, instead of the 2018 Conceptual Framework. Without this exception, an entity would have recognized certain liabilities in a business combination that would not be recognized in accordance with IAS 37.

The amendments are applicable prospectively to business combinations with acquisition dates beginning on the first annual period beginning on January 1, 2022. Early application is permitted.

Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements.

Amendments to IAS 16 “Proceeds before Intended Use”

As part of the package of limited-scope amendments issued in May 2020, the IASB issued amendments to IAS 16 Property, Plant and Equipment, which prohibit a company from deducting from the cost of property, plant and equipment amounts received from selling items produced while the company is preparing the asset for its intended use. Instead, the company will recognize such sales proceeds and related costs in profit or loss for the period. The amendments also clarify that an entity is “testing whether an asset operates correctly” when it evaluates the technical and physical performance of the asset.

These amendments are applicable to annual reporting periods beginning on January 1, 2022. Early application is permitted. The amendments will be applied retroactively, but only from the beginning of the first period presented in the financial statements in which the entity applies the amendments for the first time. The accumulated effect of initial application of the amendments will be recognized as an adjustment to the opening balance of retained earnings (or other equity components as applicable) at the beginning of the first reported period.

Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements.

Amendments to IAS 37 “Onerous Contracts: Cost of Fulfilling a Contract”

The third standard amended by the IASB in the package of limited-scope amendments issued in May 2020 was IAS 37 Provisions, Contingent Liabilities and Contingent Assets. The amendments specify which costs a company should include when evaluating whether a contract is onerous. In this sense, the amendments clarify that the direct cost of fulfilling a contract comprises both the incremental costs of fulfilling this contract (for example, direct labor and materials), as well as the allocation of other costs that are directly related to compliance with the contracts (for example, an allocation of the depreciation charge for an item of property, plant and equipment used to fulfill the contract).

These amendments are applicable for reported annual periods beginning on January 1, 2022. Early application is allowed. Companies must apply these amendments to contracts for which all obligations have still not been fulfilled at the beginning of the reported annual period in which the amendments are applied for the first time. They do not require restatement of comparative information. The accumulated effect of initially applying the amendments will be recognized as an adjustment to the opening balance of retained earnings (or another equity component as applicable) on the date of initial application.

Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements.

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Annual Improvements to IFRS: 2018-2020 Cycle

On May 14, 2020, the IASB issued a number of minor amendments to IFRSs, in order to clarify or correct minor issues or overcome possible inconsistencies in the requirements of certain standards. The amendments with potential impact on the Group are the following:

● IFRS 9Financial Instruments: clarifies that for the purpose of the 10% test for derecognition of financial liabilities, when determining commissions paid net of commissions received, the borrower must only consider the commissions paid or received between the borrower and the lender.

These improvements are applicable to reported annual periods beginning on January 1, 2022. Early application is allowed. Entities must apply these amendments to financial liabilities that are modified or exchanged at the beginning of the reported annual period, in which the amendments are applied for the first time.

● Examples that accompany IFRS 16Leases: amendment of illustrative example 13, in order to eliminate a possible confusion regarding the treatment of lease incentives. The example included as part of its background information, a reimbursement from the lessor to the lessee, related to leasehold improvements. Since the example was not sufficiently clear as to whether the reimbursement complied with the definition of a lease incentive, the IASB decided to eliminate from the illustrative example any reference to this reimbursement, thus avoiding any possibility of confusion.

Management believes that the application of these improvements will not generate an impact on the consolidated financial statements of the Group.

Amendments to IAS 1 “Classification of Liabilities as Current and Non-Current”

On January 23, 2020, the IASB issued limited-scope amendments to IAS 1 Presentation of Financial Statements, in order to clarify how to classify debt and other liabilities as current or non-current. The amendments clarify that a liability is classified as non-current if the entity has, at the end of the reporting period, the substantial right to defer settlement of the liability during at least 12 months. The classification is not affected by the expectations of the entity or by events after the reporting date. The amendments include clarification of the classification requirements for debt that a company could settle converting it to equity.

The amendments only affect the presentation of liabilities as current and non-current in the statement of financial position, not the amount and timing of their recognition, or the related disclosures. However, they could lead to companies reclassifying certain current liabilities to non-current and vice versa. This could affect compliance with covenants in the debt agreements of companies.

These amendments are applicable retroactively beginning on January 1, 2023. In response to the Covid-19 pandemic, in July 2020 the IASB extended its mandatory effective date established initially for January 1, 2022, by a year in order to provide companies more time to implement any change in classification resulting from these amendments. Early application is permitted.

Management is evaluating the potential impact of the application of these amendments on the Group’s consolidated financial statements.

2.3.  Responsibility for the information, judgments and estimates provided

The Company’s Board of Directors is responsible for the information contained in these consolidated financial statements and expressly states that all IFRS principles and standards, have been fully implemented.

In preparing the consolidated financial statements, certain judgments and estimates made by the Group’s Management have been used to quantify some of the assets, liabilities, revenue, expenses and commitments recognized.

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The most significant areas where critical judgment was required are:

- The identification of Cash Generating Units (CGU) for impairment testing (see Note 3.e).

- The hierarchy of information used to measure assets and liabilities at fair value (see Note 3.h).

- Application of the revenue recognition model in accordance with IFRS 15 (see Note 3.q).

The estimates refer basically to:

- The valuations performed to determine the existence of impairment losses in non-financial assets and goodwill (see Note 3.e).

- The assumptions used to calculate the actuarial liabilities and obligations with employees, such as discount rates, mortality tables, salary increases, etc. (see Notes 3.m.1 and 26).

- The useful lives of property, plant and equipment, and intangible assets (see Notes 3.a and 3.d).

- The assumptions used to calculate the fair value of financial instruments (see Notes 3.h and 23).

- The energy supplied to customer whose meters have not yet been read.

- Certain assumptions inherent in the electricity system affecting transactions with other companies, such as production, customer billings, energy consumption, that allow for estimation of electricity system settlements that occur on the corresponding final settlement dates, but that are pending as of the date of issuance of the consolidated financial statements and could affect the balances of assets, liabilities, income and expenses recognized in the financial statements (see Appendix 2.2).

- The interpretation of new normative related to the regulation of the Electric Sector, whose final economic effects will be determined by the resolutions of the relevant agencies (see Note 4 and 9).

- The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 3.m).

- Future disbursements for closure of facilities and restoration of land, as well as associated discount rates to be used (see Note 3.a).

- The tax results of the different Group subsidiaries that will be reported to the respective tax authorities in the future, and other estimates have been used as a basis for recording the different income tax related balances in these consolidated financial statements (see Note 3.p).

- The fair value of assets acquired and liabilities assumed, and any pre-existing interest in an entity acquired in a business combination.

- Determination of expected credit losses on financial assets (see Note 3.g.3).

- In the measurement of lease liabilities, determination of the lease term of contracts with renewal options, as well as the rates to be used to discount lease payments (see Note 3.f).

In relation to the COVID-19 pandemic, the degree of uncertainty generated in the macroeconomic and financial environment in which the Group operates, could affect the valuations and estimates made by Management to determine the carrying amounts of the more volatile assets and liabilities. As of December 31, 2020, according to the information available and considering a scenario in constant evolution, the main areas that required Management to

F-24

use their judgment and make estimates were the following: i) measurement of expected credit losses financial assets; ii) determination of impairment losses on non-financial assets; and iii) measurement of employee benefits, including actuarial assumptions.

Although these judgments and estimates have been based on the best information available as of the date of  issuance  of these consolidated financial statements, future events may occur that would require a change (increase or decrease) to these judgments and estimates in subsequent periods. This change would be made prospectively, recognizing the effects of this change in judgment or estimation in the related future consolidated financial statements.

2.4.   Subsidiaries

Subsidiaries are defined as those entities controlled either, directly or indirectly by Enel Chile. Control is exercised if, and only if, the following conditions are met: the Company has i) power over the subsidiary; ii) exposure or rights to variable returns from these entities; and iii) the ability to use its power to influence the amount of these returns.

Subsidiaries are defined as those entities controlled either, directly or indirectly by Enel Chile. Control is exercised if and only if the following conditions are met: the Company has i) power over the subsidiary; ii) exposure, or rights to variable returns from these entities; and iii) the ability to use its power to influence the amount of these returns.

The Group will reassess whether or not it controls a subsidiary if facts and circumstances indicate that there are changes to one or more of the control elements listed above.

Subsidiaries are consolidated as described in Note 2.7.

The entities in which the Group has the ability to exercise control and consequently are included in consolidation in these consolidated financial statements are detailed below:

				Ownership % at 12-31-2020			Percentage at 12-31-2019
Taxpayer ID No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
76.722.488-5	Empresa de Transmisión Chena S.A.	Chile	Chilean peso	—	100.00%	100.00%	—	100.00%	100.00%
96.783.910-8	Enel Colina S.A.(i)	Chile	Chilean peso	—	100.00%	100.00%	—	100.00%	100.00%
96.504.980-0	Empresa Eléctrica Pehuenche S.A.	Chile	Chilean peso	—	92.65%	92.65%	—	92.65%	92.65%
96.800.460-3	Luz Andes Ltda. (ii)	Chile	Chilean peso	—	—	—	—	100.00%	100.00%
96.800.570-7	Enel Distribución Chile S.A. (**)	Chile	Chilean peso	99.09%	—	99.09%	99.09%	0.00%	99.09%
91.081.000-6	Enel Generación Chile S.A.	Chile	Chilean peso	93.55%	—	93.55%	93.55%	0.00%	93.55%
78.932.860-9	GasAtacama Chile S.A. (v)	Chile	Chilean peso	—	—	—	—	0.00%	—
78.952.420-3	Gasoducto Atacama Argentina S.A.(v)	Chile	Chilean peso	—	—	—	—	0.00%	—
77.047.280-6	Sociedad Agrícola de Cameros Ltda.	Chile	Chilean peso	57.50%	—	57.50%	57.50%	0.00%	57.50%
96.920.110-0	Enel Green Power Chile Ltda. (iii)	Chile	U.S. dollar	—	—	—	99.99%	0.00%	99.99%
76.412.562-2	Enel Green Power Chile S.A. (iii) (*)	Chile	U.S. dollar	99.99%	—	99.99%	—	100.00%	100.00%
76.052.206-6	Parque Eólico Valle de los Vientos SpA (iii)	Chile	U.S. dollar	—	—	—	0.01%	99.99%	100.00%
76.306.985-0	Diego de Almagro Matriz SpA (iii)	Chile	U.S. dollar	—	—	—	—	100.00%	100.00%
96.524.140-K	Empresa Eléctrica Panguipulli S.A. (iv)	Chile	U.S. dollar	—	—	—	0.04%	99.96%	100.00%
76.321.458-3	Almeyda Solar SpA (*)	Chile	U.S. dollar	—	100.00%	100.00%	—	100.00%	100.00%
76.179.024-2	Parque Eólico Tal Tal SpA (iv)	Chile	U.S. dollar	—	—	—	0.01%	99.99%	100.00%
96.971.330-6	Geotérmica del Norte S.A.	Chile	U.S. dollar	—	84.59%	84.59%	—	84.59%	84.59%
99.577.350-3	Empresa Nacional de Geotermia S.A. (***)	Chile	U.S. dollar	—	51.00%	51.00%	—	51.00%	51.00%
76.126.507-5	Parque Talinay Oriente S.A.	Chile	U.S. dollar	—	60.91%	60.91%	—	60.91%	60.91%
76.924.079-9	Enel X Chile Spa	Chile	Chilean peso	100.00%	—	100.00%	100.00%	0.00%	100.00%

(*) On January 1, 2021, the merger by incorporation of Almeyda Solar SpA into Enel Green Power Chile S.A. took place, where the latter company became the legal successor company.

(**) On January 1, 2021, the spin-off by Enel Distribución Chile S.A was formalized which resulted in the incorporation of a new company, Enel Transmisión Chile S.A., to which the assets and liabilities associated with the electric power transmission segment were assigned and also distributing to all the shareholders of Enel Distribución Chile S.A., a number of Enel Transmisión Chile S.A. shares equal to the their interest in the spin-off company.

This process was performed to comply with the requirements related to the exclusive turn of distribution, according to the latest modifications to Decree with Force of Law No. 4/2016 issued by the Ministry of Economy, Development and Reconstruction, which established the consolidated, coordinated and systematized text of Decree with Force of Law No. 1-1982 issued by the Ministry of Mining, General Law of Electric Services.

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(***) Empresa Nacional de Geotermia S.A. is in liquidation process as of December 31, 2020.

2.4.1Changes in the scope of consolidation as of December 31, 2020.

i. On April 14, 2020, Empresa Eléctrica de Colina Ltda. changed its name to Enel Colina S.A.

ii. On January 1, 2020, Luz Andes Ltda. merged into Enel Distribución Chile S.A. where the latter company became the legal successor company.

iii. On March 1, 2020, Enel Green Power Chile Ltda. merged into Enel Green Power del Sur SpA, where the latter company became the legal successor company. This transaction was approved by the Extraordinary Shareholders' Meeting of Enel Green Power del Sur SpA, held on February 27, 2020. Subsequently, on April 14, 2020, Enel Green Power del Sur SpA changed its name to Enel Green Power Chile S.A.

On the same date, the merger by incorporation of Parque Eólico Valle de los Vientos SpA and Diego de Almagro Matriz SpA into Empresa Eléctrica Panguipulli S.A. was completed, where the latter company became the legal successor company. This transaction was approved by the Extraordinary Shareholders' Meetings of Empresa Eléctrica Panguipulli S.A. and Parque Eólico Valle de los Vientos SpA, both held on February 27, 2020.

iv. On July 1, 2020, the merger by incorporation of Empresa Eléctrica Panguipulli S.A. into Parque Eólico Taltal SpA was completed, where the latter company became the legal successor company. Subsequently, on August 1, 2020, the merger by incorporation of Parque Eólico Taltal SpA into Almeyda Solar SpA was completed, where the latter company became the legal successor company.

v. Gasoducto GasAtacama Argentina S.A. was merged into GasAtacama Chile S.A. on September 1, 2019, where the latter company became the legal successor company. Subsequently, on October 1, 2019, GasAtacama Chile S.A. was completely acquired by Enel Generación Chile S.A. as a result of a transaction approved by the Board of Directors of Enel Generación Chile S.A. on August 29, 2019. The transaction consisted of Enel Generación Chile S.A.’s acquisition of 2.63% of the shares of GasAtacama Chile S.A. held by Enel Chile. As a result, Enel Generación Chile S.A. became the owner of 100% of the shares in GasAtacama Chile S.A., which was absorbed through a merger, with Enel Generación Chile S.A. where the latter company became the legal successor company.

2.5.   Investments in associates

Associates are those entities over which Enel Chile, either directly or indirectly, exercises significant influence.

Significant influence is the power to participate in the decisions related to the financial and operating policy of the associate but without having control or joint control over those policies.

In assessing significant influence, the Group takes into account the existence and effect of currently exercisable voting rights or convertible rights at the end of each reporting period, including currently exercisable voting rights held by the Company or other entities. In general, significant influence is presumed to be present in those cases in which the Group has more than 20% of the voting power of the investee

Associates are accounted for in the consolidated financial statements using the equity method of accounting, as described in Note 3.i.

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The detail of the companies that qualify as associates is the following:

				Ownership % at 12-31-2020			Percentage at 12-31-2019
Taxpayer ID No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
76.418.940-K	GNL Chile S.A.	Chile	U.S. dollar	—	33.33%	33.33%	—	33.33%	33.33%
76.364.085-K	Energía Marina SpA	Chile	Chilean peso	—	25.00%	25.00%	—	25.00%	25.00%
77.157.779-2	Enel AMPCI Ebus Chile SpA (*)	Chile	U.S. dollar	—	20.00%	20.00%	—	—	—

(*) On June 11, 2020, the Company’s subsidiary Enel X Chile SpA acquired 20% of the holding company Enel AMPCI Ebus Chile SpA from the AMP Capital Group.

2.6.   Joint arrangements

Joint arrangements are defined as those entities in which the Group exercises control under an agreement with other shareholders and jointly with them, i.e., when decisions on the entities’ relevant activities require the unanimous consent of the parties sharing control.

Depending on the rights and obligations of the participants, joint agreements are classified as:

- Joint venture: an agreement whereby the parties exercising joint control have rights to the entity’s net assets. Joint ventures are included in the consolidated financial statements using the equity method of accounting, as described in Note 3.i.  

- Joint operation: an agreement whereby the parties exercising joint control have rights to the assets and obligations with respect to the liabilities relating to the arrangement. Joint operations are included in the consolidated financial statements recognizing the proportional interest in the assets and liabilities impacted by such operation.  

In determining the type of joint arrangement in which it is involved, the Group’s Management assesses its rights and obligations arising from the arrangement by considering the structure and legal form of the arrangement, the terms agreed by the parties in the contractual arrangement and, when relevant, other facts and circumstances. If facts and circumstances change, the Group reassesses whether the type of joint arrangement in which it is involved has changed.

The detail of Companies classified as Joint Ventures is as follows:

				Ownership % at 12-31-2020			Percentage at 12-31-2019
Taxpayer ID No.	Company	Country	Currency	Direct	Indirect	Total	Direct	Indirect	Total
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Chile	Chilean peso	—	50.00%	50.00%	—	50.00%	50.00%

Currently, Enel Chile is not involved in any joint arrangement that qualifies as a joint operation.

2.7. Basis of consolidation and business combinations

The subsidiaries are consolidated and all their assets, liabilities, revenues, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations of intra-group transactions have been made.

The Comprehensive income from subsidiaries is included in the consolidated statement of comprehensive income from the date when the parent company obtains control of the subsidiary until the date on which it loses control of the subsidiary.

The Group records business combinations using the acquisition method when all the activities and assets acquired meet the definition of a business and control is transferred to the Group. To be considered a business, a set of activities and assets acquired must include at least one input and a substantive process applied to it that, together, contribute

F-27

significantly to the ability to create output. IFRS 3 provides the option of applying a “concentration test” that allows a simplified assessment of whether a set of acquired activities and assets is not a business. The concentration test is met if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets.

The operations of Parent company and its subsidiaries have been consolidated under the following basic principles:

1. At the date the parent obtains control, the subsidiary’s assets acquired and its liabilities assumed are recorded at fair value, except for certain assets and liabilities that are recorded using valuation principles established in other IFRS standards. If the fair value of the consideration transferred plus the fair value of any non-controlling interests exceeds the fair value of the net assets acquired, this difference is recorded as goodwill. In the case of a bargain purchase, the resulting gain is recognized in profit or loss after reassessing whether all of the assets acquired and the liabilities assumed have been properly identified and following a review of the procedures used to measure the fair value of these amounts.

Foreachbusinesscombination,IFRS allow valuation of the non-controlling interests in the acquiree on the date of acquisition: i) at fair value; or ii) for the proportional ownership of the identifiable net assets of the acquiree, with the latter being the methodology that the Group has systematically applied to its business combinations.

If the fair value of all assets acquired and liabilities assumed at the acquisition date has not been completed, the Group reports the provisional values accounted for in the business combination. During the measurement period, which shall not exceed one year from the acquisition date, the provisional values recognized will be adjusted retrospectively as if the accounting for the business combination had been completed at the acquisition date, and also additional assets or liabilities will be recognized to reflect new information obtained about events and circumstances that existed on the acquisition date, but which were unknown to Management at that time. Comparative information for prior periods presented in the financial statements is revised as needed, including making any change in depreciation, amortization or other income effects recognized in completing the initial accounting.

For business combinations achieved in stages, the Company measures at fair value the participation previously held in the equity of the acquiree on the date of acquisition and the resulting gain or loss, if any, is recognized in profit or loss of the period.

2. Non-controlling interests in equity and in the comprehensive income of the consolidated subsidiaries are presented, respectively, under the line items “Total Equity: Non-controlling interests” in the consolidated statement of financial position and “Profit (loss) attributable to non-controlling interests” and “Comprehensive income attributable to non-controlling interests” in the consolidated statement of comprehensive income.

3. Balances and transactions between consolidated companies have been fully eliminated on consolidation.

4. Changes in the ownership interests in subsidiaries that do not result in the Group obtaining or losing control are recognized as equity transactions. The carrying amounts of the controlling and non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received, is recognized directly in equity attributable to shareholders of the Parent.

5. Business combinations under common control are accounted for using, as a reference, the ‘pooling of interest’ method. Under this method, the assets and liabilities involved in the transaction remain reflected at the same carrying amounts at which they were recognized in the ultimate Parent, although subsequent accounting adjustments may be needed to align the accounting policies of the companies involved.  The Group does not restate comparative periods in its financial statements for business combinations under common control.

Any difference between assets and liabilities contributed to the consolidation and the consideration paid is recorded directly in  equity as a charge or credit to Other reserves.

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2.8.   Functional currency

The functional and presentation currency of the consolidated financial statements of Enel Chile is the Chilean peso (Ch$). The functional currency has been determined, considering the economic environment in which the Company operates.

Any information presented in Ch$ has been rounded to the closest thousand (ThCh$) or million (MCh$), unless indicated otherwise.

2.9.   Conversion of financial statements denominated in foreign currency

Conversion of the financial statements of the Group companies that have functional currencies different than Ch$, and do not operate in hyperinflationary economies, is carried out as follows:

a. Assets and liabilities, using the exchange rate prevailing at the closing date of the financial statements.

b. Comprehensive income statements using the average exchange rate for the period (unless this average is not a reasonable approximation of the cumulative effect of the exchange rate existing on the transaction dates, in which case the exchange rate on the date of each transaction is used).

c. Equity is maintained at the historical exchange rate on the date of its acquisition or contribution, and at the average exchange rate as of the date of generation for retained earnings.

d. Foreign currency translation differences generated in the conversion of the financial statements are recorded under “Foreign currency translation gains (losses)” in the consolidated comprehensive income statement: Other comprehensive income (see Note 27.3).

The financial statements of subsidiaries whose functional currency is that of a hyperinflationary economy, are first adjusted for inflation, recording any gain or loss in the net monetary position in profit or loss. Subsequently, all items (assets, liabilities, equity items, expenses and revenue) are converted at the exchange rate prevailing at the closing date of the most recent statement of financial position.

Argentine Hyperinflation

Beginning on July 2018, the Argentine economy has been considered to be hyperinflationary in accordance with the criteria established in IAS 29 “Financial Reporting in Hyperinflationary Economies”. This determination was made on the basis of a number of qualitative and quantitative criteria, especially the presence of accumulated inflation in excess of 100% during the three previous years.

In accordance with IAS 29, the financial statements of investees in Argentina have been restated retrospectively, applying the general price index at historical cost, in order to reflect changes in the purchasing power of the Argentine peso, as of the closing date of these consolidated financial statements.

The general price indexes used at the end of the reporting periods are as follows:

	General price index
From January to December 2018	47.83%
From January to December 2019	53.64%
From January to December 2020	36.13%

The effects of the application of this standard on these consolidated financial statements are detailed in Note 34.

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3.    ACCOUNTING POLICIES

The main accounting policies used in preparing the accompanying consolidated financial statements are the following:

a) Property, plant and equipment

Property, plant and equipment are generally measured with at acquisition cost, net of accumulated depreciation and any impairment losses experienced. In addition to the price paid to acquire each item, the cost also includes, the following concepts, where applicable:  

- Finance costs accrued during the construction period that are directly attributable to the acquisition, construction, or production of qualifying assets, which require a substantial period of time before being ready for use such as; for example., electricity generation or distribution facilities. The Group defines “substantial period” as a period exceeding twelve months. On the other hand, the capitalization of interest is suspended for periods in which the development of activities for a qualifying asset has been interrupted, if these periods are extended over time. The interest rate used is that corresponding to the specific financing or, if it does not exist, the average financing rate of the company making the investment (See Note 16 b.1).

- Employee expenses directly related to construction in progress (see Note 16.b.2).

- Future disbursements that the Group will have to make to close its facilities are added to the value of the asset at fair value, recognizing the related provision for dismantling or restoration. Changes in the measurement of the provision resulting from changes in the estimated amount or timing of future expenditures required to settle the obligation, or changes in the discount rate, are added to or deducted from the cost of the asset, as appropriate ( See Note 25).

Assets under for construction are transferred to operating assets once the testing period has been completed and they are available for use, at which time depreciation begins.

Expansion, modernization or improvement costs that represent an increase in productivity, capacity or efficiency or a lengthening of the useful lives of the assets are capitalized as an increase in the value of the related assets.

The replacement or overhaul of entire components that increase the asset’s useful life or economic capacity are recorded as an increase in cost of the related assets, derecognizing the replaced or overhauled components.

Expenditures for periodic maintenance and repair are recognized directly as an expense for the year in which they are incurred.

Property, plant and equipment, net of its residual value, is depreciated by distributing the cost of the different items that comprise it on a straight-line basis over its estimated useful life, which is the period during which the Group expects to use the assets. Useful life estimates and residual values are reviewed on an annual basis and if appropriate adjusted prospectively.

In addition, the Group recognizes right-of-use assets for leases relating to property, plant and equipment in accordance with the criteria established in Note 3.f.

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The following are the main categories of property, plant and equipment with their related estimated useful lives:

Classes of property, plant and equipment	Years of estimated useful life
Buildings	10 – 60
Plant and equipment	6 – 65
IT equipment	3 – 15
Fixtures and fittings	2 – 35
Motor vehicles	5 – 10

In addition, for further information, the following is a more detailed breakdown of the class of plant and equipment:

Class of plant and equipment	Years of estimated useful life
Generating plant and equipment
Hydroelectric plants
Civil engineering works	10 – 65
Electromechanical equipment	10 – 45
Combined cycle power plants	10 – 25
Renewable	20
Distribution plant and equipment::
High-voltage network	10 – 60
Low- and medium-voltage network	10 – 50
Measuring and remote control equipment	10 – 50
Primary substations	6 – 25
Natural gas transportation
Gas pipelines	20

Land is not depreciated since it has an indefinite useful life, unless it relates to a right-of- use asset in which case it is depreciated over the term of the lease.

An item of property, plant and equipment is written off when sold or otherwise disposed of, or when no future economic benefits are expected to be obtained from its use, sale or other disposal.

Gains or losses arising from sales of property, plant and equipment or PP&E items retired, are recognized as “Other gains (losses)” in the statement of comprehensive income and are determined as the difference between the sale value and net carrying amount of the asset.

b)    Investment property

“Investment property” basically includes land and buildings that are kept for the purpose of obtaining gains from future sales or lease arrangements.

Investment property is measured at acquisition cost, net of accumulated depreciation and any impairment losses experienced. Investment property, excluding land, is depreciated by distributing the cost of the several elements that comprise it on a straight-line basis over the years of useful life.

An investment property is derecognized on disposal, or when no future economic benefits are expected from use or disposal.

Gains or losses arising from the sale or disposal of items of investment property are recognized as “Other gains (losses)” in the statement of comprehensive income and determined as the difference between the sales amount and the net carrying amount of the asset.

The fair value of investment property is disclosed in Note 17.

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c)    Goodwill

Goodwill arising from business combinations and reflected in consolidation, represents the excess of the value of the consideration transferred plus the amount of any non-controlling interest over the net identifiable assets acquired and liabilities assumed, measured at fair value at the date of acquisition of the subsidiary. During the measurement period of the business combination, goodwill may be adjusted as a result of changes in the provisional amounts recognized for the assets acquired and liabilities assumed (see Note 2.7.1).

Goodwill arising from acquisition of companies with functional currencies other than the functional currency of the Parent is measured in the functional currency of the acquiree and translated to Chilean peso using the exchange rate effective as of the date of the statement of financial position.

After initial recognition, goodwill is not amortized, but rather, at the end of each accounting period, or when there are indications thereof, an impairment test is performed to determine whether any impairment has occurred that reduces its recoverable value to an amount lower than the recorded net cost, and if this is the case, the impairment is recorded in the statement of income for the period (see Note 3.e).

d)    Intangible assets other than goodwill

Intangible assets  are initially recognized at their acquisition cost or production cost, and are subsequently measured at their cost, net of their accumulated amortization and impairment losses experienced.

Intangible assets are amortized on a straight-line basis over their useful lives starting from the time they are in use, except for those assets with indefinite useful lives, for which amortization is not applicable. As of December 31, 2020 and 2019, intangible assets with indefinite useful lives amounted to ThCh$14,605,574 and ThCh$16,455,724, respectively, mainly related to easements and water rights.

An intangible asset is derecognized when it is sold or otherwise disposed of, or when no future economic benefits are expected from its use, sale or other disposal.

Gains or losses arising from sales of intangible assets are recognized in profit or loss for the period and determined as the difference between the amount of the sale and the carrying amount of the asset.

The criteria for recognizing impairment losses on these assets and, if applicable, recoveries of impairment losses recorded in prior periods are explained in letter e) of this Note below.

d.1) Research and development expenses

The Group recognizes the costs incurred in a project’s development phase as intangible assets in the statement of financial position as long as the project’s technical feasibility and future economic benefits have been demonstrated.

Research costs are recorded as an expense in the consolidated statement of comprehensive income in the period in which they are incurred.

d.2) Other intangible assets

These assets correspond mainly to computer software, water rights and easements. They are initially recognized at acquisition or production cost and are subsequently valued at cost net of the related accumulated amortization and impairment losses, if any.

Computer software is amortized (on average) over four years. Certain easements and water rights have indefinite useful lives and are therefore not amortized.

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e)    Impairment of non-financial assets

During the period, and mainly at the end of each reporting period, the Group evaluates whether there is any indication that an asset has been impaired. If any such indication exists, the Group estimates the recoverable amount of that asset to determine the amount of the impairment loss. For identifiable assets that do not generate cash flows independently, the Group estimates the recoverable amount of the Cash Generating Unit (CGU) to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

Notwithstanding the preceding paragraph, for CGUs to which goodwill or intangible assets with indefinite useful lives have been allocated, a recoverability analysis is performed routinely at each year-end.

The criteria used to identify the CGUs are based, in line with Management’s strategic and operating vision, within the specific characteristics of the business, the operating rules and regulations of the market in which the Group operates and corporate organization.

Recoverable amount is the higher of fair value less costs of disposal and value in use, which is defined as the present value of the estimated future cash flows. In order to calculate the recoverable amount of Property, plant, and equipment, as well as of goodwill and intangible assets, at the level of each CGUs the Group uses value in use criteria in practically all cases.

To estimate value in use, the Group prepares future pre-tax cash flow forecasts based on the most recent budgets available. These budgets include Management’s best estimates of a CGU’s revenue and costs using sector forecasts, past experience and future expectations.

In general, these projections cover the next three years, estimating cash flows for subsequent years by applying reasonable growth rates which, in no case, are increasing rates nor exceed the average long-term growth rates for the particular sector. At the end of December 2020, the rates used to extrapolate the projections were between 2.0% and 2.9%.  

Future cash flows are discounted to calculate their present value at a pre-tax rate that covers the cost of capital for the business activity and the geographic area in which it is being carried out. The time value of money and risk premiums generally used among analysts for the business activity and the geographic zone are taken into account to calculate the pre-tax rate. The pre-tax discount rates, expressed in nominal terms, applied at the end of December 2020 were between 6.3% and 8.2%.

The Company’s approach to allocate value to each key assumption used to project cash flows, considers:

- Demand evolution: the growth estimate has been calculated based on the projected increase in Gross Domestic Product (GDP), in addition to other assumptions used by the company regarding the evolution of consumption, such as the growth in the number of customers.

- Energy purchase and sale prices: based on specifically developed internal projection models. The price of the planned “pool” is estimated by considering a number of determining factors, such as the different technology’ costs and productions and energy demand, among other items.

- Regulatory measures: an important part of the Company’s business is regulated and subject to extensive standards, which could undergo revisions, either as a result of new laws or the amendment of existing laws, and therefore the projections include adequate application of the current standards, those that are currently being developed, and those expected to be effective during the projected period.

- Installed capacity: in the estimating of the Group’s installed capacity, the existing facilities are taken into account, as well as the plans for both increasing capacity and capacity closure. The investment plan is constantly updated based on the evolution of the business, quality of service regulations determined by the regulator and changes in the business development strategy adopted by management. In the generation area, the investments necessary to maintain the installed capacity in adequate operating conditions are taken into account; in the distribution activity,

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investments for maintenance, improvement and strengthening of the network are considered, as well as the investments necessary to carry out the implementation of the technological improvement plan (Smart Meters).

- Hydrology and NCRE: the projections are made from historical series of meteorological conditions and projecting an average year, based on these.

- Fuel costs for the estimation of fuel costs take into consideration existing supply contracts and long-term projections of oil, gas or coal prices based on forward markets and available analysts' estimates.

- Fixed costs: these are projected considering the foreseen level of business activities, both in terms of the evolution of the workforce (considering salary raises in line with the CPI), and in term of other operating and maintenance costs, the level of projected inflation and long-term existing maintenance or other contracts.  The efficiencies that the Group is adopting over time are also considered, such as those that arise from the initiatives for the digitalization of internal processes.

- External sources are always considered to verify the assumptions related to the macroeconomic environment such as price evolution, GDP growth, demand, inflation, interest rates and exchange rates, among others.

Past experience has demonstrated the reliability of the Company’s forecasts, which allows it to base key assumptions on historical information. During 2020, the deviations observed with respect to the projections used to perform impairment testing as of December 31, 2019, were not significant and cash flows generated in 2020 remained in a reasonable variance range compared to those expected for that period, with the exception of the effects generated by the COVID-19 pandemic. Despite the degree of uncertainty of the evolution of the macroeconomic environment in the short term, as a result of COVID-19, Management has evaluated the recovery scenarios and has determined that there is no evidence of impairment in the Group's CGUs, which would make it necessary to estimate their value in use.

If the recoverable amount of the CGU is less than the net carrying amount of the asset, the related impairment loss is recognized for the difference, and charged to “Impairment loss (impairment reversals) recognized in profit or loss” in the consolidated statement of comprehensive income. The impairment is first allocated to the CGU’s goodwill carrying amount, if any, and then to the other assets comprising it, prorated on the basis of the carrying amount of each one, limited to the fair value less costs of disposal, or value in use, where no negative amount could be obtained.

Impairment losses recognized in prior periods for an asset other than goodwill are reversed, if and only if, there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If this is the case, the carrying amount of the asset is increased to its recoverable amount with a credit to profit or loss, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the asset. For goodwill, impairment losses are not reversed in subsequent periods.

f)    Leases

In order to determine whether an arrangement is, or contains, a lease, Enel Chile assesses the economic substance of the agreement, assessing whether the agreement conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Control is considered to exist if the customer has i) the right to obtain substantially all the economic benefits arising from the use of an identified asset; and ii) the right to direct the use of the asset.

f.1) Lessee

When the Group acts as a lessee at the commencement of the lease (i.e. on the date on which the underlying asset is available for use) it records a right-of-use asset and a lease liability in the statement of financial position.

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The Group initially recognizes right-of-use assets at cost. The cost of right-of-.use assets comprises: (i) the amount of the initial measurement of the lease liability; (ii) lease payments made until the commencement date less lease incentives received, (iii) initial direct costs incurred; and (iv) the estimate of decommissioning or restoration costs.

Subsequently, the right-of-use asset is measured at cost, adjusted by any re measurement of the lease liability, less accumulated depreciation and accumulated impairment losses. A right-of-use asset is depreciated on the same terms as other similar depreciable assets, as long as there is reasonable certainty that the lessee will acquire ownership of the asset at the end of the lease. If no such certainty exists, the leased assets are depreciated over the shorter of the useful lives of the assets and their lease term. The same criteria detailed in Note 3.e are applied to determine whether the right-of-use asset has become impaired.

Lease liabilities are initially measured at the present value of the lease payments, discounted at the Company's incremental borrowing rate, if the interest rate implicit in the lease cannot be readily determined. The incremental borrowing rate is the interest rate that the company would have to pay to borrow over a similar term, and with similar security, the funds necessary to obtain an asset of similar value to the right-of-use asset in a similar economic environment.  The Group determines its incremental borrowing rate using observable data (such as market interest rates) or by making specific estimates when observable rates are not available (e.g., for subsidiaries that do not engage in financing transactions) or when they must be adjusted to reflect the terms and conditions of the lease (e.g., when the leases are not in the subsidiary's functional currency).

Lease payments included in the measurement of liabilities comprise: i) fixed payments, less any lease incentive receivable; ii) variable lease payments that depend on an index or a rate; iii) residual value guarantees if it is reasonably certain that the Group will exercise that option; iv) the exercise price of a purchase option, if the Group is it is reasonably certain to exercise that option; and v) penalties for terminating the lease, if any.

After the commencement date, the lease liability increases to reflect the accrual of interest and is reduced by the lease payments made. In addition, the carrying amount of the liability is remeasured if there is a change in the terms of the lease (changes in the lease term, in the amount of expected payments related to a residual value guarantee, in the evaluation of a purchase option or in an index or rate used to determine lease payments). Interest expense is recognized as finance cost and distributed over the years making up the lease period, so that a constant interest rate is obtained in each year on the outstanding balance of the lease liability.

Short-term leases of one year or less or leases of low value assets are exempt from the application of the recognition criteria described above, with the payments associated with the lease recorded as an expense on a straight-line basis over the term of the lease.

Right-of-use assets and lease liabilities are presented separately from other assets and liabilities, respectively, in the consolidated statement of financial position.

f.2) Lessor

When the Group acts as a lessor, it classifies at the commencement of the agreement whether the lease is an operating or finance lease, based on the substance of the transaction. Leases in which all the risks and rewards incidental to ownership of an underlying asset are substantially transferred are classified as finance leases. All other leases are classified as operating leases.

For finance leases, at the commencement date, the Company recognizes in its statement of financial position the assets held under finance leases and presents them as an account receivable, for an amount equal to the net investment in the lease, calculated as the sum of the present value of the lease payments and the present value of any accrued residual value, discounted at the interest rate implicit in the lease. Subsequently, finance income is recognized over the term of the lease, based on a model that reflects a constant rate of return on the net financial investment made in the lease.

For operating leases, lease payments are recognized as income on a straight-line basis, over the term of the lease unless another type of systematic basis of distribution is deemed more representative. The initial direct costs incurred in

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obtaining an operating lease are added to the carrying amount of the underlying asset and are recognized as expense throughout the lease period, applying the same basis as for rental income.

g)    Financial instruments

Financial instruments are contracts that give rise to both a financial asset in one entity and a financial liability or equity instrument in another entity.

g.1) Financial assets other than derivatives

The Group classifies its non-derivative financial assets, whether permanent or temporary, excluding investments accounted for using the equity method (see Notes 3.i and 13) and non-current assets held for sale (see Note 3.k), in three categories:

(i) Amortized cost

This category includes the financial assets that meet the following conditions (i) the business model that supports the financial assets seeks to maintain such financial assets to obtain contractual cash flows, and (ii) the contractual terms of such financial assets give rise on specific dates to cash flows that are solely payments of principal and interest (SPPI criterion).

Financial assets that meet the conditions established in IFRS 9, to be valued at amortized cost in the Group are: cash equivalents, accounts receivable and, loans. Such assets are recorded at amortized cost, which is the initial fair value, less repayments of principal, plus uncollected accrued interest, calculated using the effective interest method.

The effective interest method is a method for calculating the amortized cost of a financial asset or a financial liability (or a group of financial assets or financial liabilities) and allocating the finance income or financial costs throughout the relevant period. The effective interest rate is the discount rate that exactly matches the estimated cash flows to be received or paid over the expected useful life of the financial instrument (or when appropriate in a shorter period of time), with the net carrying amount of the financial asset or financial liability.

(ii) Financial Assets Recorded at Fair Value through Other Comprehensive Income

This category includes the financial assets that the meet the following conditions: (i) they are classified in a business model, the purpose of which is to maintain the financial assets both to collect the contractual cash flows and to sell them, and (ii) the contractual conditions meet the SPPI criterion.

These financial assets are recognized in the consolidated statement of financial position at fair value when this can be determined reliably. For the holdings in unlisted companies or companies with low liquidity, it is usually not possible to determine the fair value reliably, therefore, when this occurs, such holdings are valued at their acquisition cost or for a lower amount if there is evidence of their impairment.

Changes in fair value, net of their tax effect, are recorded in the consolidated statement of comprehensive income: Other comprehensive income, until the disposal of these financial assets, where the accumulated amount in this section is fully allocated to profit or loss for the period except for investments in equity instruments where the accumulated balance in other comprehensive income is never reclassified to profit or loss.

In the event that the fair value is lower than the acquisition cost, if there is objective evidence that the asset has suffered an impairment that cannot be considered as temporary, the difference is recorded directly in the loss for the period.

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(iii) Financial Assets Recorded at Fair Value through Profit or Loss

This category includes the trading portfolio of the financial assets that have been allocated as such upon their initial recognition and which are managed and assessed according to the fair value criterion, and the financial assets that do not meet the conditions to be classified in the two categories indicated above.

These are valued in the consolidated statement of financial position at fair value, and variations in their value are recorded directly in income when they occur.

g.2) Cash and cash equivalents

This item within the consolidated statement of financial position includes cash and bank balances, time deposits, and other highly liquid investments (with original maturity of less than or equal to 90 days) that are readily convertible into cash and are subject to insignificant risk of changes in value.

g.3) Impairment of financial assets

Following the requirements of IFRS 9, the Group applies an impairment model based on the determination of expected credit losses, based on the Group's past history, existing market conditions, as well as forward-looking estimates at the end of each reporting period. This model is applied to financial assets measured at amortized cost or measured at fair value through other comprehensive income, except for investments in equity instruments.

Expected credit loss is the difference between the contractual cash flows that are due in accordance with the contract and all the cash flows that are expected to be received (i.e. all cash shortfalls), discounted at the original effective interest rate. It is determined considering: i) the probability of default (PD, Probability of Default); ii) loss given default (LGD, Loss Given Default), and iii) exposure at default (EAD, Exposure at Default).

To determine the expected credit losses the Group applies two separate approaches:

●General approach: applied to financial assets other than trade accounts receivable, contractual assets or lease receivables. This approach is based on the evaluation of significant increases in the credit risk of financial assets, from the date of initial recognition. If on the reporting date of the financial statements the credit risk has not increased significantly, the impairment losses are measured related to the expected credit losses in the next 12 months; if, on the contrary, the credit risk has increased significantly, the impairment is measured considering the expected credit losses throughout the lifetime of the asset.

In general, the measurement of expected credit losses for financial assets other than trade accounts receivable, contractual assets or lease receivables, are performed separately.

●Simplified approach: The Group applies a simplified approach for trade receivables, contract assets and lease receivables so that the impairment provision is always recognized related to the lifetime expected credit losses for the asset. This is the approach that the Group has mostly applied because trade receivables represent the main financial asset of Enel Chile and its subsidiaries.

For trade accounts receivable, contractual assets and lease receivables, the Group applies two types of evaluations of expected credit losses:

- Collective evaluation: based on grouping accounts receivable into specific groups or “clusters”, taking into account each business and the local regulatory context. Accounts receivable are grouped according to the characteristics of customer portfolios in terms of credit risk, maturity information and recovery rates. A specific definition of default is considered for each group.

To measure the expected credit losses collectively, the Group considers the following assumptions:

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- PD: average default estimate, calculated for each group of trade receivables, taking into account a   minimum of 24-month historical data.

- LGD: calculated based on the recovery rates of a predetermined section, discounted at the effective interest rate; and

- EAD: accounting exposure on reporting date, net of cash deposits, including invoices issued, but not due and invoices to be issued.

- Analytical or individual evaluation: if accounts receivable are considered individually significant by Management and there is specific information regarding any significant increase in the credit risk, the Group applies an individual evaluation of accounts receivable. For the individual evaluation, the PD is obtained mainly from an external supplier, when it is possible to do so, and the LGD through an internal model that considers the recovery rate and other contractual and financial characteristics of accounts receivable. The expected credit loss is obtained by multiplying both factors by the EAD, which is defined as the accounting exposure at the reporting date, including the invoices issued but not due and invoices to be issued for services rendered, net of potential cash deposits obtained as guarantees.

On the basis of the benchmark market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for those accounts receivable, the Group mainly applies a predetermined definition of 180 days overdue to determine expected credit losses, since this is considered an effective indicator of a significant increase in credit risk. Consequently, financial assets that are more than 90 days overdue generally are not considered to be in default.

Based on specific evaluations performed by Management, the prospective adjustment can be applied considering qualitative and quantitative information to reflect possible future events and macroeconomic scenarios, which may affect the risk of the portfolio or the financial instrument.

g.4) Financial liabilities other than derivatives

General financial liabilities are initially recognized, at fair value net of any costs incurred in the transaction. In subsequent periods, these obligations are measured at their amortized cost using the effective interest method (see Note 3.g.1).

Lease liabilities are initially measured at the present value of future lease payments, determined in accordance with the criteria described in Note 3.f.

In the particular case that a liability is the hedged item in a fair value hedge, as an exception, such liability is measured at its fair value for the portion of the hedged risk.

In order to calculate the fair value of debt, both when it is recorded in the statement of financial position and for fair value disclosure purposes as shown in Note 23, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and floating interest rate debt (hereinafter “floating-rate debt”). Fixed-rate debt is that on which fixed-interest coupons established at the beginning of the transaction are paid explicitly or implicitly over its term. Floating-rate debt is that debt issued at floating interest rate, i.e., each coupon is established at the beginning of each period based on the benchmark interest rate. All debt has been measured by discounting expected future cash flows with a market interest rate curve based on the payment currency.  

g.5) Derivative financial instruments and hedge accounting

Derivatives held by the Group are transactions entered into to hedge interest and/or exchange rate risk, intended to eliminate or significantly reduce these risks in the underlying transactions being hedged.

Derivatives are recorded at fair value at the end of each reporting period as follows: if their fair value is positive, they are recorded within “Other financial assets” and if their fair value is negative, they are recorded within “Other financial

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liabilities”. For derivatives on commodities, positive fair value is recorded in “Trade and other receivables”, and negative fair value, if any, is recognized in “Trade and other liabilities.”

Changes in fair value are recorded directly in profit or loss, except when the derivative has been designated for  hedge accounting purposes as a hedging instrument  and all of the conditions for applying hedge accounting established by IFRS are met, including that the hedge is highly effective. In this case, changes are recognized as follows:  

- Fair value hedges: The underlying portion for which the risk is being hedged and the hedging instrument are measured at fair value, and any changes in the value of both items are recognized in the statement of comprehensive income offsetting the effects in the same caption of the statement comprehensive income.

- Cash flow hedges: Changes in the fair value of the effective portion of the hedged item and hedge instrument are recognized in other comprehensive income and accumulated in an equity reserve referred to as Hedging reserve. The cumulative loss or gain in this caption is transferred to the consolidated statement of comprehensive income to the extent that the hedged item impacts the consolidated statement of comprehensive income offsetting the effect in the same comprehensive income statement caption. Gains or losses from the ineffective portion of the hedging relationship are recognized directly in the statement of comprehensive income.

Hedge accounting is discontinued only when the hedging relationship (or a part of the relationship) fails to meet the required criteria, after making any rebalancing of the hedging relationship, if applicable. If it is not possible to continue the hedging relationship, including when the hedging instrument expires, is sold, settled or exercised, any gain or loss accumulated in equity at that date remains in the equity until the forecast transaction affects the statement of comprehensive income. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in equity is immediately transferred to the statement of income.

As a general rule, long-term commodity purchases or sales agreements are recognized in the statement of financial position at their fair value at the end of each reporting period, recognizing any differences in value directly in profit or loss, except for, when all of the following conditions are met:

- The sole purpose of the agreement is for its own use, which is understood as: for fuel purchase agreements such use is to generate electricity; for electrical energy purchased for sale, its sale is to the end-customers; and for electricity sales its sale is to the end-customers.

- The Group’s future projections evidence the existence of these agreements for own use.

- Past experience with agreements shows that they have been use for the Group’s “own use”, except for certain isolated cases when for exceptional reasons or reasons associated with logistical issues, these have been used for other purposes beyond the Group’s control and expectations.

- The agreement does not establish net settlement of differences and there has been no practice to settle similar differences in similar contracts in the past.

The long-term commodity purchase or sale agreements maintained by the Group, which are mainly for electricity, fuel, and other supplies, meet the conditions described above. Accordingly, the purpose of fuel purchase agreements is to use them to generate electricity, electricity purchase contracts for use in sales to end-customers, and electricity sale contracts for sale of the Group’s own products.

The Group also evaluates the existence of derivatives embedded in contracts or financial instruments to determine if their characteristics and risk are closely related to the host contract, provided that when taken as a whole they are not being accounted for at fair value. If they are not closely related, they are recorded separately and changes in value are accounted for directly in the statement of comprehensive income.

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g.6) Derecognition of financial assets and liabilities

Financial assets are derecognized when:

- The contractual rights to receive cash flows from the financial asset expire or have been transferred or, even when, the Group has assumed a contractual obligation to pay these cash flows to one or more recipients.

- The Group has substantially transferred all the risks and rewards of their ownership, or, if it has neither assigned nor retained substantially all the risks and rewards, when it does not retain control of the financial asset.

For transactions in which the Group retains substantially all the inherent risks and rewards of their ownership of the financial asset assigned, it recognizes them as a financial liability for the consideration received. Transactions costs are recognized in profit and loss by using the effective interest method (see Note 3.g.1).

Financial liabilities are derecognized when they are extinguished; i.e., when the obligation arising from the liability has been paid or cancelled or has expired. An exchange for a debt instrument with substantially different conditions, or a substantial modification in the current conditions of an existing financial liability (or a part thereof), is recorded as a cancellation of the original financial liability, and a new financial liability is recognized.

g.7) Offsetting of financial assets and financial liabilities

The Group offsets financial assets and liabilities and the net amount is presented in the statement of financial position only when:

- there is a legally binding right to offset the amounts recognized; and

- the Group intends to settle them on a net basis, or to realize the asset and settle the liability simultaneously.

Such rights may only be legally enforceable in the normal course of business, or in the event of default, or in the event of insolvency or bankruptcy, of one or all the counterparties.

g.8) Financial guarantee contracts

The financial guarantee contracts, defined as the guarantees issued by the Group to third parties, are initially measured at their fair value, adjusted for transaction costs that are directly attributable to the issuance of the guarantee.

Subsequent to initial recognition, financial guarantee contracts are recognized at the higher of:

- the amount of the liability determined in accordance with the accounting policy described in Note 3.m; and

- the amount of the asset initially recognized less, if applicable, any accumulated amortization recognized in accordance with the revenue recognition policies described in Note 3.q.

h)    Fair value measurement

The fair value of an asset or liability is defined as the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market, namely, the market with the greatest volume and level of activity for that asset or liability. In the absence of a principal market, it is assumed that the transaction is carried out in the most advantageous market available to the

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entity, namely, the market that maximizes the amount that would be received to sell the asset or minimizes the amount that would be paid to transfer the liability.

In estimating fair value, the Group uses valuation techniques that are appropriate for the circumstances and for which there is sufficient data to perform the measurement where it maximizes the use of relevant observable data and minimizes the use of unobservable data.

Given the hierarchy explained below, data used in the valuation techniques, assets and liabilities measured at fair value can be classified at the following levels:

● Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities;

● Level 2: Inputs other than quoted prices included in Level 1 that are observable for the assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices). The methods and assumptions used to determine the fair values at Level 2 by type of financial assets or financial liabilities take into consideration estimated future cash flows discounted at market rates. Future cash flows for financial assets and financial liabilities are discounted with the zero coupon interest rate curves for each currency (these valuations are performed using external tools such as Bloomberg).; and

● Level 3: Inputs for assets or liabilities that are not based on observable market data (unobservable inputs).

The Group takes into account the characteristics of the asset or liability when measuring fair value, in particular:

- For non-financial assets, fair value measurement takes into account the ability of a market participant to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset at its highest and best use;

- For liabilities and equity instruments, the fair value measurement assumes that the liability would not be settled, and an equity instrument would not be cancelled or otherwise extinguished on the measurement date. The fair value of the liability reflects the effect of non-performance risk, namely, the risk that an entity will not fulfill the obligation, which includes but is not limited to, the Company’s own credit risk;

- For derivatives not traded in active markets, the fair value is determined by using the discounted cash flow method and generally accepted options valuation models, based on current and future market conditions as of the closing date of the financial statements. This methodology also adjusts the value based on the Company’s own credit risk (Debt Valuation Adjustment, DVA), and the counterparty risk (Credit Valuation Adjustment, CVA). These Credit Valuation Adjustment CVA / Debt Valuation Adjustment DVA adjustments are measured on the basis of the potential future exposure of the instrument (asset or liability position) and the risk profile of both the counterparties and the Group itself.

- For financial assets and financial liabilities with offsetting positions in market risks or counterparty credit risks, measuring the fair value on a net basis is allowed. However, this must be consistent with the manner in which market participants would price the net risk exposure at the measurement date.

Financial assets and financial liabilities measured at fair value are shown in Note 23.3.

i)     Investments accounted for using the equity method

The Group’s interests in joint ventures and associates are recognized using the equity method of accounting.

Under the equity method of accounting, an investment in an associate or joint venture is initially recognized at cost. As of the acquisition date, the investment is recognized in the statement of financial position based on the share of equity that the Group’s interest represents in capital, adjusted for, if appropriate, the effect of transactions with the Group plus any goodwill generated in acquiring the company. If the resulting amount is negative, zero is recorded for that investment in the statement of financial position, unless the Group has a present obligation (either legal or constructive) to reinstate the Company’s equity position, in which case the related provision is recognized.

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The financial statements of associates or joint ventures are prepared for the same reporting period as the Group. When necessary, adjustments are made to align the accounting policies with those of the Group.

Goodwill from the associate or joint venture is included in the carrying amount of the investment. It is not amortized but is subject to impairment testing as part of the overall investment carrying amount when there are indicators of impairment.

Dividends received from these investments are deducted from the carrying amount of the investment, and any profit or loss obtained from them to which the Group is entitled based on its ownership interest is recognized under “Share of profit (loss) of associates accounted for using the equity method of accounting.”

The companies classified as “Associates” and “Joint Ventures” (see Notes 2.5 and 2.6, respectively) in these consolidated financial statements are accounted for under the equity method of accounting.

j)     Inventories

Inventories are measured at their weighted average acquisition cost or the net realizable value, whichever is lower. The net realizable value is the estimated selling price in the ordinary course of business less the applicable costs to sell.

The cost of inventories includes all costs of purchase and all necessary costs incurred in bringing the inventories to their present location and condition net of trade discounts and other rebates.

k)     Non-current assets (or disposal groups of assets) held for sale or held for distribution to owners and discontinued operations.

Non-current assets, including property, plant and equipment; intangible assets; investments accounted for using the equity method of accounting and joint ventures and disposal groups (a group of assets for disposal or distribution together with liabilities directly associated with those assets), are classified as:

- Held for sale, if their carrying amount will be recovered mainly through a sale transaction rather than through continuing use, or

- Held for distribution to owners, when the entity is committed to distribute the assets (or disposal groups) to the owners.

For the above classifications, the assets must be available for immediate sale or distribution in their present condition and their sale or distribution must be highly probable. For a transaction to be considered highly probable, management must be committed to the sale or distribution and actions to complete the transaction must have been initiated and should be expected to be completed within one year from the date of classification.

Actions required to complete the sale or distribution plan should indicate that it is unlikely that significant changes to the plan can be made or that the plan will be cancelled. The probability of shareholders’ approval (if required in the jurisdiction) should be considered as part of the assessment of whether the sale or distribution is highly probable.

The assets or disposal groups classified as held-for-sale or held for distribution to owners are measured at the lower of their carrying amount and fair value less costs to sell or costs to distribute, as appropriate.

Depreciation and amortization on these assets cease when they meet the criteria to be classified as non-current assets held for sale or held for distribution to owners.

Assets that are no longer classified as held for sale or held for distribution to owners, or are no longer part of a disposal group, are measured at the lower of their carrying amounts before being classified as held for sale or held for distribution, less any depreciation, amortization or revaluation that would have been recognized had they had not been

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classified as held for sale or held for distribution to owners and their recoverable amount at the date of reclassification as non-current assets.

Non-current assets held for sale and the components of the disposal groups classified as held for sale or held for distribution to owners are presented in the consolidated statement of financial position as a single line item within assets referred to as “Non-current assets or disposal groups held for sale or for distribution to owners”, and the related liabilities are presented as a single line item within liabilities referred to as “Liabilities included in disposal groups held for sale or for distribution to owners”.

The Group classifies as discontinued operations those components of the Group that either have been disposed of, or are classified as held for sale and:

- represent a separate major line of business or geographical area of operations;

- is part of a single coordinated plan to dispose of a separate major line of business or geographical area of operations; or;

- is a subsidiary acquired exclusively with a view to resale it.

The after-tax results of discontinued operations are presented in a single line of the statement of comprehensive income referred to as "Profit (loss) from discontinued operations", as well as the gain or loss recognized from the measurement at fair value less costs to sell or from the disposal of the assets or groups for disposal comprising the discontinued operation.

l)      Treasury shares

Treasury shares are presented deducting the caption “Total equity” in the consolidated statement of financial position and measured at acquisition cost.

Gains and losses from the disposal of treasury shares are recognized directly in “Total Equity – Retained earnings (losses)”, without affecting profit or loss for the period.  

m)     Provisions

Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material). The unwinding of the discount is recognized as finance cost. Incremental legal costs expected to be incurred in resolving a legal claim are included in measuring of the provision.

Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of resources embodying economic benefits will be required to settle the obligation, the provision is reversed.

A contingent liability does not result in the recognition of a provision. Legal costs expected to be incurred in defending a legal claim are expensed as incurred. Significant contingent liabilities are disclosed unless the likelihood of an outflow of resources embodying economic benefits is remote.

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m.1) Provisions for post-employment benefits and similar obligations

Certain of the Group’s companies have entered into pension and other similar commitments with their employees. Those defined benefit and defined contribution commitments are basically through pension plans, except for those related to certain benefits in lieu of payment, basically commitments to supply electric energy, which, due to their nature have not been outsourced and their coverage is provided through the related internal provision.

For defined benefit plans, the companies record the related expense for these commitments following the accrual criteria over the service life of the employees through timely actuarial studies performed as of the reporting date calculated applying the projected credit unit method. The cost of past services which correspond to variances in benefits is recognized immediately.

The defined benefit plan obligations in the statement of financial position represent the present value of the accrued obligations, upon deduction of the fair value of the different plans’ assets, if any.

Actuarial gains and losses arising from measurements of both the plan liabilities and the plan asset, are recorded directly as a component of "Other comprehensive income".

n)   Translation of balances in foreign currency

Transactions performed by each entity in a currency other than its functional currency are recognized using the exchange rates prevailing as of the date of the transactions. During the period, differences arising between the prevailing exchange rate at the date of the transaction and the exchange rate as of the date of collection or payment are recognized as “Foreign currency translation differences” in the consolidated statement of comprehensive income.

Likewise, at the end of each reporting period, balances or payable denominated in a currency other than each entity’s functional currency are remeasured using the closing date exchange rate. Any differences are recorded as “Foreign currency translation differences” in the consolidated statement of comprehensive income.

The Group has established a policy to hedge the portion of revenue from its consolidated entities that is directly linked to variations in the U.S. dollar, through obtaining financing in such currency. Exchange differences related to this debt, which is regarded as the hedging instrument in cash flow hedge transactions, are recognized, net of taxes, in other comprehensive income and are accumulated in an equity reserve and  recorded in  profit or loss in the term in which the cash flows hedged will be realized. This term has been estimated as ten years.

o)    Classification of balances as current and non-current

In these consolidated statements of financial position, assets and liabilities expected to be recovered or settled within twelve months are presented as current assets or liabilities, except for post-employment and other similar obligations. Those assets and liabilities expected to be recovered or settled in more than twelve months are presented as non-current items. Deferred income tax assets and liabilities are classified as non-current.

When the Group has any obligations that mature in less than twelve months but can be refinanced over the long term at the Group’s discretion, through unconditionally available loan agreements with long-term maturities, such obligations are classified as non-current liabilities.  

p)    Income taxes

Income tax expense for the period is determined as the sum of current taxes from each of the Group’s subsidiaries and results from applying the tax rate to the taxable income for the period, after deductions allowed have been made, plus any changes in deferred tax assets and liabilities and tax credits, both for tax losses and deductions. Differences between the carrying amount and tax basis of assets and liabilities generate deferred tax assets and liabilities, which are calculated using the tax rates expected to applied when the assets and liabilities are realized or settled, based on tax rates that have been enacted or substantively enacted by the end of the reporting period.

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Deferred tax assets are recognized for all deductible temporary differences, tax losses and unused tax credits to the extent that it is probable that sufficient future taxable profits exist to recover the deductible temporary differences and use the tax credits. Such deferred tax asset is not recognized if the deductible temporary difference arises from the initial recognition of an asset or liability that:

- did not arise from a business combination; and

- at initial recognition provide it affected neither accounting profit nor taxable profit (loss).

With respect to deductible temporary differences associated with investments in subsidiaries, associates and joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profits will be available against which the temporary differences can be utilized.

Deferred tax liabilities are recognized for all temporary differences, except for those derived from the initial recognition of goodwill and those that arose from investments in subsidiaries, associates and joint ventures in which the Group can control their reversal and where it is probable that they will not be reversed in the foreseeable future.

Current tax and changes in deferred tax assets or liabilities are recorded in profit or loss, other comprehensive income or total equity in the statement of financial position, depending on where the gains or losses that triggered these tax entries have been recognized.

Any tax deductions that can be applied to current tax liabilities are credited to earnings within the line item “Income tax expenses”, except when uncertainty exits about their tax realization, in which case they are not recognized until they are effectively realized, or when they relate to specific tax incentives, in which case they are recorded as grants.

At the end of each reporting period, the Group reviews the deferred tax assets and liabilities recognized, and makes, if any necessary corrections based on the results of this analysis.

Deferred tax assets and deferred tax liabilities are offset in the consolidated statement of financial position if the Group has a legally enforceable right to set off current tax assets against current tax liabilities, and only when the deferred taxes relate to income taxes levied by the same tax authority.

q)    Revenue and expense recognition

Revenue is recognized when (or as) the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which the Group is expected to be entitled for said transfer of control, excluding the amounts collected on behalf of third parties.

The Group analyzes and takes into consideration all the relevant facts and circumstances for revenue recognition, applying the five step model established by IFRS 15: 1) Identifying the contract with a customer; 2) Identifying the performance obligations; 3) Determining the transaction price; 4) Allocating the transaction price; and 5) Recognizing revenue.

The following are the criteria for revenue recognition by type of good or service provided by the Group:

● Electricity supply (sale and transportation): Corresponds to a single performance obligation that transfers to the customer a number of different goods/services that are substantially the same and that have the same transfer pattern. Since the customer receives and simultaneously consumes the benefits provided by the Company, it is considered a performance obligation met over time. In these cases, the Group applies an output method to recognize revenue in the amount to which it is entitled to bill for electricity supplied to date.

- Generation: revenue is recorded according to the physical deliveries of energy and power, at the prices established in the respective contracts, at the prices established in the electricity market by the current regulations,

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or at the marginal cost of energy and power, depending on whether they are unregulated customers, regulated customers or energy trading in the spot market are involved, respectively.

- Distribution of electricity: Revenue is recognized based on the amount of energy supplied to customers during the period, at prices established in the related contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate.

These revenues include an estimate of the service provided and not invoiced, through the reporting date of the financial statements (see Notes 2.3 and, 28 and Appendix 2.2).

● Gas sale and transport: revenue is recognized over time based on the actual physical deliveries of gas in the consumption period, at the prices established in the respective contracts.

● Other Services: mainly the provision of supplementary services to the electricity business, construction of works and engineering and consulting services. Customers control committed assets as they are created or improved. Therefore, the Company recognizes this revenue over time based on the progress, measuring progress through output methods (percentage of completion through the present date, milestones reached, etc.), or costs incurred (resources consumed, hours of labor spent, etc.), as appropriate in each case.

● Sale of goods: revenue from the sale of goods is recognized at a certain time, when control of the goods has been transferred to the customer, which generally occurs at the time of the physical delivery. Revenues are measured at the independent sale price of each good, and any type of applicable variable compensation.

In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance obligations of the transaction, based on the control transfer pattern of each good or service that is separate and an independent selling price allocated to each of them, or jointly to two or more transactions, when these are linked to contracts with customers that are negotiated with a single business purpose and  the goods and services committed represent a single performance obligation and their selling prices are not independent.

The Group determines the existence of significant financing components in its contracts, adjusting the value of the consideration if applicable, to reflect the effects of the time value of money. However, the Group applies the practical expedient provided by IFRS 15, and will not adjust the value of the consideration committed for the purpose of a significant financing component, if it expects, at the beginning of the contract, that the period between the payment and the transfer of goods or service to the customer is one year or less.  

The Group excludes the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue amount. The Group only records as revenue the payment or commission to which it expects to be entitled.

Because the Group mainly recognizes revenue for the amount to which it has the right to invoice, it has decided to apply the disclosure practical expedient provided in IFRS 15, through which it is not required to disclose the aggregate amount of the transaction price allocated to the performance not met (or not met partially) at the end of the reporting period.

In addition, the Group evaluates the existence of incremental costs of obtaining a contract and costs directly related to the fulfillment of a contract. These costs are recognized as an asset, if their recovery is expected, and amortized in a manner consistent with the transfer of the related goods or services. As a practical expedient, the incremental costs of obtaining a contract are recognized as an expense, if the depreciation period of the asset that has been recognized is one year or less. Costs that do not qualify for capitalization are recognized as expenses at the time they are incurred, unless they are explicitly attributable to the customer.  

As of December 31, 2020 and 2019, the Group has not incurred costs to obtain or perform a contract which meet the conditions for their capitalization. The costs incurred to obtain a contract are substantially commission payments for

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sales that, although are incremental costs, relate to short-term contracts or performance obligations that are met at a certain time, therefore, the Group has decided to recognize these costs as an expense when they occur.

Interest income (expenses) are recorded considering the effective interest rate applicable to the principal pending amortization, during the related accrual period.

r)    Earnings per share

Basic earnings per share are calculated by dividing net income attributable to shareholders of the Parent Company by the weighted average number of ordinary shares of outstanding during the period, excluding the average number of shares of the Company held by other subsidiaries within the Group, if any.

Basic earnings per share for continuing and discontinued operations are calculated by dividing net income from continuing and discontinued operations attributable to shareholders of the Company (the numerator) by the weighted average number of shares of common stock outstanding (the denominator) during the year, excluding the average number of shares of the Company held by other subsidiaries within the Group.

Diluted earnings per share is calculated by dividing profit attributable to shareholders of the Parent Company by the weighted average number of ordinary shares outstanding during the period plus the weighted average number of ordinary shares of that would be issued on conversion of all the potential dilutive securities into ordinary shares, if any.

s)Dividends

Article No. 79 of Law No. 18,046 (the “Chilean Corporations Act”), establishes that, unless unanimously agreed otherwise by the shareholders of all issued shares, listed corporations must distribute a cash dividend to shareholders on an annual basis, pro rata among the shares owned or the proportion established in the Company’s by-laws if there are preferred shares, of at least 30% of profit for each year, except when accumulated losses from prior years must be absorbed.

As it is practically impossible to achieve a unanimous agreement given Enel Américas’ highly fragmented share ownership, at the end of each reporting period the amount of the minimum statutory dividend obligation to its shareholders is determined, net of interim dividends approved during the period, and then accounted for in “Trade and other payables, currrent”, current” and “Current accounts payable to related parties”, as appropriate, and recognized in equity.

The interim and final dividends are deducted from equity when approved by the relevant authority, which in the first case is normally the Board of Directors and in the second case is the responsibility of the shareholders as agreed at a General Shareholders’ Meeting.

t)    Share issuance costs

Share issuance costs, only when they represent incremental expenses directly attributable to the transaction, are recognized directly in net equity as a deduction from “Share premiums,” net of any applicable taxes.

If the share premium account has a zero balance or if the costs described exceed the balance, they are recognized in “Other reserves”. Subsequently, these costs must be deducted from paid-in capital, and this deduction that must be approved at the Extraordinary Shareholders’ Meeting, which occurs immediately after the date on which the disbursements were incurred.

Share issuance and placement expenses directly related to a probable future transaction are recorded as prepaid expenses in the statement of financial position. These expenses are recorded in equity upon issuance and placement of the shares, or in profit or loss when the condition changes and the transaction is no longer expected to occur.

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u)    Statement of cash flows

The statement of cash flows reflects changes in cash and cash equivalents that took place during the period, determined with the direct method. It uses the following definitions and related meanings:

- Cash flows: inflows and outflows of cash or cash equivalents, which are defined as highly liquid investments maturing in less than three months with a low risk of changes in value.

- Operating activities: the principal revenue-producing activities of the Group that cannot be considered investing or financing activities.

- Investing activities: the acquisition and disposal of long-term assets and other investments not included in cash and cash equivalents.

- Financing activities: activities that result in changes in the size and composition of the total equity and borrowings of the Group.

4.    SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS

a) Regulatory Framework

The Chilean electricity sector is regulated by the General Law of Electricity Services No. 20,018, contained in DFL No. 1 of 1982, of the Ministry of Mining, whose restated and coordinated text was established by DFL No. 4 of 2006 of the Ministry of Economy (“Electricity Law”) and its corresponding Regulations, contained in DS No. 327 of 1998.

The main authority on energy matters is the Ministry of Energy, which is responsible for proposing and conducting public policies on energy, strengthening coordination, and facilitating a comprehensive vision of the sector. It was created on February 1, 2010 as an autonomous body, after years of being part of the Ministry of Mining.

Within the Ministry of Energy is the regulatory body of the electricity sector (the National Energy Commission) and the oversight entity (the Superintendency of Electricity and Fuels). The Ministry also includes the Chilean Commission of Nuclear Energy (CChEN) and the Energy Sustainability Agency.

The National Energy Commission (CNE) has the authority to propose regulated rates, approve transmission expansion plans, and create instruction plans for the construction of new generation units. Meanwhile, the Superintendency of Electricity and Fuels (SEF) supervises and oversees compliance with laws, regulations, and technical standards for the generation, transmission and distribution of electricity, liquid fuels, and gas.

Additionally, the legislation considers a Panel of Experts, composed of expert professionals whose key job is to decide on any discrepancies produced in terms of the matters established in the Electricity Law and in the application of other laws on energy, through binding rulings.

The Law establishes a National Electric Coordinator, an independent body of public law, responsible for the operation and coordination of the Chilean electricity system, whose main objectives are: i) To preserve the security of the service, ii) To guarantee the economic operation of the electricity system's interconnected facilities, and iii) To guarantee free access to all transmission systems. Its main activities include coordinating the Electricity Market, authorizing connections, managing complementary services, implementing public information systems, monitoring competition and the payment chain, among others.

From a physical perspective, the Chilean electricity sector is divided into three main electricity systems: the National Electricity System (SEN) and two isolated medium-sized systems: Aysén and Magallanes. The SEN was created from the interconnection of the Central Interconnected System (SIC) and the Great North Interconnected System (SING) in November 2017. Until the interconnection, the SIC was the country's main system, extending longitudinally across

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2,400 km, and linking Taltal, to the north, to Quellon on the Island of Chiloe, to the south. Meanwhile, the SING covered the north of Chile, from Arica to Coloso, covering a length of 700 km.

The Chilean electricity industry can be divided into three main activities: Generation, Transmission and Distribution. The electricity facilities associated with these three activities have the obligation to operate in an interconnected and coordinated manner, with the primary objective of providing electricity to the market at minimal cost and within the service quality and safety standards required by the electricity regulations.

Due to their essential nature, the Transmission and Distribution activities constitute natural monopolies, therefore their segments are regulated as such by the electricity regulations, requiring free access to the grids and definition of regulated rates.

In the electricity market, two products (Energy and Capacity) are traded and different services are provided. In particular, the National Electric Coordinator is responsible for making balances, determining the corresponding transfers between generators, and calculating the marginal time-specific cost, the price at which energy transfers are valued. On the other hand, the CNE determines the prices of Capacity.

Consumers are classified according to the size of their demand as regulated or free customers. Regulated customers are those with a connected capacity lower than 5,000 kW. However, customers with connected capacity between 500 kW and 5,000 kW may choose between the free or regulated rate system.

Integration and Concentration Limits

In Chile, there is legislation to defend free competition, which along with the specific regulations applicable to electricity, define the criteria to avoid certain levels of economic concentration and/or abusive market practices.

In principle, companies are allowed to participate in different activities (generation, distribution, commercialization) as long as there is adequate separation of these, both in accounting and corporate terms. Nevertheless, the transmission sector is where most restrictions are imposed, mainly due to its nature and the need to guarantee proper access to all agents. The Electricity Law defines the limits of participation for generation or distribution companies in the National Transmission segment, and prohibits the participation of the National Transmission companies in the generation and distribution segment.

a.1 Generation Segment

Generation companies must operate under the Coordinator's operations plan. However, each company can freely decide to sell its energy and capacity to regulated or unregulated customers. Any surplus or deficit between their sales to customers and production is sold to or bought from other generators at the spot market price.

A generation company may have the following types of customers:

● Free Customers, users with a connected capacity of more than 5,000 kW. (mainly industrial and mining companies), or customers with connected capacity between 500 and 5,000 kW that choose to be a free customer, for at least four years. These consumers can freely negotiate their electricity supply prices with suppliers.

● Distribution Companies, which deliver supply to their regulated customers. Distribution companies buy energy from generation companies through a public bid process regulated by the CNE.

● Other Generation Companies: The relationship between generation companies may exist either through bilateral contracts or transfers in the short-term or Spot Market. The latter correspond to energy and capacity transactions among generation companies coordinated by the National Electric Coordinator to achieve the cost-effective operation of the system; any surplus (deficit) in production with respect to their commercial commitments are transferred through sales (purchases) to other generators within the system, valuing energy at marginal cost and capacity at the corresponding regulated price established bi-annually by the authority.

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In Chile, the capacity to be paid to each generator depends on a calculation performed centrally by the National Electric Coordinator each year, based on current regulations, in order to obtain the sufficiency capacity for each plant. This value depends primarily on the availability of the facilities themselves and the technology-specific generation resource.

Non-Conventional Renewable Energies

Law No. 20,257 of April 2008, promotes the use of Non-Conventional Renewable Energies (NCRE). The main aspect of this law is that it required generators, between 2010 and 2014, to ensure that at least 5% of their energy sold to customers came from renewable sources, progressively increasing by 0.5% between 2014 and 2024, to reach 10%. This Law was modified in 2013 by Law No. 20.698, entitled 20/25, which establishes that by the year 2025, 20% of the electricity matrix will be covered by NCRE, respecting the withdrawal plan provided by the previous law for contracts effective as of July 2013.

a.2 Transmission Segment

The transmission systems comprise lines and substations within an electricity system and which are not distribution facilities. These are divided into five segments: National Transmission, Transmission for Development Hubs, Zonal Transmission, Dedicated Transmission, and International Interconnected Systems.

The transmission facilities are subject to an open access system and may be used by any interested user under non-discriminatory conditions. The remuneration of the existing facilities in the National Transmission and Zonal Transmission segments is determined through a fee-setting process performed every four years. This process determines the Annual Value of Transmission, which includes efficient operating and maintenance costs and the annual value of investment, determined according to a discount rate (7% minimum after taxes) set by the authority every four years based on a study and the economic useful lives of the facilities.

The planning of the National Transmission and Zonal Transmission systems is a regulated and centralized process, where each year the National Electric Coordinator issues an expansion plan that is published by the CNE in a call for proposals. The Expansion Plan report can receive observations by participants and must be ultimately approved by the CNE.

The expansions of both systems is performed through open bids, distinguishing between new works and expansion works on existing facilities. In the case of new works, the execution is subject to bid and the winning bidder takes over ownership of the facility. In the case of the expansion works on existing facilities, the original owner of the facility is also the owner of its expansion, but the construction must be awarded by bid. Both types of bids are managed by the Coordinator.

The remuneration of new works corresponds to the resulting value of the bid, which constitutes income for the first 20 years of operation. Meanwhile, the remuneration of new works includes the resulting value of investment from the bid and the applicable operations and maintenance costs. In both cases, as of the 21st year, the remuneration of these transmission facilities is determined as if they were existing facilities.

Current regulations define that transmission is remunerated by the sum of rate revenue and the collection of charges for the use of the transmission systems. These charges are defined ($/kWh) by the CNE twice a year.

a.3 Distribution Segment

The distribution system corresponds to electric facilities aimed at supplying electricity to final customers, at a maximum voltage of 23 kV.

Distribution companies operate under a public service concessions system and are required to provide service to all customers and supply electricity to all customers subject to regulated rates (clients with connected capacity less than 5,000 kW, with the exception of customers between 500 and 5,000 kW who may opt for the free rate). Note that free-

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rate customers may negotiate their supply with any supplier, and must pay a regulated toll for using the distribution network.

Regarding the supply for users subject to price regulation, the law establishes that distribution companies must provide an ongoing energy supply, based on open, non-discriminatory and transparent public bids. These bid processes are designed by the CNE and carried out at least 5 years ahead of time, with a supply contract agreement of up to 20 years. In the case of unforeseen variations in demand, the authority has the power to carry out a short-term bid. There is also a regulated procedure to remunerate potential supply not under contract.

The fee-setting in this segment is performed every four years based on a cost study to determine the Added Value of Distribution (AVD). The AVD is determined according to an efficient model company scheme and the concept of typical area.

On December 21, 2019, the Ministry of Energy published Law No. 21,194 (Short Law) which reduces the Profitability of Distribution Companies and modifies the Electricity Distribution rate process.

To determine the AVD, the CNE classifies companies with similar distribution costs into groups known as “typical areas.” For each typical area, the CNE engages independent consultants to carry out a study to determine the costs associated with an efficient model company, considering fixed costs, average energy and capacity losses, and standard investment, maintenance, and operating costs related to distribution, including some restrictions faced by real distribution companies. The annual costs of investment are calculated considering the New Replacement Value (NRV) of the facilities adapted to demand, their useful life, and a rate of renewal, calculated every four years by the CNE, which must be an annual rate between 6% and 8% after taxes.

Subsequently, the rates are structured and the economic profitability rate after taxes is validated, which may not differ by more than two points higher or three points lower than the rate defined by the CNE.

Additionally, and along with the calculation of the AVD, every four years the CNE reviews the Related Services not consisting of energy supply which the Free Competition Defense Court qualifies as subject to rate regulation.

The Chilean distribution rate model is a consolidated model, with nine price-setting processes carried out since the General Law of Electricity Services was ratified in 1982.

b) Regulatory Matters

Laws 2019 - 2020

(i) Law No. 21,185 – Creates a Transitory Mechanism to Stabilize Electricity Prices for Customers Subject to Rate Regulation.

On November 2, 2019, the Ministry of Energy published Law No. 21.185, which creates a Transitory Mechanism to Stabilize Electricity Prices for Customers Subject to Rate Regulation. Through this Law, between July 1, 2019 and December 31, 2020, the prices to be transferred to regulated customers are the price levels defined for the first half of 2019 (Decree 20T/2018) to be referred to as “Stabilized Price to Regulated Customers” (PEC). Between January 1, 2021 and until the end of the stabilization mechanism, prices shall be those defined in the semiannual price-setting processes referred to in article 158 of the Electricity Law, but may not be higher than the adjusted PEC according to the Consumer Price Index as of January 1, 2021, based on the same date (adjusted PEC). Any billing differences that arise will generate an account receivable in favor of the generators, up to a limit of MUS$ 1,350 until 2023. The balance must be recovered by December 31, 2027. The technical provisions on this mechanism are established in Exempt Resolution No. 72/2020, of the National Energy Commission, and its modifications.

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(ii) Law No. 21,194 - Reduces the Profitability of Distribution Companies and modifies the Electricity Distribution rate process

On December 21, 2019, the Ministry of Energy published Law No. 21,194, which reduces the Profitability of Distribution Companies and modifies the Electricity Distribution rate process. This Law eliminates the proportion of two-thirds for the AVD study performed by the CNE and one-third for the AVD study done by distribution companies, replacing it with a single study ordered by the CNE. On the other hand, it modifies the renewal rate for the calculation of annual investment costs from an annual real rate of 10% to a rate calculated by the CNE every four years, which shall be an annual rate that may be no less than 6% and no greater than 8% after taxes. The economic profitability rate after taxes for distribution companies must not differ by more than two points higher or three points lower than the rate defined by the CNE. Additionally, distribution companies must have an exclusive line of business as of January 2021.

(iii) CNE Exempt Resolution No. 176 /2020 - Exclusive Line of Business

On June 9, 2020, Exempt Resolution No. 176 was published in the Official Gazette. This resolution determines the scope of the Exclusive Line of Business and Separate Accounting obligations, for the provision of public electricity distribution service in accordance with Law No.21,194.

According to this Resolution and its modifications, the distribution companies acting as public service concessions companies and operating in the National Electricity System must be constituted exclusively as distribution companies and may only perform economic activities aimed at providing public distribution services, in accordance with the requirements established by Law and current regulations. The requirements contained in said Resolution shall be applied starting January 1, 2021. Notwithstanding the above, those operations that by nature cannot be performed prior to this date must be reported and justified to the CNE, including a planning schedule and the compliance periods for the respective requirements, which under no circumstances may exceed January 1, 2022.

(iv) Law No. 21,249 – Exceptional provision of the measures indicated for final users of water and sanitation, electricity, and gas services. Last modification to Law No. 21,301

On August 8, 2020, the Law on Utility Services was passed. This law considers extraordinary measures to support the most vulnerable customers, although Enel Distribución Chile had already been applying most of these measures. These measures include the suspension of the electricity supply disconnection due to default and the possibility of signing agreements to pay off electricity debt in installments, in both cases, for a group of vulnerable customers. The suspended disconnection benefit was for a duration of 90 days following publication of the Law, and debts accumulated by customers covered by this measure must be paid within a maximum of 12 installments from the end of the grace period.

On December 29, 2020, Law No. 21,301 was ratified and extended the terms defined in Law No. 21,249, establishing a benefit duration of 270 days following ratification of this new Law, as opposed to the initial 90 days. Likewise, the number of installments was modified to a maximum of 36, instead of the previously defined maximum of 12 installments.

(v) Law No. 21,304 - Electricity Supply for Electro-Dependent Individuals

On January 21, 2021, the Law on Electro-Dependent Individuals was passed to address home healthcare patients whose health treatment requires them to be physically connected permanently or temporarily to a medical device that operates on electricity.

The law establishes that concessions companies must keep a record of electro-dependent individuals residing in their respective concessions zones, who have a certificate from their attending physician to accredit such condition, indicating the medical device they require for treatment and its characteristics.

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On the other hand, concessions companies must implement any technical solutions to help mitigate the effects of interruptions to the electricity supply, and prioritize reestablishing service to the residence of electro-dependent individuals. Moreover, they must incorporate a mechanism between the home’s central connection system and the medical devices to measure the consumption, at the company’s expense, and this measurement must be discounted from the home's monthly total consumption.

This law will go into effect once the respective regulations have been issued, within six months from the publication of the law.

(vi)Electricity Portability Bill

On September 9, 2020, a bill was filed at the Chamber of Representatives for the purpose of modifying the General Law on Electricity Services in order to establish the right to electricity portability and introduce the figure of energy commercializer. This would uncouple all services that may be offered to the distribution company's final customers, so that the distribution company be dedicated exclusively to the operation of its grids. It considers a transition period to be defined in future decrees, so that regulated consumers in certain areas may gradually obtain the freedom to choose their commercializer. The main point of discussion of this bill is related to the gradual market liberalization and could affect existing regulated contracts.

CNE 2020 Regulatory Plan

By way of Exempt Resolution No. 776 of December 16, 2019, in accordance with the provisions of article 72-19 of the General Law on Electrical Services, the CNE published its Annual Work Plan for the creation and development of the technical regulations for 2020. The document defines the general guidelines and programming priorities of the CNE 2020 Regulatory Work Plan and the regulatory procedures pending from the 2019 Plan, which continued to be developed during 2020.

By way of Exempt Resolutions No. 231 and 313 of June 30, 2020 and August 19, 2020, respectively, Exempt Resolution No. 776 on the 2020 regulatory plan was modified.

CNE 2021 Regulatory Plan

By way of Exempt Resolution No. 471 of December 15, 2020, in accordance with the provisions of article 72-19 of the General Law on Electrical Services, the CNE published its Annual Work Plan for the creation and development of the technical regulations for 2021. The document defines the general guidelines and programming priorities of the CNE 2021 Regulatory Work Plan and the regulatory procedures pending from the 2020 Plan, which will begin or continue to be developed during 2021.

Regulations Published in 2019 - 2020

Regulations on Complementary Services. On March 27, 2019, the Ministry of Energy published Decree No. 113/2017, with the Regulations on Complementary Services as referred to in article No. 72-7 of the General Law of Electricity Services, with deferred application from January 1, 2020.

Regulations on the Coordination and Operation of the National Electricity System. On December 20, 2019, the Ministry of Energy published Decree No. 125/2017 with the Regulations on the Coordination and Operation of the National Electricity System.

Regulation Standard 4. On March 5, 2020, the Ministry of Energy published Decree No. 8/2019 with the Regulations on the Security of Electricity Consumption Facilities.

Regulations on the Valuation of Transmission. On June 13, 2020, the Ministry of Energy published Decree No. 10/2019 with the Regulations on the Rating, Valuation, Price-Setting, and Remuneration of Transmission Facilities.

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Regulations on Net billing. On September 24, 2020, the Ministry of Energy published Decree No. 57/2019 with the Regulations on Distributed Generation for Self-Consumption.

Regulations on the Planning of Transmission. On October 30, 2020, Decree No. 37/2019 was refiled at the Office of the Comptroller General of the Republic. This decree approves the Regulations on Transmission Systems and the Planning of Transmission, which is still pending approval.

Modification to the Regulations on Sufficiency Capacity. On December 26, 2020, the Ministry of Energy published Decree No. 42 which modifies the Regulations on Capacity in force in Supreme Decree 62/2006. These Regulations incorporate the State of Strategic Reserve, which recognizes a proportion of the sufficiency capacity of plants that are withdrawn from the system within the framework of the decarbonization plan within 5 years from the date of announcement.

Additionally, it establishes a calculation methodology to recognize the sufficiency capacity for hydroelectric plants with storage capacity.

Expansion of Transmission

2017 Transmission Expansion Plan

In compliance with the process phases stipulated by law, the Ministry of Energy published Exempt Decree No. 293/2018 on November 8, 2018, which establishes the Expansion Works to the National and Zonal Transmission Systems to begin their bid process during the following twelve months (later modified by Exempt Decree No. 202/2019 of August 13, 2019).  

On January 9, 2019, the Ministry of Energy published Exempt Decree No. 4/2019, which establishes the New Works on the National and Zonal Transmission Systems to begin their bid process during the following twelve months.

2018 Transmission Expansion Plan

In compliance with the process phases stipulated by law, the Ministry of Energy published Exempt Decree No. 231/2019 on September 24, 2019, which establishes the New Works on the National and Zonal Transmission Systems to begin their bid process or fringe studies, as applicable, during the following twelve months.

On August 10, 2019, the Ministry of Energy published Exempt Decree No. 198/2019, which establishes the Expansion Works to the National and Zonal Transmission Systems to begin their bid process during the following twelve months, corresponding to the 2018 expansion plan.

2019 Transmission Expansion Plan

In compliance with the process phases stipulated by law, the Ministry of Energy published Exempt Decree No. 185/2020 on October 2, 2020, which establishes the New Works on the National and Zonal Transmission Systems to begin their bid process or area studies, as applicable, during the following twelve months, according to the 2019 expansion plan.

On September 14, 2020, the Ministry of Energy published Exempt Decree No. 171/2020, which establishes the Expansion Works to the National and Zonal Transmission Systems to begin their bid process during the following twelve months, corresponding to the 2019 expansion plan.

2020 Transmission Expansion Plan

In accordance with article 91 of Law 20,936/2016, which establishes the Transmission Planning Procedure, the National Electric Coordinator sent the expansion proposal for the different transmission segments to the CNE on January 22, 2020. Subsequently, the CNE issued a call to submit proposals for Transmission Expansion projects by April 22, 2020, although this deadline was extended to May 27, 2020 by Exempt Resolution No. 132/2020.

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c. Tariff Revisions and Supply Processes

c.1  Distribution Price-Setting 2016 - 2020

The price-setting process for the 2016-2020 period culminated on August 24, 2017 with the publication of Decree No. 11T/2016 in the Official Gazette, which establishes the distribution rate formulas effective from November 4, 2016.

On September 28, 2018, the Ministry of Energy Decree No. 5T went into effect, updating Decree No. 11T/2016 by the same Ministry and modifying the electricity rates in force for the distribution segment until the next price-setting process.

On July 26, 2019, through Ordinary Official Letter No. 15699/2019, the SEF instructed a plan of action to apply the adjustment indicated in the CNE Ordinary Official Letter No. 490/2019, with respect to the Ministry of Energy Decree No. 5T/2018. The adjustment was effective retroactively from September 28, 2018.

The final customer rates that have governed during 2020 are determined according to the following decrees and resolutions:

i) Decree No. 11T/2016, which establishes the rate formulas applicable to electricity supply subject to regulated prices, published in the Official Gazette on August 24, 2017, was effective retroactively from November 4, 2016.

ii) Decree No. 2T/2018, which establishes the rate formulas applicable to electricity supply subject to regulated prices, published in the Official Gazette on June 27, 2018, and which is effective for the four-year period from November 2016 to November 2020.

iii) Decree No. 5T/2018, which establishes the rate formulas applicable to electricity supply subject to regulated prices as indicated in Decree No. 11T of 2016, published in the Official Gazette on September 28, 2018, and which was effective from the date of publication.

iv) SEF Ordinary Official Letter No. 15699/2019, which instructs the action plan for the adjustment informed in CNE Ordinary Official Letter No. 490/2019, with respect to the Ministry of Energy Decree No. 5T/2018, effective retroactively from September 28, 2018 to November 3, 2020.

v) Decree No. 6T/2017, which establishes the Annual Value by Bracket for Zonal and Dedicated Transmission Facilities used by users subject to price regulation, its rates and indexing formulas for 2018-2019, published by the Ministry of Energy in the Official Gazette on October 5, 2018, and effective from January 1, 2018 to December 31, 2019.

vi) Price Decrees:  

- Average Regulated Prices:

On May 6, 2019, the Ministry of Energy published Decree No. 20T/2018 in the Official Gazette, which establishes the average regulated prices in the national electricity system, as well as the adjustments and surcharges upon application of the Residential Rate Equality Mechanism, effective retroactively as of January 1, 2019.

On October 5, 2019, the Ministry of Energy published Decree No. 7T/2019 in the Official Gazette, which establishes the average regulated prices in the national electricity system, as well as the adjustments and surcharges upon application of the Residential Rate Equality Mechanism, effective retroactively from July 1, 2019.

On November 2, 2019, the Ministry of Energy published Law No. 21,185, which creates a Transitory mechanism to stabilize electricity prices for customers subject to rate regulation. Article 5 of this Law repeals Decree 7T/2019, and extends the effective term of Decree No. 20T/2018 from its original effective date until the publication of the subsequent average regulated price decree.

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On November 2, 2020, the Ministry of Energy published Decree No. 6T/2020 in the Official Gazette, which establishes the average regulated prices in the national electricity system, as well as the adjustment factor for application of the price stabilization transitory mechanism considered in Law No. 21,185, effective from January 1, 2020. Given the price stabilization mechanism, the publication of this decree had no effect on the final regulated customer rate.

- Short Term Regulated Prices

On October 23, 2019, the Ministry of Energy published Decree No. 9T/2019, which establishes the regulated prices for electricity supply, effective retroactively from October 1, 2019.

On April 7, 2020, the Ministry of Energy published Decree No. 2T/2020, which establishes the regulated prices for electricity supply, effective from April 1, 2020.

On December 3, 2020, the Ministry of Energy published Decree No. 12T/2020, which establishes the regulated prices for electricity supply, effective from October 1, 2020.

c.2 Distribution Price Setting 2020-2024

Through Exempt Resolution No. 24 of January 21, 2020, the CNE published the Preliminary Technical Terms and Conditions for calculating the components of the Added Value of Distribution for the 2020-2024 period, and the Cost Study on electricity supply-related services, initiating the distribution price setting process for the corresponding four-year period.

In compliance with the process phases established by law, the interested parties made observations on the terms and conditions and submitted discrepancies to the Panel of Experts. Then, on June 11, 2020, the CNE published the Final Technical Terms and Conditions in Exempt Resolution No. 195.

On July 17, 2020, Exempt Resolution No. 256 constituted the Cost Studies Committee established in article 183 bis of the General Law of Electricity Services. Through Exempt Resolutions No. 336 and 366 of September 1, 2020 and September 24, 2020, respectively, updates were incorporated to Exempt Resolution No. 256 regarding the primary and alternate representatives.

On August 18, 2020, the CNE informed that the Added Value of Distribution 2020-2024 study had been awarded to the company INECON, which was the fourth bid awarded for this type of study.

On November 17, 2020, Progress Report No. 1 of the study was submitted, and Exempt Resolution No. 4 of January 4, 2021 extended the deadlines for Progress Report No. 2 and the Final Report to February 8, 2021 and March 8, 2021, respectively.

c.3 Price Setting for Distribution-Related Services

On July 24, 2018, the Ministry of Energy published Decree No. 13T/2018 in the Official Gazette, which establishes the prices of Services other than energy supply related to electricity distribution. These prices were effective from the date of publication of said decree and are still in force to date.

According to legislation, a new price-setting process for Services other than energy supply related to electricity distribution shall be performed at the same time as the Distribution Price Setting for 2020-2024.

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c.4 Zonal Transmission Price Setting

On October 5, 2018, the Ministry of Energy published Decree No. 6T/2017, which establishes the annual value by bracket of zonal and dedicated transmission facilities used by users subject to price regulation, its rates and indexing formulas for 2018-2019.

c.5 Zonal Transmission Price Setting 2020-2023

Within the framework of the Transmission Price Setting 2020-2023, the following processes are performed: Rating of Transmission System Facilities, Determination of the Useful Life of Transmission Facilities, and Definition of the Technical and Administrative Terms and Conditions for the Transmission Facilities Appraisal Study.

In this context, for the purposes of the Rating of Transmission System Facilities for the 2020-2023 period, in late 2017 the Regulator issued a preliminary technical report defining which transmission facilities correspond to each segment (National, Zonal and Dedicated). In compliance with the phases established by law, on April 9, 2019, the CNE issued the Final Technical Report through Exempt Resolution No. 244.

In addition, for the purposes of determining the Useful Life of Transmission Facilities, on June 5, 2018, the CNE approved the Final Technical Report to determine Useful Lives, through Exempt Resolution No. 412.

Finally, for the purposes of defining the Technical and Administrative Terms and Conditions for the Transmission Facilities Appraisal Study, the CNE published the Preliminary Technical and Administrative Terms and Conditions at the end of 2017. In general terms, this document governs the process for engaging the price study and defines the rules for performing a price study for all transmission, defining bids for two studies: one for National Facilities and another for Zonal and Dedicated Facilities.

In compliance with the phases considered by Law, the CNE issued Exempt Resolution No. 272 on April 26 2019 which approved the Final Technical and Administrative Terms and Conditions for the Transmission Facilities Appraisal Study. On December 11, 2019, the CNE issued Exempt Resolution No. 766 to correct the previous resolution.

In compliance with the phases considered by Law, the CNE constituted a Committee for awarding and overseeing the transmission facilities appraisal studies, through Exempt Resolution No. 271 of April 26, 2019. Additionally, and through Exempt Resolution No. 678 of October 4, 2019, it approved the Service Provision Agreement for the performance of the National Transmission Study, while on January 7, 2020, it approved the Service Provision Agreement for the Zonal and Dedicated Transmission Study.

With respect to the facilities appraisal studies, the Final Report on the National Transmission System was submitted in October 2020, with a Public Hearing on November 13, 2020. In November 2020, the Final Report for the Zonal and Dedicated Transmission System was submitted, with a Public Hearing on December 2, 2020.

c.6 Supply Bids (regulated PPAs)

Under the new bids law, three processes have been carried out: Supply Bid 2015/01, Supply Bid 2015/02 and Supply Bid 2017/01. Likewise, the CNE informed the start of a fourth processed entitled Supply Bid 2019/01.

The 2015/02 process began in June 2015 and concluded in October of the same year with the awarding of 3 blocks of 1.2 TWh/year (100%) and an average bid price of US$ 79.30/MWh.

The 2015/01 process began in May 2015 with the Call for Proposals, and ended in July 2016 with the awarding of 5 energy blocks, for a total of 12.4 TWh/year (100%) to 84 companies at an average bid price of US$ 47.60/MWh, and incorporating new participants into the market. The most successful bidder in the 2015/01 process was Enel Generación Chile, which was awarded supply contracts in the amount of 5.9 TWh/year, representing 47.6% of the total bid.

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The 2017/01 process began in January 2017 with the Call for Proposals, and ended in November 2017 with the awarding of a total of 2,200 GWh/year (100%) to 5 companies at an average bid price of US$ 32.50/MWh.

As in the previous process, the most successful bidder was Enel Generación Chile, which was awarded supply contracts in the amount of 1.2 TWh/year, representing 54% of the total bid.

A future bid process (2021/01) is considered for the supply period between 2026 and 2040, for an annual volume of 2,310 GWh. The deadline for the presentation of bids is May 28, 2021.

5.    BUSINESS COMBINATIONS UNDER COMMON CONTROL.

Corporate Reorganization Project

Considering the high priority given to renewable energies in the Group's strategy, and for the purpose of consolidating a vehicle to maximize this strategy, on August 25, 2017, Enel Chile submitted a proposal to the consideration of Enel S.p.A. for a corporate reorganization (hereinafter “the Reorganization of Renewable Assets”), which consisted of integrating the renewable energy assets in Chile held by Enel Green Power Latin America S.A. (“EGPL”) along with Enel Chile, which was also the controller of conventional energy generation assets belonging to Enel Generación Chile S.A. (“Enel Generación Chile”) and electricity distribution assets belonging to Enel Distribución Chile S.A.

Enel Chile and Enel Generación Chile are entities registered with the Financial Market Commission and have American Depository Receipts (“ADS”) traded in the New York Stock Exchange, therefore they are also subject to regulation by the U.S. Securities and Exchange Commission.

EGPL was an indirect subsidiary of Enel S.p.A., controlled through Enel Green Power S.p.A. (“EGP”).

The proposed reorganization involved the following phases, each of which was conditioned upon the implementation of the other, as described below:

i) Tender Offer for the acquisition of the shares (“OPA”)

Enel Chile conducted a tender offer for the acquisition of the shares, aimed at acquiring all shares issued by the subsidiary Enel Generación Chile, which were owned by the latter’s minority shareholders (equivalent to approximately 40% of paid-in capital), in cash at a price of Ch$590 per share with the condition that the shareholders of Enel Generación Chile use Ch$236 to subscribe Enel Chile shares, and the ADS would be priced at Ch$17,700, also payable in cash and subject to Ch$7,080 being used to subscribe Enel Chile ADS, at a subscription price of Ch$82   per Enel Chile share or Ch$4,100 per Enel Chile ADS (the “Share/ADS Subscription Condition”).

ii) Capital increase

Enel Chile undertook a capital increase (the “Capital increase”) in order to have sufficient Enel Chile ordinary shares to provide to the shareholder and ADS holders of Enel Generación Chile to meet the Share/ADS Subscription Condition.

With respect to the capital increase, according to Chilean legislation, Enel Chile made a preferential share subscription offer, where shareholders or third parties that exercised their subscription rights could grant the corresponding share subscription contracts in the apportionment process and proceed to pay Ch$82 per share corresponding to the shares subscribed by them.

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iii) Merger

Once the tender offer was declared successful, EGPL merged with Enel Chile (the “Merger”). Consequently, the renewable assets owned by EGPL were integrated within Enel Chile.

At the Enel Chile Extraordinary Shareholders’ Meeting held on December 20, 2017, the Reorganization was approved, subject to fulfillment of the conditions established for the tender offer, capital increase and merger. The Meeting also approved Enel Chile's capital increase in the amount of Ch$1,891,727,278,668, through the issuance of 23,069,844,862 new shares, all of a single series and with no par value, according to the price and other conditions approved by the Shareholders.  

Finally, on March 25, 2018, modifications were also approved and made to Enel Chile articles by-laws to reflect the agreements on the Merger, Capital Increase, and expansion of the corporate purpose of Enel Chile, among other provisions. The tender offer occurred between February 16 and March 22, 2018, and the preferential shares related to the capital increase were subscribed between February 15 and March 16, 2018. The Reorganization of Renewable Assets (including the Merger), was finalized and was effective from April 2, 2018, thus increasing Enel Chile’s interest in Enel Generación Chile from 59.98% to 93.55% and completing the merger of Enel Chile and EGPL. As of that date, Enel S.p.A. increased its total interest in Enel Chile to 61.93%.

This merger was accounted for in accordance with the accounting criteria established in Note 2.7.5 and generated a charge to Other miscellaneous reserves under Enel Chile's equity, in the amount of ThCh$407,354,462 (see Note 27.5.c.v.).

Carrying amount of EGPL assets and liabilities at the date of merger:

Identifiable net assets acquired	ThCh$
Cash and cash equivalents	12,173,982
Other current financial assets	8,460
Other current non-financial assets	3,832,583
Trade and other receivables, current	27,414,273
Current receivables to related parties	73,749,131
Inventories	2,851,171
Current tax assets	2,750,250
Other non-current financial assets	5,685,422
Other non-current non-financial assets	262,878
Trade and other receivables, non-current	43,829,961
Intangible assets other than goodwill	41,786,159
Goodwill	6,652,935
Property, plant and equipment	1,365,850,084
Deferred tax assets	21,246,605
Other current financial liabilities	(62,444,763)
Trade and other current payables, current	(49,109,886)
Current payables to related parties	(33,381,911)
Current tax liabilities	(347,483)
Other non-current financial liabilities	(259,856,654)
Non-current accounts payable to related parties	(396,081,972)
Other non-current provision	(9,169,918)
Deferred tax liabilities	(58,067,689)
Provisions for non-current employee benefits	(603,109)
Net identifiable assets acquired	739,030,509

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6.    CASH AND CASH EQUIVALENTS

a) The details of cash and cash equivalents as of December 31, 2020 and 2019 are as follows:

	As of December 31,
	2020	2019
Cash and Cash Equivalents	ThCh$	ThCh$
Cash balances	42,660	31,416
Bank balances	330,471,774	24,960,269
Time deposits	591,570	14,600,772
Other fixed-income instruments	930,009	196,092,043
Total	332,036,013	235,684,500

Time deposits have a maturity of three months or less from their date of acquisition and accrue the market interest for this type of short-term investment. Other fixed-income investments are mainly comprised of resale agreements maturing in 90 days or less from the date of investment. There are no restrictions for significant amounts of cash availability.

b) The detail, by type of currency, of the above balance is as follows:

	As of December 31,
	2020	2019
Currency	ThCh$	ThCh$
Chilean peso	300,357,148	209,818,277
Argentinean peso	3,977,675	7,096,519
Euro	83,819	654,319
U.S. dollar	27,617,371	18,115,385
Total	332,036,013	235,684,500

c) The following table records the components of “Other payments for operating activities” line item in the Statement of Cash Flows:

	2020	2019	2018
Other payments from operating activities	ThCh$	ThCh$	ThCh$
VAT tax debit	(135,096,018)	(123,065,058)	(111,371,155)
Emissions tax	(23,800,541)	(15,563,495)	(16,437,441)
Others	(11,394,034)	(15,871,496)	(9,543,503)
Total	(170,290,593)	(154,500,049)	(137,352,099)

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d) Reconciliation of liabilities arising from financing activities:

		Financing Cash Flows				Non-Cash Changes
Liabilities arising from financing activities	Balance as of 1-1-2020	From	Used	Interest paid	Total	Acquisition of subsidiaries	Changes in fair value	Foreign exchange differences	Financial costs  (1)	New leases	Other changes	Balance as of 12-31-2020 (1)
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Short-term loans	158,284,616	199,395	(150,878,247)	(137,759,315)	(288,438,167)	—	(1,893,193)	3,280,020	133,794,543	—	152,545,857	157,573,676
Long-term loans	2,470,532,068	484,520,001	(4,791,827)	—	479,728,174	—	12,628,182	(165,703,734)	2,646,905	—	(151,799,376)	2,648,032,219
Lease liabilities (Nota 21)	53,407,689	—	(4,940,582)	(1,492,089)	(6,432,671)	—	—	48,124	2,137,451	2,704,926	—	51,865,519
Assets held to cover liabilities arising from financing activities	(4,862,949)	708,062	—	—	708,062	—	(4,578,826)	(7,756,977)	—	—	—	(16,490,690)
Total	2,677,361,424	485,427,458	(160,610,656)	(139,251,404)	185,565,398	—	6,156,163	(170,132,567)	138,578,899	2,704,926	746,481	2,840,980,724
		Financing Cash Flows				Non-Cash Changes
Liabilities arising from financing activities	Balance as of 1-1-2019	From	Used	Interest paid	Total	Acquisition of subsidiaries	Changes in fair value	Foreign exchange differences	Financial costs  (1)	New leases	Other changes	Balance as of 12-31-2019 (1)
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Short-term loans	408,415,562	—	(350,652,302)	(133,788,145)	(484,440,447)	—	—	9,096,964	134,487,859	—	90,724,678	158,284,616
Long-term loans	2,140,557,500	283,799,437	—	—	283,799,437	—	7,924,704	137,637,204	—	—	(99,386,777)	2,470,532,068
Lease liabilities (Nota 21)	14,476,449	—	(4,498,202)	(641,609)	(5,139,811)	—	—	4,437,228	1,815,169	37,818,654	—	53,407,689
Assets held to cover liabilities arising from financing activities	(43,213,556)	1,823,783	—	—	1,823,783	—	38,471,730	(2,231,057)	—	—	286,151	(4,862,949)
Total	2,520,235,955	285,623,220	(355,150,504)	(134,429,754)	(203,957,038)	—	46,396,434	148,940,339	136,303,028	37,818,654	(8,375,948)	2,677,361,424
		Financing Cash Flows				Non-Cash Changes
Liabilities arising from financing activities	Balance as of 1-1-2018	From	Used	Interest paid	Total	Acquisition of subsidiaries	Changes in fair value	Foreign exchange differences	Financial costs  (1)	New leases	Other changes	Balance as of 12-31-2018
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Short-term loans	15,760,182	287,759,113	(168,360,646)	(115,801,821)	3,596,646	71,502,040	24,229,123	9,525,539	149,113,811	—	134,688,221	408,415,562
Long-term loans	769,169,018	1,278,023,491	(674,473,125)	—	603,550,366	649,261,789	2,541,108	261,981,228	—	—	(145,946,009)	2,140,557,500
Lease liabilities (Nota 21)	14,608,915	—	(1,889,685)	(739,070)	(2,628,755)	—	—	1,757,219	739,070	—	—	14,476,449
Assets held to cover liabilities arising from financing activities	(50,828,136)	—	—	—	—	(5,495,214)	21,619,259	(8,509,465)	—	—	—	(43,213,556)
Total	748,709,979	1,565,782,604	(844,723,456)	(116,540,891)	604,518,257	715,268,615	48,389,490	264,754,521	149,852,881	—	(11,257,788)	2,520,235,955

(1) It relates to accrual of interest.

7.    OTHER FINANCIAL ASSETS

The detail of other financial assets as of December 31, 2020 and 2019 is as follows:

	Current		Non-current
	12-31-2020	12-31-2019	12-31-2020	12-31-2019
Other Financial Assets	ThCh$	ThCh$	ThCh$	ThCh$
Financial assets at fair value with changes in other comprehensive income	127,854	127,854	2,326,480	2,349,223
Financial assets Financial assets measured at amortized cost	808,692	860,425	—	—
Hedging derivatives	1,000,964	322,316	16,422,737	4,871,397
Non-Hedging derivatives	1,414,894	—	1,911,233	—
Total	3,352,404	1,310,595	20,660,450	7,220,620

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8.    OTHER NON-FINANCIAL ASSETS AND LIABILITIES

a) Other non-financial assets

The detail of other non-financial assets as of December 31, 2020 and 2019, is as follows:

	Currrent		Non-Current
Other non-financial assets	12-31-2020	12-31-2019	12-31-2020	12-31-2019
	ThCh$	ThCh$	ThCh$	ThCh$
VAT Tax Credit and Other Taxes	8,575,080	19,497,233	46,638,860	19,799,224
Prepaid expenses	9,991,447	12,329,859	—	—
Guarantee deposit	—	—	128,724	1,879,019
PPM water rights	—	—	7,910,531	7,670,114
Spare parts with a consumption schedule of more than 12 months	—	—	7,543,841	5,773,991
Other	1,235,046	2,807,471	3,565,259	2,927,836
Total	19,801,573	34,634,563	65,787,215	38,050,184

b) Other non-financial liabilities

The detail of other non-financial liabilities as of December 31, 2020 and 2019, is as follows:

	Currrent		Non-Current
Other non-financial liabilities	12-31-2020	12-31-2019	12-31-2020	12-31-2019
	ThCh$	ThCh$	ThCh$	ThCh$
VAT Credit and Other Taxes	40,117,141	31,616,664	—	—
Reimbursable financial contributions	—	—	1,177,968	1,302,759
Splices	3,860,816	9,283,177		—
Transfer of networks	1,473,486	2,845,708		—
Products and services	954,609	1,088,498		—
Other	760,529	674,336		—
Total	47,166,581	45,508,383	1,177,968	1,302,759

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9.    TRADE AND OTHER RECEIVABLES

a) The detail of trade and other receivables as of December 31, 2020 and 2019, is as follows:

	As of December 31,
	2020		2019
Trade and Other Receivables, Gross	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, gross	619,626,310	445,129,898	566,919,977	313,574,385
Trade receivables, gross	531,179,316	377,160,616	500,040,783	191,966,929
Accounts receivable from finance leases, gross	8,556,146	62,602,528	13,158,795	117,873,340
Other receivables, gross	79,890,848	5,366,754	53,720,399	3,734,116
	As of December 31,
	2020		2019
Trade and Other Receivables, Net	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, net	554,886,639	445,016,566	511,455,330	313,574,385
Trade receivables, net	481,442,020	377,047,284	456,552,682	191,966,929
Accounts receivable from finance leases, net	4,072,738	62,602,528	11,121,878	117,873,340
Other receivables, net (1)	69,371,881	5,366,754	43,780,770	3,734,116

(1) The detail of other accounts receivable is as follows:

	As of December 31,
	2020		2019
Other receivables, net	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Recoveries from insurance companies	20,325	—	2,011,406	—
Accounts receivable from employees	13,256,252	4,442,878	10,017,453	3,308,861
Advances to suppliers and creditors	43,102,611	909,661	19,864,669	415,787
Compensation for central claims Tarapacá and Bocamina 1	5,360,345	—	—	—
Others	7,632,348	14,215	11,887,242	9,468
Total	69,371,881	5,366,754	43,780,770	3,734,116

a.1) Increase in trade and other receivables:

The main increase as of December 31, 2020, is observed in the long-term accounts receivable, which increased by ThCh$185,193,687 compared to the end of 2019. This variation is fundamentally explained by the following.

On November 2, 2019, the Ministry of Energy published Law No. 21,185, which creates a Transitory Mechanism to Stabilize Electricity Prices for Customers Subject to Rate Regulation. By this Law, between July 1, 2019 and December 31, 2020, the prices to be transferred to regulated customers are the price levels defined for the first half of 2019 (Decree 20T/2018) and will be referred to as “Stabilized Price to Regulated Customers” (PEC).

Between January 1, 2021 and up to the end of the stabilization mechanism, prices shall be those defined in the semiannual price-setting processes mentioned in article 158 of the Electricity Law, but may not be higher than the adjusted PEC according to the Consumer Price Index from January 1, 2021, based on the same date (adjusted PEC).

The differences produced between the billing period while applying the stabilization mechanism, and the theoretical billing, considering the price that would have been applied according to the conditions of the respective contracts with the Electricity Distribution companies, will generate an account receivable in favor of the Electricity Generation companies, up to a maximum of US$1,350 million until 2023. All billing differences will be recorded in USD and will not accrue financial remuneration until December 31, 2025. The balance must be recovered by December 31, 2027 at the latest.

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The application of this Law generates a greater delay in the billing and collection of sales generated in the Company´s Electricity Generation segment, with the corresponding financial and accounting impact this situation generates. In the case of the Company´s Electricity Distribution segment, the financial and accounting effects are neutralized (pass-through principle).

On September 14, 2020, the National Energy Commission published Exempt Resolution No. 340, which modified the technical provisions for the implementation of the Rate Stabilization Law. This Resolution clarified that the payment to each supplier “must be allocated to the payment of Balances chronologically, paying from the oldest to the newest Balances,” and not on a weighted basis over the total balances pending payment, as the industry practice had been until that date.

In addition, this Resolution established that the payment of Balances shall be performed using the USD exchange rate observed on the business day following publication of the Coordinator's Balance Payment Chart, instead of the average USD exchange rate during the billing month, as established up to that moment.

As a result of the abovementioned situations, and after eliminating transactions between related companies, the accounting effects recorded by the Group are summarized as follows:

- Classification as non-current in trade receivables in the amount of ThCh$370,276,397 as of December 31, 2020 (ThCh$182,076,569 as of December 31, 2019) and trade payables for the purchase of energy from suppliers in the amount of ThCh$112,895,627 (ThCh$53,941,373 as of December 31, 2019), see Note 24.

- Lower energy sales revenue of ThCh$10,864,866 as of December 31, 2020 (ThCh$3,782,091 as of December 31, 2019).

- Lower energy purchase costs of ThCh$3,515,292 (ThCh$1,181,163 as of December 31, 2019).

- Higher finance income of ThCh$15,328,829 as of December 31, 2020, of which ThCh$11,887,346 corresponds to the effect of application of Exempt Resolution No. 340 (higher finance income of ThCh$5,225,739 as of December 31, 2019), see Note 34.

- Higher finance costs of ThCh$(4,518,268) as of December 31, 2020, of which ThCh$3,206,420 corresponds to the effect of application of Exempt Resolution No. 340 (higher finance costs of ThCh$ 19,062,333 as of December 31, 2019), see Note 34.

- Net loss from foreign currency translation of ThCh$25,260,383 as of December 31, 2020 (ThCh$3,835,024 as of December 31, 2019), due to the dollarization of unbilled accounts receivable, see Note 34.

The aforementioned trade and non-trade concepts, while included in the model to determine impairment losses (see Note 3.g.3), have no greater impact at the close of December 2020 and 2019, due to the nature of these items: invoices not yet issued, invoices not yet due, or past due invoices within normal business ranges.

a.2) Transfer of collection rights from Distribution Segment customers

On December 28, 2020, Enel Distribución Chile and Inter-American Investment Corporation entered into a framework agreement by which Enel Distribución Chile, from time to time, may transfer the collection rights it owns and derived from part of its trade receivables from the sale of energy made to certain customer segments. Within this context, on December 30, 2020, Enel Distribución Chile made the first transfer of collection rights in the amount of ThCh$44,797,737 and, following the accounting criteria described in Note 3.g.6), the inflow of cash obtained in the transaction implied the derecognition of  accounts receivable and the recognition of a finance expense in the amount of ThCh$533,615.

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As indicated above, Enel Distribución Chile can continue to make new transfers of collection rights from time to time. The completion of additional transfers of collection rights will depend on Management’s analysis and ongoing evaluation of the cash needs and market conditions.

a.3) Others

There are no restrictions on the disposal of these types of accounts receivable in a significant amount.

The Group has no customers whose sales represent 10% or more of its revenue for the years ended December 31, 2020 and 2019.

For amounts, terms and conditions related to accounts receivable due from related parties, refer to Note 10.1

b) Financial lease receivables

As of December 31, 2020 and 2019, future collections on financial lease receivables are the following.

	12-31-2020			12-31-2019
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	8,560,073	4,487,336	4,072,737	15,313,622	4,191,744	11,121,878
From one to two years	10,294,652	1,735,758	8,558,894	17,350,359	3,919,937	13,430,422
From two to three years	10,266,956	1,692,482	8,574,474	17,350,359	3,630,136	13,720,223
From three to four years	10,226,534	1,309,548	8,916,986	17,316,251	3,115,800	14,200,451
From four to five years	10,118,045	472,760	9,645,285	17,271,708	2,246,896	15,024,812
More than five years	27,488,134	581,244	26,906,890	65,391,395	3,893,963	61,497,432
Total	76,954,394	10,279,128	66,675,266	149,993,694	20,998,476	128,995,218

The amounts correspond to the development of public lighting projects, mainly for municipalities, and the fleet of electric buses for public transportation with their respective charging stations.

The decrease of ThCh$62,319,952 in accounts payable compared to December 31, 2019, is mainly due to the sale of electric bus lease agreements on August 19, 2020 by the Company’s subsidiary Enel X Chile to its associate Enel AMPCl Ebus Chile SpA.

As of December 31, 2020, the profit from the sale of finance leases was ThCh$5,090,399, (ThCh$5,366,871 and ThCh$3,345,786 as of December 31, 2019 and 2018, respectively). Additionally, the finance income from lease receivables amounted to ThCh$1,562,017, (ThCh$1,446,779 and ThCh$1,182,229 as of December 31, 2019 and 2018, respectively).

c) As of December 31, 2020 and 2019, the analysis of past-due, unpaid trade receivables, but for which no impairment losses have been recorded, is detailed as follows:

	As of December 31,
	2020	2019
Trade accounts receivables due and unpaid, but of which no impairment losses have been recorded	ThCh$	ThCh$
Less than three months	52,948,476	43,661,270
Between three and six months	13,513,388	6,462,265
Between six and twelve months	8,311,729	5,162,189
More than twelve months	34,485,893	10,668,714
Total	109,259,486	65,954,438

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d) The movement of impairment loss of trade receivables, determined according to Note 3.g.3, is detailed as follows:

	Current and
	Non-current
Trade accounts receivables due and unpaid, with impairment losses	ThCh$
Balance as of January 1, 2019	49,479,880
Increases (decreases) for the year	10,047,000
Amounts written off	(4,067,201)
Increases (decreases) in foreign currency translation differences	4,968
Balance at December 31, 2019	55,464,647
Increases (decreases) for the year (*)	15,167,707
Amounts written off	(5,709,371)
Increases (decreases) in foreign currency translation differences	(69,980)
Balance at December 31, 2020	64,853,003

(*) As of December 31, 2020, the impairment losses of trade receivables amounted to ThCh$15,167,707, representing a 51% increase over the loss of ThCh$10,047,000 recorded at December 31, 2019. This increase is mainly due to the effects of COVID-19 on the economy, a deterioration in the payment capacity of a segment of customers, a prolonged lockdown with its effects on different commercial and industrial activities, and the inability to disconnect residential customers pursuant to Law No. 21,249, the Law on Utility Services, whose terms were extended by Law No. 21,301, among other factors. See more information in Note 4.b.iv “Sector Regulation – and Electricity System Operations – Regulatory Matters,” Note 31 “Depreciation, Amortization and Impairment Loss of Property, Plant and Financial Assets Under IFRS 9,” and Note 36.5 “COVID -19 Contingency.”

Write-offs of doubtful accounts

The write-off of doubtful accounts is performed once all collections proceedings have been exhausted, including judicial proceedings, and proof of the debtors’ insolvency has been obtained. In the case of the Company’s Generation Business, the process normally considers at least one year of proceedings. In the Company’s Distribution Business, the process takes less than 24 months. Over all, the risk of uncollectability and, therefore, the write-off of the Company’s customers, is limited. (See Notes 3.g.3 and 22.5).

e) Additional Information:

-Additional statistical information required by CMF Circular No. 715, dated February 3, 2012, (XBRL taxonomy). See Appendix 2.

-Complementary information on trade receivables, see Appendix 2.1.

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10.    BALANCES AND TRANSACTIONS WITH RELATED PARTIES

Related party transactions are performed at current market conditions.

Transactions between companies comprising the Group have been eliminated in the consolidation process and are not disclosed in this Note.

As of the date of these consolidated financial statements, there are no allowances for doubtful accounts between related entities.

The controlling company of Enel Chile is the Italian company Enel S.p.A.

Enel Chile S.A. provides administrative services to its subsidiaries, through a centralized cash contract used to finance cash deficits or consolidate cash surpluses. These accounts may have a debtor or creditor balance and are prepayable, short-term accounts with a variable interest rate that represents market conditions. To reflect these market conditions, the interest rates are reviewed periodically through an update procedure approved by the Boards of Directors of the respective companies.

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10.1 Balances and transactions with related parties

The balances of accounts receivable and payable as of December 31, 2020 and 2019 are as follows:

a)    Receivables from related parties

							Current		Non-current
							12-31-2020	12-31-2019	12-31-2020	12-31-2019
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of transaction	Term of transaction	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Endesa Spain	Spain	Common Immediate Parent	EUR	Other services	Less than 90 days	31,032	26,979	-	-
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	266,732	146,061	-	-
Foreign	Enel Green Power Morocco	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	252,803	94,340	-	-
76.418.940-K	GNL Chile S.A.	Italy	Associated	US$	Advance Gas Purchase	Less than 90 days	20,067,363	31,025,024	48,358,915	34,407,142
76.418.940-K	GNL Chile S.A.	Chile	Associated	US$	Dividends	Less than 90 days	616,697	-	-	-
Foreign	Endesa Generación	Spain	Common Immediate Parent	EUR	Engineering services	Less than 90 days	42,794	45,069	-	-
Foreign	Enel Italy SrL.	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	534,991	403,854	-	-
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	216,185	120,276	-	-
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	US$	Gas sales	Less than 90 days	-	16,880,527	-	-
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	EUR	Commodity derivatives	Less than 90 days	22,048,245	2,962,387	-	-
Foreign	Enel S.p.A.	Italy	Parent	EUR	Other services	Less than 90 days	533,309	467,393	-	-
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	BRL	Other services	Less than 90 days	-	705,954	-	-
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	US$	Other services	Less than 90 days	866,928	-	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Immediate Parent	US$	Engineering services	Less than 90 days	198,066	473,527	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	164,018	105,320	-	-
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	COP	Computer Services	Less than 90 days	-	833,336	-	-
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	EUR	Computer Services	Less than 90 days	322,872	-	-	-
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	74,930	26,237	-	-
Foreign	Enel Generación Peru S.A.	Peru	Common Immediate Parent	CLP	Engineering services	Less than 90 days	1,064,232	725,163	-	-
Foreign	Enel Generación Peru S.A.	Peru	Common Immediate Parent	US$	Engineering services	Less than 90 days	162,252	-	-	-
Foreign	Enel Generación Peru S.A.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	404,354	455,544	-	-
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CLP	Computer Services	Less than 90 days	410,946	991,564	-	-
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CLP	Other services	Less than 90 days	1,007,511	1,859,205	-	-
Foreign	Enel Green Power Colombia SAS	Colombia	Common Immediate Parent	US$	Engineering services	Less than 90 days	1,342,341	-	-	-
Foreign	Enel Green Power Colombia SAS	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	-	489,301	-	-
Foreign	Enel Generación Piura S.A.	Peru	Common Immediate Parent	US$	Engineering services	Less than 90 days	55,897	60,670	-	-
Foreign	Enel Innovation Hubs Srl	Italy	Common Immediate Parent	EUR	Computer Services	Less than 90 days	25,362	-	-	-
Foreign	Chinango S.A.C.	Peru	Common Immediate Parent	US$	Engineering services	Less than 90 days	70,925	-	-	-
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	170,756	1,131,635	-	-
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	US$	Engineering services	Less than 90 days	395,683	-	-	-
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	2,088	267,422	-	-
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	US$	Other services	Less than 90 days	653,975	1,509,373	-	-
Foreign	Sociedad Portuaria Central Cartagena S.A.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	-	149,525	-	-
96.971.330-6	Geotérmica del Norte	Chile	Common Immediate Parent	CH$	Venta de Energía	Less than 90 days	-	-	-	-
Foreign	Enel Distribución Peru S.A.	Peru	Common Immediate Parent	US$	Computer Services	Less than 90 days	657,232	603,171	-	-
Foreign	Enel Green Power Peru	Peru	Common Immediate Parent	US$	Engineering services	Less than 90 days	405,030	302,697	-	-
Foreign	Enel Green Power Peru	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	186,734	1,463,242	-	-
Foreign	Energía Nueva Energía Limpia México S.R.L	Mexico	Common Immediate Parent	US$	Other services	Less than 90 days	34,843	108,327	-	-
Foreign	Proyectos y Soluciones Renovables S.A.C.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	96,267	60,717	-	-
Foreign	Enel Generacion Costanera S.A.	Argentina	Common Immediate Parent	US$	Engineering services	Less than 90 days	155,722	34,771	-	-
Foreign	Enel Generacion El Chocón S.A.	Peru	Common Immediate Parent	US$	Engineering services	Less than 90 days	11,954	12,589	-	-
Foreign	Enel Green Power Brasil Participacoes LTDA.	Brazil	Common Immediate Parent	US$	Engineering services	Less than 90 days	6,714	51,895	-	-
Foreign	Enel Green Power Brasil Participacoes LTDA.	Brazil	Common Immediate Parent	US$	Other services	Less than 90 days	200,977	75,984	-	-
Foreign	Enel Power Argentina	Argentina	Common Immediate Parent	US$	Other services	Less than 90 days	269,280	284,876	-	-
Foreign	Energetica Monzon S.A.C.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	-	461,677
Foreign	Energetica Monzon S.A.C.	Peru	Common Immediate Parent	US$	Engineering services	Less than 90 days	653,567	-	-	-
Foreign	Enel Green Power RSA (PTY) LTD	South Africa	Common Immediate Parent	US$	Other services	Less than 90 days	-	385,716	-	-
Foreign	Enel Green Power RSA (PTY) LTD	South Africa	Common Immediate Parent	CLP	Other services	Less than 90 days	-	110,699	-	-
Foreign	Enel Green Power North America Inc	United States	Common Immediate Parent	US$	Other services	Less than 90 days	-	141,708	-	-
Foreign	Enel Green Power North America Inc	United States	Common Immediate Parent	CLP	Other services	Less than 90 days	-	7,381	-	-
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Immediate Parent	US$	Other services	Less than 90 days	234,834	168,691	-	-
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Immediate Parent	US$	Computer Services	Less than 90 days	1,080,101	1,136,784	-	-
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	CLP	Other services	Less than 90 days	623,843	341,200	-	-
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	29,990	26,954	-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	60,644	13,781	-	-
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	753,544	273,003	-	-
Foreign	Enel North America Inc	United States	Common Immediate Parent	US$	Other services	Less than 90 days	192,582	-	-	-
Foreign	Enel X North America Inc	United States	Common Immediate Parent	US$	Other services	Less than 90 days	86,685	92,730	-	-
Foreign	Parque Amistad Ii Sa De Cv	Mexico	Common Immediate Parent	US$	Other services	Less than 90 days	-	50,264	-	-
Foreign	Parque Amistad Iv Sa De Cv	Mexico	Common Immediate Parent	US$	Other services	Less than 90 days	-	17,590	-	-
Foreign	Renovables de Guatemala S.A.	Guatemala	Common Immediate Parent	US$	Engineering services	Less than 90 days	1,089	-	-	-
Foreign	Enel Trading Argentina S.R.L.	Argentina	Common Immediate Parent	EUR	Computer Services	Less than 90 days	173,263	-	-	-
77.157.781-4	Enel AMPCI Ts1 Holdings SpA	Chile	Associated	US$	Other services	Less than 90 days	8,176	-	-	-
77.157.783-0	Enel AMPCI Ts1 SpA	Chile	Associated	US$	Other services	Less than 90 days	41,591	-	-	-
77.157.779-2	Enel AMPCI Ebus Chile SpA	Chile	Associated	US$	Other services	Less than 90 days	8,176	-	-	-
						Total	57,976,125	68,182,133	48,358,915	34,407,142

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b)    Accounts payable to related parties

							Current		Non-current
							12-31-2020	12-31-2019	12-31-2020	12-31-2019
Taxpayer ID N°	Company	Country	Relationship	Currency	Description of transaction	Terms of transaction	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Endesa Spain	Spain	Common Immediate Parent	EUR	Other services	Less than 90 days	159,940	159,940	-	-
Foreign	Enel Trading Argentina S.R.L.	Argentina	Common Immediate Parent	US$	Other services	Less than 90 days	94,838	86,189	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Immediate Parent	COP	Other services	Less than 90 days	4,576	4,723	-	-
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CLP	Other services	Less than 90 days	2,285,642	1,909,747	-	-
Foreign	Enel Distribución Peru S.A.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	2,185	2,291	-	-
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	651,662	57,324	-	-
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	5,397,360	1,984,129	-	-
76.418.940-K	GNL Chile S.A.	Chile	Associated	US$	Gas Purchase	Less than 90 days	14,650,079	4,980,936	-	2,497,660
Foreign	Endesa Generación	Spain	Common Immediate Parent	EUR	Engineering services	Less than 90 days	190,879	190,879	-	-
Foreign	Endesa Generación	Spain	Common Immediate Parent	EUR	Other services	Less than 90 days	25,643	25,643	-	-
Foreign	Enel Iberia SRL	Spain	Common Immediate Parent	EUR	Other services	Less than 90 days	891,821	883,576	-	-
Foreign	E-Distribuzione Spa	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	-	49,488	-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	1,395,436	3,249,960	-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	1,999,721	2,793,150	-	-
Foreign	Enel Energía	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	478,207	452,289	-	-
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Chile	Joint Arrangement	CLP	Tolls	Less than 90 days	13,887	13,887	-	-
Foreign	Enel Green Power Spain SL	Spain	Common Immediate Parent	EUR	Other services	Less than 90 days	403,225	352,233	-	-
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	558,964	1,099,133	-	-
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	US$	Commodity derivatives	Less than 90 days	2,405,919	9,295,836	-	-
Foreign	Enel Global Trading S.p.A.	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	5,042,033	2,857,244	-	-
Foreign	Enel Global Services S.r.l.	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	1,154,817	-	-	-
Foreign	Enel Global Services S.r.l.	Italy	Common Immediate Parent	EUR	Computer Services	Less than 90 days	11,719,059	-	-	-
Foreign	Enel Global Services S.r.l.	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	551,776	-	-	-
Foreign	Enel Global Services S.r.l.	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	640,692	-	-	-
Foreign	Enel S.p.A.	Italy	Parent	CLP	Dividends	Less than 90 days	-	55,018,871	-	-
Foreign	Enel S.p.A.	Italy	Parent	EUR	Technical services	Less than 90 days	7,310,421	6,982,284	-	-
Foreign	Enel S.p.A.	Italy	Parent	EUR	Computer Services	Less than 90 days	263,443	-	-	-
Foreign	Enel S.p.A.	Italy	Parent	EUR	Engineering services	Less than 90 days	1,381,313	-	-	-
Foreign	Enel S.p.A.	Italy	Parent	EUR	Other services	Less than 90 days	2,516,113	2,965,604	-	-
Foreign	Enel Italy SrL	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	-	6,438,614	-	-
Foreign	Enel Italy SrL	Italy	Common Immediate Parent	EUR	Computer Services	Less than 90 days	253,605	-	-	-
Foreign	Enel Italy SrL	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	676,267	9,115,709	-	-
Foreign	Enel Italy IT	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	243,460	-	-	-
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	35,616	17,950	-	-
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	4,782,053	3,017,847	-	-
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	EUR	Computer Services	Less than 90 days	2,125,349	-	-	-
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	17,720	-	-	-
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	947,100	681,544	-	-
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	21,206,647	19,758,903	-	-
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	17,975,839	12,594,833	-	-
Foreign	Enel Green Power Spa	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	9,249,143	10,666,792	-	-
Foreign	Enel Green Power North America Inc	United States	Common Immediate Parent	US$	Other services	Less than 90 days	315,697	248,051	-	-
Foreign	Enel Finance International NV (*)	Holland	Common Immediate Parent	US$	Loan payable	Less than 90 days	3,444,366	-	1,164,044,462	781,875,824
Foreign	Enel Finance International NV	Holland	Common Immediate Parent	US$	Other services	Less than 90 days	-	134,278	-	-
Foreign	Enel Green Power Italy	Italy	Common Immediate Parent	CLP	Other services	Less than 90 days	459,992	-	-	-
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	CLP	Other services	Less than 90 days	345,708	344,877	-	-
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	EUR	Engineering services	Less than 90 days	871,748	-	-	-
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	42,549	107,037	-	-
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	US$	Engineering services	Less than 90 days	60,957	-	-	-
76.364.085-K	Energía Marina S.P.A	Chile	Associated	CLP	Other services	Less than 90 days	-	2,357	-	-
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	EUR	Other services	Less than 90 days	130,664	198,815	-	-
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	EUR	Technical services	Less than 90 days	4,225,269	147,488	-	-
Foreign	Cesi S.p.A.	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	247,773	890,343	-	-
Foreign	Tecnatom SA	Italy	Common Immediate Parent	EUR	Engineering services	Less than 90 days	73,842	29,093	-	-
Foreign	Enel X Brasil Gerenciamento de Energia Ltda	Brazil	Common Immediate Parent	US$	Other services	Less than 90 days	360	-	-	-
Foreign	Enel Distribución Sao Paulo	Brazil	Common Immediate Parent	US$	Other services	Less than 90 days	132,587	-	-	-
						Total	130,053,962	159,809,887	1,164,044,462	784,373,484

(*) See letter d below.

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c)    Significant transactions and effects on profit or loss

As of December 31, 2020, 2019 and 2018 the significant transactions with related companies that are not consolidated, are as follows:

6
					For the years ended December 31,
					2020	2019	2018
Taxpayer ID N°	Company	Country	Relationship	Description of transaction	ThCh$	ThCh$	ThCh$
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	Provision of administration and other services	5,021,265	4,748,244	5,071,453
76.418.940-K	GNL Chile S.A.	Chile	Associated	Gas consumption	(164,410,577)	(99,801,403)	(131,521,989)
96.524.140-K	Empresa Eléctrica Panguipulli S.A.	Chile	Common Immediate Parent	Energy Purchases	-	-	(1,954,523)
76.052.206-6	Parque Eolico Valle de los Vientos SpA	Chile	Common Immediate Parent	Energy Purchases	-	-	(3,349,525)
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	Technical services	(3,435,918)	-	-
Foreign	Enel Global Services S.r.l.	Italy	Common Immediate Parent	Engineering services	(5,097,105)	-	-
Foreign	Enel S.p.A.	Italy	Parent	Technical services	(3,800,471)	(4,110,257)	-
76.412.562-2	Enel Green Power del Sur SPA	Chile	Common Immediate Parent	Energy Purchases	-	-	(30,205,373)
76.179.024-2	Parque Eolico Tal Tal SpA	Chile	Common Immediate Parent	Energy Purchases	-	-	(4,448,833)
Foreign	Enel Global Trading SpA.	Italy	Common Immediate Parent	Commodity derivatives	(37,771,702)	(12,118,800)	7,584,772
Foreign	Enel Global Trading SpA.	Italy	Common Immediate Parent	Technical services	(2,183,183)	(1,634,832)	(1,213,116)
Foreign	Enel Global Trading SpA.	Italy	Common Immediate Parent	Gas sales	-	58,352,346	34,701,425
Foreign	Enel Finance International NV	Holland	Common Immediate Parent	Financial expenses	(35,079,947)	(31,328,749)	(23,253,535)
Foreign	Enel Italy S.r.l.	Italy	Common Immediate Parent	Computer Services	-	(2,699,915)	(1,481,631)
Foreign	Enel Italy S.r.l.	Italy	Common Immediate Parent	Technical services	-	(3,139,990)	(2,629,893)
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	Technical services	(3,172,872)	-	(1,845,425)
Foreign	Enel Green Power SpA	Italy	Common Immediate Parent	Engineering services	(7,263,535)	-	-
Foreign	Enel Green Power SpA	Italy	Common Immediate Parent	Technical services	(4,674,437)	(3,898,762)	(4,257,363)
76.802.924-3	Energía y Servicios South America SpA	Chile	Common Immediate Parent	Computer Services	(2,128,624)	-	-

d) Significant transactions

i) Enel Chile

● On December 21, 2018, Enel Finance International NV granted a revolving credit facility in USD to Enel Chile S.A. for a committed amount of up to US$400 million, with a variable LIBOR 6M interest rate, plus an annual margin of 1.00% with the payment of interest every six months and a maturity date of December 21, 2022. The facility allowed Enel Chile S.A. to make indefinite withdrawals up to the committed amount and until June 21, 2019, defined as the availability period, during which Enel Chile S.A. must pay an annual availability commission equivalent to 35% of the margin over the non-withdrawn amount. On June 3 and 18, 2019, Enel Chile S.A. withdrew the total amount of the line of credit. The credit obtained by Enel Chile S.A. is unsecured, corresponds to a bullet maturity loan, and the principal and interest can be repaid early, in part or in full, without any penalty other than the “breakage costs,” by sending to Enel Finance International NV a request for early repayment, completed at least 10 (ten) days prior to the prepayment date. Enel Chile S.A. will not pay any “breakage costs” if the prepayment date falls on an interest payment date. The debt balance as of December 31, 2020 was US$400 million, equivalent to ThCh$284,380,000, while as of December 31, 2019 it was US$400 million, equivalent to ThCh$299,496,000. As of December 31, 2020, this debt has no accrued interest due to the payment of interest on December 31, 2020.

● In June 2019, Enel Chile S.A. entered into a revolving credit facility with Enel Finance International N.V. in USD for a total of US$50 million, at a LIBOR 1M, 3M or 6M variable rate plus a margin of  0.90%, with monthly, quarterly or semiannual interest payments, and a maturity date of December 24, 2024. During the availability period, Enel Chile S.A. will pay an annual availability commission equivalent to 0.25% the non-withdrawn amount. This revolving credit facility is unsecured, and the principal and accumulated interest or other cost subject to agreement may be repaid early, in part or in full. Enel Chile S.A. may require renewal of a withdrawal, by sending a letter at least 5  (five) business days prior to the due date of the obligation. As of December 31, 2020, this line has not been used.

● On January 3, 2020, Enel Finance International NV granted a loan in USD to Enel Chile S.A. for up to US$200 million, with a fixed interest rate of 2.60%, with the payment of interest every six months and a maturity date of July 3, 2023. The loan obtained by Enel Chile S.A. is unsecured, corresponds to a bullet loan, and the principal and interest can be repaid early, in part or in full, without any penalty other than

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the “breakage costs,” by sending to Enel Finance International NV a request for early repayment, at least 10 (ten) days prior to the prepayment date. Enel Chile S.A. will not pay any “breakage costs” if the prepayment date falls on an interest payment date. The debt balance as of December 31, 2020 was US$200 million, equivalent to ThCh$142,190,000. As of December 31, 2020, this debt has no accrued interest due to the payment of interest on December 31, 2020.

● On March 11, 2020, Enel Finance International NV granted a loan in USD to Enel Chile S.A. for up to US$400 million, with a fixed interest rate of 3.30%, with the payment of interest every six months and a maturity date of March 11, 2030. The loan obtained by Enel Chile S.A. is unsecured, corresponds to a bullet loan, and the principal and interest can be repaid early, in part or in full, without penalty any other than the “breakage costs,” by sending to Enel Finance International NV a request for early repayment at least 10 (ten) days prior to the prepayment date. Enel Chile S.A. must not pay any “breakage costs” if the prepayment date falls on an interest payment date. The debt balance as of December 31, 2020 was US$400 million, equivalent to ThCh$284,380,000. The accrued interest as of December 31, 2020 was ThCh$2,893,567.

● On June 15, 2020, Enel Chile S.A. entered into a revolving credit facility with Enel Finance International N.V. in USD for a total of US$290 million, at a LIBOR 1M, 3M or 6M variable rate plus a margin of 1.40%, with monthly, quarterly or semiannual interest payments, and a maturity date of June 15, 2021. During the availability period, Enel Chile S.A. will pay an annual availability commission equivalent to 0.35% the margin over the non-withdrawn amount. This revolving credit facility is unsecured, and the principal and accumulated interest or other cost subject to agreement may be repaid early, in part or in full. Enel Chile S.A. may require renewal of a withdrawal, by sending a letter at least 5 (five) business days prior to the due date of the obligation. As of December 31, 2020, this line has not been used.

ii) EGP Chile Group

● On December 31, 2015, Enel Green Power International B.V. (currently Enel Finance International N.V.) granted to Parque Eólico Renaico SpA (later Enel Green Power del Sur SpA and currently Enel Green Power Chile S.A.) a loan in USD for a committed amount of up to US$650 million, at a variable LIBOR 6M interest rate, plus an annual margin of 4.94% , with the payment of interest every six months and a maturity date of December 31, 2027. The loan allowed Enel Green Power del Sur SpA to make indefinite withdrawals up to the committed amount until December 31, 2017, defined as the availability period, during which Enel Green Power Chile S.A. paid an annual availability fee equivalent to 35% of the margin over the non-withdrawn amount. On June 28, 2019, the annual margin was reduced to 1.40%. Additionally, on September 30, 2019, Enel Green Power Chile S.A. and :Enel Finance International N.V. renewed the agreement to modify the Loan Agreement, under the following terms: (i) modify the interest rate, from variable to fixed, establishing an annual rate of 2.82%, with payment of interest every six months; and (ii) modify the semiannual payment schedule, starting June 30, 2024, maintaining voluntary prepayment with breakage costs (modifying the definition of breakage cost) and the maturity date of December 31, 2027. The debt balance as of December 31, 2020 was US$644 million equivalent to ThCh$458,115,848 as of December 31, 2019,(US$644 million, equivalent to ThCh$482,466,643. This is a bullet maturity loan secured by Enel Chile S.A. As of December 31, 2020, this debt has no accrued interest due to the payment of interest on December 31, 2020.

10.2 Board of directors and key management personnel

Enel Chile is managed by a Board of Directors which consists of seven members. Each director serves for a three-year term after which they can be reelected.

The current Board of Directors was elected at the Ordinary Shareholders’ Meeting held on April 25, 2018. In the Board of Directors Meeting held on the same day, the current Board Chairman and Secretary were appointed.

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a)    Accounts receivable and payable and other transactions

-Accounts receivable and payable

There are no outstanding balances receivable and payable between the Company and its Directors and Group Management.

-Other transactions

There are no transactions other than remuneration between the Company and its Directors and Group Management.

b)    Compensation for directors

In accordance with Article 33 of Law No.18.046 governing stock corporations, the compensation of Directors is established each year at the General Shareholders Meeting of Enel Chile.

A monthly remuneration, one part a fixed monthly fee and another part dependent on meetings attended, shall also be paid to each member of the Board of Directors. This remuneration is broken down as follows:

-     UF 216 as a fixed monthly fee in any event; and

-     UF 79.2 as a per diem for each Board meeting attended with a maximum of 16 sessions in total whether ordinary or extraordinary, within the corresponding exercise.

According to the provisions of the bylaws, the remuneration of the Chairman of the Board will be twice that of a Director.

In the event a Director of Enel Chile S.A participates in more than one Board of Directors of domestic or foreign subsidiaries and / or affiliated, or acts as director or consultant for other domestic or foreign companies or legal entities in which Enel Chile S.A. has direct or indirect interest, he/she may receive remuneration only in one of said Board of Directors or Management Boards.  

The executive officers of Enel Chile S.A. and/or its domestic or foreign subsidiaries or affiliates will not receive remunerations or per diem allowances if acting as directors in any of Enel Chile S.A.’s domestic or foreign subsidiaries, affiliates or investee in any way. However, said remunerations or per diem allowances may be received by the executive officers as long as they are previously and expressly authorized as advances of their variable portion of remuneration by the corresponding companies with which they are associated through an employment contract.

Directors’ Committee:

Each member will be paid a monthly compensation, one part a fixed monthly fee and another part dependent on meetings attended.

This compensation is broken down as follows:

-     UF 72 as a fixed monthly fee, in any event, and

-     UF 26.4 as a per diem for each Board meeting attended, all with a maximum of 16 meetings in total, whether ordinary or extraordinary, within the corresponding fiscal year.

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The following tables show details of the compensation paid to the members of the Board of Directors of the Company for the years ended December 31, 2020, 2019 and 2018:

				December 31, 2020
				Enel Chile Board	Board of subsidiaries	Directors' Committee
Taxpayer ID No.	Name	Position	Period in position	ThCh$	ThCh$	ThCh$
4.975.992-4	Herman Chadwick Piñera	Chairman	January - December 2020	207,918	—	—
Foreign	Giulio Fazio	Director	January - December 2020	—	—	—
4.461.192-9	Fernan Gazmuri Plaza	Director	January - December 2020	103,959	—	34,653
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2020	103,959	—	34,653
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - December 2020	103,959	—	34,653
Foreign	Daniele Caprini	Director	January - December 2020	—	—	—
Foreign	Salvatore Bernabei	Director	January - December 2020	—	—	—
			Total	519,795	—	103,959

				December 31, 2019
				Enel Chile Board	Board of subsidiaries	Directors' Committee
Taxpayer ID No.	Name	Position	Period in position	ThCh$	ThCh$	ThCh$
4.975.992-4	Herman Chadwick Piñera	Chairman	January - December 2019	206,350	—	—
Foreign	Giulio Fazio	Director	January - December 2019	—	—	—
4.461.192-9	Fernan Gazmuri Plaza	Director	January - December 2019	103,175	—	33,648
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2019	103,175	—	33,648
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - December 2019	103,175	—	33,648
Foreign	Daniele Caprini	Director	January - December 2019	—	—	—
Foreign	Salvatore Bernabei	Director	January - December 2019	—	—	—
			Total	515,875	—	100,944

				December 31, 2018
				Enel Chile Board	Board of subsidiaries	Directors' Committee
Taxpayer ID No.	Name	Position	Period in position	ThCh$	ThCh$	ThCh$
4.975.992-4	Hermán Chadwick Piñera	Chairman	January - December 2018	181,789	—	—
Foreigner	Giulio Fazio	Director	January - December 2018	—	—	—
4.461.192-9	Fernán Gazmuri Plaza	Director	January - December 2018	90,894	—	31,018
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2018	90,894	—	31,018
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - December 2018	90,894	—	31,018
Foreigner	Vicenzo Ranieri	Director	April - December 2018	—	—	—
Foreigner	Salvatore Bernabei	Director	January - December 2018	—	—	—
			Total	454,471	—	93,054

c)    Guarantees given by the Company in favor of the directors

No guarantees have been given to the directors.

10.3 Compensation of key management personnel

Enel Chile's key personnel as of December 31, 2020 is comprised of the following people:

Key Management Personnel
Taxpayer ID No.	Name	Position
Foreign	Paolo Palloti	Chief Executive Officer
Foreign	Giuseppe Turchiarelli (1)	Administration, Finance and Control Officer
13.903.626-3	Liliana Schnaidt Hagedorn	Human Resources and Organization Manager
6.973.465-0	Domingo Valdés Prieto	General Counsel and Secretary to the Board
Foreign	Eugenio Belinchon Gueto (2)	Internal Audit Manager

(1) On November 15, 2019, Mr. Giuseppe Turchiarelli, was appointed CFO, replacing Mr. Marcelo Antonio de Jesús.

(2) On March 1, 2020, Mr. Eugenio Belinchon Gueto was appointed Head of Internal Auditing, replacing Mr. Raffaele Cutrignelli.

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The following executives were part of the Company's key staff until September 24, 2019.

- Mónica De Martino, Regulation Manager

- Antonella Pellegrini, Sustainability and Community Relations Manager

- Claudia Navarrete Campos, Planning and Control Manager

- Alison Dunsmore M., Service Manager

- Pedro Urzúa Frei, Institutional Relations Manager

- Raúl Puentes Barrera, Provisioning Manager

- Andrés Pinto Bontá, Security Manager

- Ángel Barrios Romo, Digital Solutions Manager

10.4 Incentive plans for key management personnel

Enel Chile has implemented an annual bonus plan for its executives based on meeting company-wide objectives and on the level of their individual contribution in achieving the overall goals of the Group. The plan provides for a range of bonus amounts according to seniority level. The bonuses paid to the executives consist of a certain number of monthly gross remunerations.

Compensation of key management personnel is the following:

	December 31, 2020	December 31, 2019	December 31, 2018
	ThCh$	ThCh$	ThCh$
Remuneration	2,133,063	2,357,252	2,959,019
Short-term benefits for employees	272,714	207,391	497,424
Other long-term benefits - IAS	146,404	2,088	322,865
Total	2,552,181	2,566,731	3,779,308

a) Guarantees established by the Company in favor of key management personnel

No guarantees have been given to key management personnel.

10.5 Compensation plans linked to share price

There are no payment plans granted to the Directors or key management personnel based on the share price of the Enel Chile.

11.  INVENTORIES

The detail of inventories as of December 31, 2020 and 2019, is as follows:

	As of December 31,
	2020	2019
Classes of Inventories	ThCh$	ThCh$
Supplies for Production	5,207,472	18,352,465
Gas	2,280,335	2,287,934
Oil	2,927,137	3,888,712
Coal	—	12,175,819
Supplies for projects and spare parts	13,468,592	18,073,825
Electrical materials	4,633,965	3,245,960
Total	23,310,029	39,672,250

There are no inventories acting as security for liabilities.

For the years ended December 31, 2020,2019 and 2018, raw materials and inputs recognized as fuel cost amount to ThCh$231,176,489, ThCh$230,944,415 and ThCh$231,028,169, respectively. (see Note 29). The amount

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corresponding to 2020 includes ThCh$ 21,246,157 and ThCh$ 328,626 for the adjustment of impairment of coal inventories and of diesel oil, respectively, related to the process of closure operations of the Bocamina II power plant (see Note 16.c.iv).

12.   CURRENT TAX ASSETS AND LIABILITIES

a) The detail of current tax receivables as of December 31, 2020 and 2019, is as follows:

	As of December 31,
	2020	2019
Tax Receivables	ThCh$	ThCh$
Monthly provisional tax payments	34,534,731	38,536,220
Tax credit for absorbed profits	—	86,068,128
Tax credit for training expenses	503,682	2,668,941
Total	35,038,413	127,273,289

b) The detail of current tax payables as of December 31, 2020 and 2019, is as follows:

	As of December 31,
	2020	2019
Current tax liabilities	ThCh$	ThCh$
Income tax	72,359,944	17,995,833
Total	72,359,944	17,995,833

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13.   INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD

13.1. Investments accounted for using the equity method

a. The detail of the Group's investees accounted for using the equity method and the movements for the years ended December 31, 2020 and 2019, are as follows:

								Share of		Foreign	Other	Other	Balance as		Balance as
						Balance as of		Profit	Dividends	Currency	Comprehensive	Increase	of	Negative	of
Taxpayer ID					Ownership	1-1-2020	Additions	(Loss)	Declared	Translation	Income	(Decrease)	12-31-2020	Equity	12-31-2020
Number	Associates and Joint Ventures	Relationship	Country	Currency	Interest	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	Provision	ThCh$
76.418.940-K	GNL Chile S.A.	Associate	Chile	U.S. dollar	33.33%	1,410,206	—	1,127,312	(686,058)	(122,077)	—	—	1,729,383	—	1,729,383
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Joint Venture	Chile	Chilean peso	50.00%	6,099,228	—	1,351,965	—	—	—	—	7,451,193	—	7,451,193
76.014.570-K	Enel Argentina S.A.	Associate	Argentina	Angentine peso	0.0793%	401,908	—	15,333	—	(130,962)	—	84,284	370,563	—	370,563
76.364.085-K	Energía Marina SpA.	Associate	Chile	Chilean peso	25.00%	17,246	—	(70,360)	—	—	—	—	(53,114)	53,114	—
77.157.779-2	Enel AMPCI Ebus Chile SpA	Associate	Chile	U.S. dollar	20.00%	—	2,727,091	1,085,142	—	(389,551)	18,982	—	3,441,664	—	3,441,664
					TOTAL	7,928,588	2,727,091	3,509,392	(686,058)	(642,590)	18,982	84,284	12,939,689	53,114	12,992,803

								Share of		Foreign	Other	Other	Balance as	Negative	Balance as
						Balance as of		Profit	Dividends	Currency	Comprehensive	Increase	of	Equity	of
Taxpayer ID					Ownership	1-1-2019	Additions	(Loss)	Declared	Translation	Income	(Decrease)	12-31-2019	Provision	12-31-2019
Number	Associates and Joint Ventures	Relationship	Country	Currency	Interest	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
76.418.940-K	GNL Chile S.A.	Associate	Chile	U.S. dollar	33.33%	3,052,983	—	(254,132)	(1,518,880)	130,235	—	—	1,410,206	—	1,410,206
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Joint Ventures	Chile	Chilean peso	50.00%	9,473,711	—	695,437	(4,069,920)	—	—	—	6,099,228	—	6,099,228
76.014.570-K	Enel Argentina S.A.	Associate	Argentina	Argentine peso	0.0793%	300,198	—	104,335	—	(95,726)	—	93,101	401,908	—	401,908
76.364.085-K	Energías Marina SpA	Associate	Chile	Chilean peso	25.00%	46,639	131,647	(179,551)			—	18,511	17,246	—	17,246
					TOTAL	12,873,531	131,647	366,089	(5,588,800)	34,509	—	111,612	7,928,588	—	7,928,588

(*) See section b) below

F-76

13.2. Additional financial information on investments in associates

Financial information as of December 31, 2020 and 2019 of the main companies in which the Group exercises significant influence is detailed below:

	As of December 31, 2020
	% Ownership Interest Direct /	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Indirect	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GNL Chile S.A	33.33%	57,032,080	1,433,019,578	117,974,825	1,366,888,682	553,288,674	(549,906,739)	3,381,935	(366,207)	3,015,728
Enel AMPCI E bus Chile SpA	20.00%	20,007,409	93,871,600	15,101,345	81,569,344	7,503,692	(2,077,983)	5,425,709	—	5,425,709

	As of December 31, 2019
	% Ownership Interest Direct /	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Indirect	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GNL Chile S.A	33.33%	67,419,256	1,615,973,312	161,197,047	1,517,964,903	582,441,735	(583,204,131)	(762,396)	389,843	(372,553)

None of the Company’s associates have issued price quotations

13.3. Joint ventures

Information as of December 31, 2020 and 2019 of the statements of financial position and statements of income of the joint venture related to Transmisora Eléctrica de Quillota Ltda., is as follows:

	Transmisora Eléctrica
	de Quillota Ltda.
	50.0%	50.0%
	12-31-2020	12-31-2019
	ThCh$	ThCh$
Total current assets	7,157,805	3,346,667
Total non-current assets	10,068,936	10,834,220
Total current liabilities	806,841	365,640
Total non-current liabilities	1,517,515	1,616,791
Cash and cash equivalents	4,261,166	2,403,904
Revenues	4,643,283	3,191,566
Other fixed operating expenses	(268,806)	(768,866)
Depreciation and amortization expense	(782,799)	(782,800)
Other Income	4,187	6,087
Interest income	29,103	152,370
Income tax expense	(921,039)	(407,478)
Profit (loss)	2,703,929	1,390,879
Comprehensive income	2,703,929	1,390,879

There are no significant commitments and contingencies, or restrictions to the availability of funds in associated companies and joint ventures.

F-77

14.  INTANGIBLE ASSETS OTHER THAN GOODWILL

The balances of this caption as of December 31, 2020 and 2019 are presented below:

	As of December 31,
	2020	2019
Intangible Assets, Gross	ThCh$	ThCh$
Intangible Assets, Gross	275,527,801	229,944,365
Easements and water rights	20,551,471	22,553,618
Concessions	53,053,457	34,718,676
Patents, Registered Trademarks and Other Rights	679,227	771,002
Computer software	186,855,438	156,836,017
Other identifiable intangible assets	14,388,208	15,065,052

	As of December 31,
	2020	2019
Intangible Assets, Amortization and Impairment	ThCh$	ThCh$
Accumulated Amortization and Impairment, Total	(110,413,280)	(97,665,772)
Easements and water rights	(5,519,394)	(5,200,726)
Concessions	(9,469,344)	(8,562,257)
Patents, Registered Trademarks and Other Rights	(478,232)	(454,032)
Computer software	(92,187,254)	(80,673,217)
Other identifiable intangible assets	(2,759,056)	(2,775,540)

	As of December 31,
	2020	2019
Intangible Assets, Net	ThCh$	ThCh$
Intangible Assets, Net	165,114,521	132,278,593
Easements and water rights	15,032,077	17,352,892
Concessions	43,584,113	26,156,419
Patents, Registered Trademarks and Other Rights	200,995	316,970
Computer software	94,668,184	76,162,800
Other identifiable intangible assets	11,629,152	12,289,512

The following table presents intangible assets other than Goodwill as of December 31, 2020 and 2019:

	Easements and water rights	Concessions	Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangibles Assets, Net
Changes in Intangible Assets	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2020	17,352,892	26,156,419	316,970	76,162,800	12,289,512	132,278,593
Changes in identifiable intangible assets
Increases other than from business combinations	—	23,221,080	—	32,122,529	—	55,343,609
Increase (decrease) from foreign currency translation differences	(239,991)	(3,566,641)	—	(273,172)	(661,569)	(4,741,373)
Amortization (1)	(556,017)	(2,009,087)	(24,200)	(11,785,777)	—	(14,375,081)
Impairment loss recognized in profit or loss (2)	—	(217,658)	—	—	—	(217,658)
Increases (decreases) from transfers and other changes	91,775	—	(91,775)	(1,067)	1,067	—
Increases (decreases) from transfers	91,775	—	(91,775)	(1,067)	1,067	—
Disposals and removal from service	(1,616,582)	—	—	—	—	(1,616,582)
Removals from service	(1,616,582)	—	—	—	—	(1,616,582)
Argentina Hyperinflation Effect	—	—	—	—	142	142
Other increases (decreases)	—	—	—	(1,557,129)	—	(1,557,129)
Total changes in identifiable intangible assets	(2,320,815)	17,427,694	(115,975)	18,505,384	(660,360)	32,835,928
Closing balance as of December 31, 2020	15,032,077	43,584,113	200,995	94,668,184	11,629,152	165,114,521

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	Easements and water rights	Concessions	Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangibles Assets, Net
Changes in Intangible Assets	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2019	17,736,954	25,953,878	7,394	60,067,635	11,606,532	115,372,393
Changes in identifiable intangible assets
Increases other than from business combinations	—	—	—	25,208,199	—	25,208,199
Increase (decrease) from foreign currency translation differences	425,373	2,028,583	—	156,906	926,375	3,537,237
Amortization (1)	(809,435)	(1,826,042)	(24,200)	(9,241,732)	(1,598)	(11,903,007)
Increases (decreases) from transfers and other changes	—	—	333,776	(91,776)	(242,000)	—
Increases (decreases) from transfers	—	—	333,776	(91,776)	(242,000)	—
Argentina Hyperinflation Effect	—	—	—	—	203	203
Increase (decrease)	—	—	—	63,568	—	63,568
Total changes in identifiable intangible assets	(384,062)	202,541	309,576	16,095,165	682,980	16,906,200
Closing balance as of December 31, 2019	17,352,892	26,156,419	316,970	76,162,800	12,289,512	132,278,593

(1) See Note 31 a).

(2) See Note 31 b).

No impairment losses have been recognized as of December 31, 2020, 2019 and 2018. According to the estimates and projections of the Group’s Management, the projections for the cash flows attributable to intangible assets allow recovering the net value of these assets recorded as of December 31, 2020 (see Note 3. e).

15.  GOODWILL

The following table sets forth goodwill by cash-generating unit or group of cash-generating units to which it belongs and changes for the years ended December 31, 2020 and 2019:

		Opening Balance 01-01-2019	Transfer Merger by Absorption	Foreign Currency Translation	Closing Balance 12/31/2019	Foreign Currency Translation	Closing Balance 12-31-2020
Company	Cash Generating Unit	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Colina S.A.	Enel Colina S.A.	2,240,478	—	—	2,240,478	—	2,240,478
Enel Distribución Chile S.A.	Enel Distribución Chile	128,374,362	—	—	128,374,362	—	128,374,362
Enel Generación Chile S.A.	Generación Chile	731,782,459	24,860,356	—	756,642,815	—	756,642,815
GasAtacama Chile S.A.	Generación Chile	24,860,356	(24,860,356)	—	—	—	—
Almeyda Solar SpA	Enel Green Power Chile S.A.	20,146,823	—	1,673,580	21,820,403	(1,194,585)	20,625,818
Geotérmica del Norte	Enel Green Power Chile S.A.	75,646	—	6,284	81,930	(4,485)	77,445
Parque Eólico Talinay Oriente	Enel Green Power Chile S.A.	7,564,601	—	628,385	8,192,986	(448,535)	7,744,451
	Total	915,044,725	—	2,308,249	917,352,974	(1,647,605)	915,705,369

According to the Group Management’s estimates and projections, the expected future cash flows projections attributable to the cash-generating units or groups of cash-generating units, to which the acquired goodwill has been allocated, allow the recovery of its carrying amount as of December 31, 2020 and 2019 (see Note 3.e).

The origin of the goodwill is detailed below:

1. Enel Colina S.A

On December 31, 1996, Enel Distribución Chile S.A acquired 100% of Empresa Eléctrica de Colina Ltda (currently Enel Colina S.A.) from Inversiones Saint Thomas S.A., a company that is neither directly or indirectly related to Enel Distribución Chile S.A.

F-79

2. Enel Distribución Chile S.A.

During November 2000, Enersis S.A. (currently Enel Américas S.A.) acquired in a public tender offer, an additional ownership interest of 25.4% in Enel Distribución Chile S.A. to reach 99.99% ownership.

3. Enel Generación Chile S.A.

On May 11, 1999, Enersis S.A. (currently Enel Américas S.A.) acquired an additional 35% ownership interest in Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) to achieve 60% ownership of the generation company, through a public tender offer in the Santiago Stock Exchange and the purchase of shares in the United States (30% and 5%, respectively).

On October 1, 2019, Gasatacama Chile S.A. merged with Enel Generación Chile S.A., with the latter being the legal surviving company. Due to the above, the following goodwill was directly recognized in Enel Generación Chile.

3.1 GasAtacama Chile S.A. (formerly Inversiones GasAtacama Holding Limitada)

On April 22, 2014, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired 50% ownership interest in GasAtacama Chile S.A. (formerly Inversiones GasAtacama Holding Limitada), previously held by Southern Cross Latin América Private Equity Fund III L.P.

3.2.GasAtacama Chile S.A. (formerly Empresa Eléctrica Pangue S.A.)

On July 12, 2002, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired 2.51% of the shares of Empresa Eléctrica Pangue S.A., upon exercise of the sale option by the minority shareholder International Finance Corporation (IFC).

On May 2, 2012, Empresa Eléctrica Pangue S.A. merged with Compañía Eléctrica San Isidro S.A., with the latter being the legal surviving company.

3.3. GasAtacama Chile S.A. (formerly Compañía Eléctrica San Isidro S.A.)

On August 11, 2005, Empresa Nacional de Electricidad S.A. (currently Enel Generación Chile S.A.) acquired an ownership interest in Inversiones Lo Venecia Ltda., whose sole asset was a 25% interest in San Isidro S.A.

On September 1, 2013, Compañía Eléctrica San Isidro S.A. merged with Endesa Eco S.A., with the latter being the legal surviving company.

On November 1, 2013, Endesa Eco S.A. merged with Compañía Eléctrica Tarapacá S.A., with the latter being the legal surviving company.

On November 1, 2016, Celta merged with GasAtacama Chile S.A., with the latter being the legal surviving company.

4. Enel Green Power Chile S.A.

On March 26, 2013, Enel Green Power Chile S.A. acquired ownership interest in Parque Eólico Talinay Oriente S.A.

On August 6, 2001, Enel Green Power Chile S.A. acquired ownership interests in Empresa Eléctrica Panguipulli S.A. and Empresa Eléctrica Puyehue S.A., which later merged with Panguipulli, with the latter company being the legal surviving company. Later, on July 1, 2020, Empresa Eléctrica Panguipulli S.A. was absorbed by Parque Eólico Taltal SpA, with the latter being the legal surviving company, and on August 1, 2020, Parque Eólico Taltal SpA was merged into Almeyda Solar SpA, with the latter company being the legal surviving company.

F-80

16.  PROPERTY, PLANT AND EQUIPMENT

The following table sets forth the property, plant and equipment as of December 31, 2020 and 2019:

	As of December 31,
	2020	2019
Classes of Property, Plant and Equipment, Gross	ThCh$	ThCh$
Property, Plant and Equipment, Gross	9,768,708,590	9,225,653,590
Construction in progress	1,567,685,720	1,048,988,931
Land	78,366,909	77,754,923
Buildings	562,807,945	531,250,194
Generation Plant and Equipment	5,992,384,131	6,002,160,751
Network infrastructure	1,378,810,834	1,396,996,724
Fixtures and fittings	171,396,847	150,242,089
Other property, plant and equipment	17,256,204	18,259,978

	As of December 31,
	2020	2019
Classes of Accumulated Depreciation and Impairment in Property, Plant and Equipment	ThCh$	ThCh$
Total Accumulated Depreciation and Impairment in Property, Plant and Equipment	(4,735,212,118)	(3,921,177,476)
Buildings	(144,646,529)	(110,930,435)
Plant and equipment	(3,871,912,436)	(3,106,167,890)
Network infrastructure	(584,630,846)	(587,567,750)
Fixtures and fittings	(117,944,385)	(102,483,181)
Other property, plant and equipment	(16,077,922)	(14,028,220)

	As of December 31,
	2020	2019
Classes of Property, Plant and Equipment, Net	ThCh$	ThCh$
Property, Plant and Equipment, Net	5,033,496,472	5,304,476,114
Construction in progress	1,567,685,720	1,048,988,931
Land	78,366,909	77,754,923
Buildings	418,161,416	420,319,759
Generation Plant and Equipment	2,120,471,695	2,895,992,861
Network infrastructure	794,179,988	809,428,974
Fixtures and fittings	53,452,462	47,758,908
Other property, plant and equipment	1,178,282	4,231,758

F-81

The composition and movements of the property, plant and equipment accounts during the fiscal year ended December 31, 2020 and 2019 are as follows:

	Construction in progress	Land	Buildings, Net	Generation Plant and Equipment Net	Network infrastructure, Net	Fixtures and Fittings, Net	Other property, plant and equipment, Net	Property, Plant and Equipment, Net
Changes in 2020	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2020	1,048,988,931	77,754,923	420,319,759	2,895,992,861	809,428,974	47,758,908	4,231,758	5,304,476,114
Increases other than from business combinations	744,544,601	-	151,195	691,268	101,862	119,324	-	745,608,250
Increases (decreases) from foreign currency translation differences	(57,958,736)	28,352	(19,184,500)	(54,569,811)	(3,320,508)	2,286,520	87,719	(132,630,964)
Depreciation (1)	—	—	(20,527,447)	(144,943,455)	(36,650,102)	(6,265,815)	(3,141,195)	(211,528,014)
Impairment losses recognized in profit or loss for the period (2)	(45,596,397)	—	—	(652,638,983)	—	—	—	(698,235,380)
Increases (decreases) from transfers and other changes	(57,868,918)	59,304	11,483,868	41,125,722	—	5,200,024	-	-
Increases (decreases) from transfers from construction in progress	(57,868,918)	59,304	11,483,868	41,125,722	—	5,200,024	-	-
Disposals and removals from service	(1,425,412)	-	—	(1,942,587)	(8,509,816)	—	-	(11,877,815)
Disposals	—	—	—	(1,942,587)	(6,899,719)	—	-	(8,842,306)
Removals	(1,425,412)	—	—	—	(1,610,097)	—	-	(3,035,509)
Other increases (decreases) (3)	(63,014,492)	489,124	25,862,428	36,315,417	33,129,578	4,137,244	-	36,919,299
Argentine hyperinflationary economy	16,143	35,206	56,113	441,263	—	216,257	-	764,982
Total changes	518,696,789	611,986	(2,158,343)	(775,521,166)	(15,248,986)	5,693,554	(3,053,476)	(270,979,642)
Closing balance as of December 31, 2020	1,567,685,720	78,366,909	418,161,416	2,120,471,695	794,179,988	53,452,462	1,178,282	5,033,496,472

	Construction in progress	Land	Buildings, Net	Generation Plant and Equipment, Net	Network infrastructure, Net	Fixtures and Fittings, Net	Other property, plant and equipment, Net	Property, Plant and Equipment, Net
Changes in 2019	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2019	862,274,093	74,753,283	384,027,047	3,143,869,929	764,095,247	55,091,617	6,881,745	5,290,992,961
Increases other than from business combinations	320,298,423	-	-	-	-	-	-	320,298,423
Increases (decreases) from foreign currency translation differences	9,880,815	36,282	29,731,649	81,221,513	4,238,408	65,341	361,574	125,535,582
Depreciation (1)	—	—	(17,944,173)	(159,163,293)	(34,964,877)	(6,299,395)	(3,011,561)	(221,383,299)
Impairment losses recognized in profit or loss for the period (2)	(32,967,462)	—	—	(247,052,801)	—	—	—	(280,020,263)
Increases (decreases) from transfers and other changes	(121,288,336)	4,151,834	22,879,420	17,534,668	74,941,622	1,780,792	-	—
Increases (decreases) from transfers from construction in progress	(121,288,336)	4,151,834	22,879,420	17,534,668	74,941,622	1,780,792	-	—
Disposals and removals from service	—	(406,656)	(792,638)	(948,350)	(1,880,608)	(837,345)	-	(4,865,597)
Disposals	—	(406,656)	—	(948,350)	—	—	-	(1,355,006)
Removals	—	—	(792,638)	—	(1,880,608)	(837,345)	-	(3,510,591)
Other increases (decreases) (3)	10,843,933	(779,820)	2,418,454	59,398,742	2,999,182	(2,042,102)	-	72,838,389
Argentine hyperinflationary economy	(52,535)	-	—	1,132,453	—	—	-	1,079,918
Total changes	186,714,838	3,001,640	36,292,712	(247,877,068)	45,333,727	(7,332,709)	(2,649,987)	13,483,153
Closing balance as of December 31, 2019	1,048,988,931	77,754,923	420,319,759	2,895,992,861	809,428,974	47,758,908	4,231,758	5,304,476,114

(1) See Note 31.

(2) See clause iv) in section c) other information, contained in this same Note.

(3) See Note 25.

Additional information on property, plant and equipment, net

a)    Main investments

The main additions to property, plant and equipment relate to investments in the Company’s networks, investments in operating plants and new projects under construction. Total work in progress amounted to ThCh$ 1,567,685,720 and ThCh$ 1,048,988,931 as of December 31, 2020 and 2019, respectively.    

In the Distribution Business, the main investments are improvements in networks to optimize their operation, in order to improve efficiency and quality of service level. The carrying amount of these works in progress totaled ThCh$148,835,155 and ThCh$173,566,099 as of December 31, 2020 and 2019, respectively.

In the Generation Business, investments include works towards the new capacity program. This includes:

F-82

i) Progress on the construction of the Los Cóndores Hydroelectric power plant, by Enel Generación Chile, which will use the resources from the Maule Lake and will have an installed capacity of approximately 150 MW. The carrying amount recorded in assets for this project was ThCh$637,303,224 and ThCh$541,401,896, as of December 31, 2020 and 2019, respectively.

ii) Progress on the Sol de Lila, Azabache, Domeyko, Valle del Sol, Finis Terrae, Renaico II, Cerro Pabellón and Campos del Sol projects, which together represent an installed capacity of approximately 1.3 GW, and which are being executed by Enel Green Power Chile.  The carrying amount recorded in assets for this project was ThCh$436,164,981 and ThCh$17,485,325, as of December 31, 2020 and 2019, respectively.

Following the accounting criteria described in Note 3.a), only those investments made in the abovementioned generation projects qualify as assets suitable for capitalizing interest. As a whole, these projects represent cumulative cash disbursements in the amount of ThCh$780,827,755 and ThCh$543,844,674, as of December 31, 2020 and 2019.

b)    Capitalized cost

b.1) Capitalized financial expenses

The capitalized cost for financial expenses amounted to ThCh $ 33,109,819 as of December 31, 2020, (ThCh $ 9,321,354 and ThCh $ 6,435,646 as of December 31, 2019 and 2018, respectively) (see Note 34). The average financing rate ranged between 4.60% and 6.84% as of December 31, 2020 (5.86% as of December 31, 2019).

The increase in interest capitalization evidenced during 2020 is mainly explained by a greater development of non-conventional renewable energy projects and by a greater continuity in the development of the Los Cóndores project. Note that, with respect to the Los Cóndores project, given the difficulties inherent to a project of this magnitude and the impacts related to COVID-19, which implied some suspensions in the execution of the same during the last year, an update of the project schedule was provided by Enel Generación Chile in an essential fact dated July 27, 2020, estimating that it will be completed in the last quarter of 2023.

b.2) Capitalized personnel expenses in work-in-progress

The capitalized cost for personnel expenses directly related directly to constructions in progress amounted to ThCh$25,539,316, ThCh$17,610,861 and ThCh$16,710,963 as of December 31, 2020, 2019 and 2018, respectively.

The increase in the capitalization of interest and personnel expenses compared to 2019 is mainly due to a greater development of non-conventional renewable energy projects.

c)    Other information

i) As of December 31, 2020, and 2019, the Group maintained commitments to acquire tangible fixed assets in the amount of ThCh$303,709,257 and ThCh$185,457,682, respectively.

ii) As of December 31, 2020, and 2019, Enel Chile had no property, plant and equipment pledged as collateral for liabilities.

iii) The Group and its consolidated entities have insurance contracts with policies that cover any risk, earthquake and machinery breakdown up to a limit of €1,000 million (ThCh$873,300,000), and this coverage includes damages due to business disruption.

Additionally, the Group has civil liability insurance policies for third-party claims up to a limit of €500 million (ThCh$436,650,000) when these claims are due to the rupture of any dams owned by the Company or its Subsidiaries, and Environmental Civil Liability to cover environmental damage claims up to €20 million

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(ThCh$17,466,000). The premiums associated with these policies are recorded proportionally to each company in the caption prepaid expenses.

iv) Decarbonization plan

Development during 2019

On June 4, 2019, the Company’s subsidiaries Enel Generación Chile and Gasatacama Chile entered into an agreement by which both companies, in line with their own sustainability strategy and strategic plan, and the Ministry of Energy, regulated how they would proceed to progressively eliminate the Tarapacá, Bocamina I and Bocamina II coal-fired generation units (hereinafter, Tarapacá, Bocamina I and Bocamina II).

The agreement is subject to the condition precedent that the regulations on capacity transfers between generation companies go into force, which establishes, among other things, the essential conditions to ensure non-discriminatory treatment among the generators and to define the State of Strategic Reserve. By virtue of the above, Enel Generación Chile and Gasatacama Chile would formally and irrevocably agree to the final withdrawal of Bocamina 1 and Tarapacá, respectively, from the National Electricity System, establishing their deadlines at May 31, 2020 for Tarapacá, and December 31, 2023 for Bocamina I.

The Group stated its intention to accelerate the withdrawal of Tarapacá and Bocamina I, promoting the termination of their operations, all fully coordinated with the Authority. Within this context, on June 17, 2019, Gasatacama Chile submitted a request to the National Energy Commission (hereinafter CNE) to perform the final withdrawal, disconnection, and termination of operations of Tarapacá at an earlier date, i.e., by December 31, 2019.  On July 26, 2019, by Exempt Resolution No. 450 and in accordance with the provisions of article 72 -18 of the General Law of Electricity Services, the CNE authorized the final withdrawal, disconnection, and termination of operations of Tarapacá from December 31, 2019.

The management of the Tarapacá and Bocamina I assets will be carried out separately, and these assets will not form part of the Cash-Generating Unit formed by the rest of the plants owned by the Enel Generación Chile Group, whose economic management is performed in an integrated manner.

Due to the abovementioned and as a result of impairment testing on an individual basis, in 2019 the Group recognized impairment losses in the amount of ThCh$197,188,542 and ThCh $82,831,721 to adjust the carrying amount of the capitalized investment in Tarapacá and Bocamina I, respectively, to their recoverable amount. The resulting recoverable amount, after the recorded impairment, corresponds to the value of the lands held in Tarapacá and Bocamina I, in the amount of ThCh$1,613,803 and ThCh$ 6,362,581, respectively.

With respect to Bocamina II, Enel Generación Chile set a goal for its early withdrawal by December 31, 2040, at the latest. All of the above was subject to the authorization established in the General Law of Electricity Services. The financial effects would depend on the factors involved in the electricity market behavior, such as fuel prices, hydrological conditions, the growth of electricity demand, and international inflation indexes, which could not be determined at the close of 2019.

Notwithstanding the above, the useful lives of the Bocamina II assets were adjusted such that in any case, the depreciation would be calculated for any useful lives beyond December 31, 2040. This measure implied the recognition of a higher depreciation of ThCh$ 4,083,855 during 2019.

Development during 2020:

On May 27, 2020, the Board of Directors of Enel Generación Chile approved, subject to the corresponding CNE authorizations, the early withdrawal of Bocamina I and Bocamina II, establishing deadlines for such withdrawals on December 31, 2020 and May 31, 2022, respectively. The corresponding request was communicated to the CNE that same day.

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This decision shows the Company's commitment to fight against climate change and also considered the deep changes being experienced by the Industry, including the constant and increasing penetration of renewable energies and the reduction in commodities prices, making gas-powered production more competitive, which would give greater flexibility to the system's operations in comparison to coal-fired production.

On July 3, 2020, the CNE issued Exempt Resolution No. 237 authorizing the final withdrawal, disconnection, and termination of operations of Bocamina I from December 31, 2020.

Regarding Bocamina II, the Group also intended to accelerate its early closure, promoting the discontinuation of its operations in strict coordination with the Authority. In this context, on July 23, 2020, the CNE issued Exempt Resolution No. 266 authorizing the final withdrawal, disconnection, and termination of operations of Bocamina II as of May 31, 2022.

As occurred in 2019 with Tarapacá and Bocamina I, Bocamina II’s management assets will be managed separately and, accordingly, these assets will not form part of the Cash-Generating Unit consisting of the rest of the plants owned by the Enel Generación Chile Group, whose economic management continues to be carried out in a centralized manner.

Consequently, and as a result of impairment testing on an individual basis, in 2020 the Group recorded an impairment loss of ThCh$697,856,387 to adjust the carrying amount of the capitalized investment in Bocamina II to its recoverable value (See Note 31). The resulting recoverable value, after the impairment recorded, corresponds to the value of the land associated with this plant, which as of December 31, 2020 was ThCh$2,014,684.

These situations have effects on deferred taxes, which are disclosed in Note 19.b.

v) As of September 2020, the Company’s subsidiary Empresa Nacional de Geotermia recorded an impairment of its works in progress of ThCh$378,993. Subsequently, its liquidation process began in December 2020.

vi) As a result of the public disturbances occurred in Chile during the last quarter of 2019, write-offs related to property, plant and equipment amounting to ThCh$1,629,983 were recorded. On the other hand, equipment disposals amounting to ThCh$1,880,608 ocurred. Both concepts total ThCh$3,510,591, see Note 32.

17.  INVESTMENT PROPERTY

The investment property breakdown and activity during 2020 and 2019 are detailed as follows:

	Investment Properties, Gross	Accumulated Depreciation, Amortization and Impairment	Investment Properties, Net
Investment Property, Net, Cost Model	ThCh$	ThCh$	ThCh$
Balance at January 1, 2019	9,189,377	(1,632,021)	7,557,356
Depreciation expense	—	(19,812)	(19,812)
Impairment loss recognized in the income statement	—	(742,389)	(742,389)
Balance at December 31, 2019	9,189,377	(2,394,222)	6,795,155
Depreciation expense	—	(19,812)	(19,812)
Reversals of impairment recognized in the income statement	—	646,597	646,597
Balance at December 31, 2020	9,189,377	(1,767,437)	7,421,940

During 2020 and 2019, no real estate property has been sold.

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- Fair value measurement and hierarchy

As of December 31, 2020, and 2019, the fair value of the investment was ThCh$8,484,901 and ThCh$7,880,432 respectively. This value was determined according to independent appraisals.

The input data used in this valuation are considered to be Level 3 for the purposes of the fair value hierarchy.

The fair value hierarchy for investment properties is the following:

	Fair value measured as of December 31, 2020
	Level 1	Level 2	Level 3
	ThCh$	ThCh$	ThCh$
Investment properties	—	—	8,484,901

See Note 3.h.

The revenue and expenses derived from investment properties for the years ended December 31, 2020, 2019 and 2018, are detailed as follows:

	2020	2019	2018
Income and expense from investment properties	ThCh$	ThCh$	ThCh$
Income derived from rental income from investment properties	196,955	202,896	204,166
Direct operating expenses from investment properties that generate rental income	(36,761)	(44,136)	(56,327)
Total	160,194	158,760	147,839

There are no contracts for repairs, maintenance, acquisition, construction, or development which represent future obligations for the Group as of December 31, 2020 and 2019.

The Group has engaged insurance policies to cover the possible risks to which the different elements of its real estate investments are exposed, as well as potential claims that may arise due to the performance of its activities, with the understanding that these policies sufficiently cover these risks.

18.  RIGHT-OF-USE-ASSETS

Right-of-use assets for the year ended December 31, 2020 and 2019, are detailed as follows:

	Land	Other Plants and Equipments	Right-of-use assets, Net
Changes in 2020	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2020	34,081,799	21,761,711	55,843,510
New assets contracts, by right-of use	213,445	2,491,480	2,704,925
Increases (decreases) from foreign currency translation differences, net	830,349	157,520	987,869
Depreciation	(1,894,646)	(2,139,466)	(4,034,112)
New agreements (decreases)	356,444	(356,444)	-
Other increases (decreases)	(707,853)	(2,338,390)	(341,318)
Closing balance as of December 31, 2020	33,373,946	19,423,321	55,502,192
	Land	Other Plants and Equipments	Right-of-use assets, Net
Changes in 2019	ThCh$	ThCh$	ThCh$
Opening balance as of January 1, 2019 before application of IFRS 16	2,758	17,651,914	17,654,672
Effects first time adoption IFRS 16	23,097,767	5,716,375	28,814,142
Opening balance as of January 1, 2019 after application of IFRS 16	23,100,525	23,368,289	46,468,814
Increases (decreases) from foreign currency translation differences, net	1,537,867	-	1,537,867
Depreciation	(1,482,706)	(1,838,562)	(3,321,268)
New agreements (decreases)	10,926,113	231,984	11,158,097
Total changes	10,981,274	-1,606,578	9,374,696
Closing balance as of December 31, 2019	34,081,799	21,761,711	55,843,510

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As of December 31, 2020 and 2019, the main right-of-use assets and lease liabilities are detailed as follows:

-These come primarily from a contract for Electricity Transmission Lines and Facilities (Ralco-Charrúa 2X220 KV), entered into by Enel Generación Chile S.A. and Transelec S.A. This contract has a duration of 20 years and accrues interest at an annual rate of 6.5%.

-In addition, as a consequence of the application of IFRS 16 (see Note 3.f), the Group recognized as of January 1, 2019 right-of-use assets related to property, plant and equipment in the amount of ThCh$28,814,142.

The present value of future payments derived from those contracts is detailed as follows:

	As of December 31,
	2020			2019
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	8,783,640	1,775,929	7,007,711	7,602,720	1,760,705	5,842,015
From one to two years	6,583,269	1,546,496	5,036,773	6,234,867	1,719,045	4,515,822
From two to three years	8,399,111	1,332,024	7,067,087	6,049,847	1,484,321	4,565,526
From three to four years	3,271,835	1,245,169	2,026,666	8,326,858	1,265,224	7,061,634
From four to five years	3,077,572	1,174,438	1,903,134	2,964,375	1,180,435	1,783,940
More than five years	37,595,016	8,770,869	28,824,147	38,630,310	8,991,558	29,638,752
Total	67,710,443	15,844,925	51,865,518	69,808,977	16,401,288	53,407,689

a) Short-term and low-value leases

The consolidated income statement for the years ended December 31, 2020 and 2019 includes expenses in the amount of ThCh$4,958,760 and ThCh$3,824,195, respectively, of which ThCh$3,334,241 correspond to short-term lease payments in 2020 and ThCh$1,995,392 in 2019; while ThCh$1,624,519 and ThCh$1,828,803, relate to leases with variable payment clauses in 2020 and 2019, respectively, which are exempt from the application of IFRS 16 (see Note 3.f).

As of December 31, 2020 and 2019, future payments derived from those contracts are detailed as follows:

	As of December 31,	As of December 31,
	2020	2019
	ThCh$	ThCh$
Less than one year	4,813,265	3,485,151
From one to two years	—	—
From two to three years	—	—
From three to four years	—	—
From four to five years	—	—
More than five years	—	—
Total	4,813,265	3,485,151

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19.  INCOME TAX AND DEFERRED TAXES

a)    Income taxes

The components of income tax for the years 2020, 2019 and 2018 are detailed as follows:

	2020	2019	2018
Current Income Tax and Adjustments to Current Income Tax for Previous Periods	ThCh$	ThCh$	ThCh$
Current income tax	(155,196,656)	(54,904,679)	(47,354,780)
Adjustments to current tax from the previous period	3,694,656	(2,251,167)	(6,304,285)
Current tax (expenses) / benefit (related to cash flow hedges)	72,354,119	(36,172,878)	(60,650,786)
Other current tax benefit / (expense)	(98,646)	(1,197,052)	(856,466)
Current tax expense, net	(79,246,527)	(94,525,776)	(115,166,317)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences	160,551,634	33,297,872	(43,134,500)
Adjustments to deferred taxes from the previous period	—	—	4,818,298
Total deferred tax benefit / (expense)	160,551,634	33,297,872	(38,316,202)
Income tax expense	81,305,107	(61,227,904)	(153,482,519)

The following table shows the reconciliation of the tax rate as of December 31, 2020, 2019 and 2018:

		2020		2019		2018
Reconciliation of Tax Expense	Tax Rate	ThCh$	Tax Rate	ThCh$	Tax Rate	ThCh$
ACCOUNTING INCOME BEFORE TAX		(133,691,942)		377,321,122		566,330,276
Total tax income (expense) using statutory rate	27.00%	36,096,825	(27.00)%	(101,876,703)	(27.00)%	(152,909,175)
Tax effect of rates applied in other countries	—	—	0.06%	232,897	—	—
Tax effect of tax-exempt revenue and other positive effects impacting the effective rate	31.83%	42,557,794	11.30%	42,638,986	0.31%	1,746,052
Tax effect of non-deductible expenses for determining taxable profit (loss)	(7.32)%	(9,790,603)	(2.76)%	(10,399,776)	(2.26)%	(12,786,965)
Tax effect of adjustments to income taxes in previous periods	2.76%	3,694,656	(0.60)%	(2,251,167)	(1.11)%	(6,304,285)
Adjustments for prior periods deferred taxes	-	—		—	0.85%	4,818,298
Price level restatement for tax purposes (investments and equity)	6.54%	8,746,435	2.76%	10,427,859	2.11%	11,953,556
Total adjustments to tax expense using statutory rate	33.82%	45,208,282	10.77%	40,648,799	(0.10)%	(573,344)
Income tax benefit (expense)	60.82%	81,305,107	(16.23)%	(61,227,904)	(27.10)%	(153,482,519)

The main temporary differences are described below.

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b)    Deferred taxes

The origin of and changes in deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows:

	12-31-2020		12-31-2019
	Assets	Liabilities	Assets	Liabilities
Deferred Taxes Assets/(Liabilities)	ThCh$	ThCh$	ThCh$	ThCh$
Depreciations	55,197,762	(249,821,145)	10,652,313	(404,453,928)
Obligations for post-employment benefits	9,581,174	(5,997)	7,772,646	(34,413)
Revaluations of financial instruments	—	—	456,888	—
Tax loss	46,518,690	—	81,154,636	—
Provisions	91,579,562	—	87,275,541	—
Dismantling Provision	51,513,634	—	44,485,711	—
Provision for Civil Contingencies	3,991,087	—	3,502,161	—
Provision Contingencies Workers	—	—	492,522	—
Provision for doubtful trade accounts	12,544,171	—	14,555,712	—
Provision of Human Resources accounts	8,605,410	—	7,859,341	—
Other Provisions	14,925,260	—	16,380,094	—
Other Deferred Taxes	24,942,402	(38,036,065)	20,980,774	(31,240,859)
Activation of expenses for issuance of financial debt	—	(10,691,535)	—	(11,412,737)
Monetary Correction - Argentina	—	(1,015,095)	—	(657,871)
Other Deferred Taxes	24,942,402	(26,329,435)	20,980,774	(19,170,251)
Deferred taxes Assets/(Liabilities) before compensation	227,819,590	(287,863,207)	208,292,798	(435,729,200)
Compensation deferred taxes Assets/Liabilities	(119,805,645)	119,805,645	(186,444,559)	186,444,559
Deferred taxes Assets/(Liabilities) after compensation	108,013,945	(168,057,562)	21,848,239	(249,284,641)

		Changes
Recognized in others in comprehensive income	Net balance as of January 1, 2020	Recognized in profit or loss	Recognized in others in comprehensive income	Foreign currency translation difference	Other increases (decreases)	Net balance as of December 31, 2020
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Depreciations (1)	(393,801,615)	191,919,566	—	7,258,666	—	(194,623,383)
Obligations for post-employment benefits	7,738,233	(464,804)	2,308,510	(6,762)	—	9,575,177
Revaluations of financial instruments	456,888	(93,879)	(387,000)	23,991	—	—
Tax loss	81,154,636	(33,611,187)	—	(1,024,759)	—	46,518,690
Provisions	87,275,541	5,091,987	—	(787,966)	—	91,579,562
Dismantling Provision	44,485,711	7,238,957	—	(211,034)	—	51,513,634
Provision for Civil Contingencies	3,502,161	464,407	—	24,519	—	3,991,087
Provision Contingencies Workers	492,522	(517,792)	—	25,270	—	—
Provision for doubtful trade accounts	14,555,712	(1,995,773)	—	(15,768)	—	12,544,171
Provision of Human Resources accounts	7,859,341	801,863	—	(55,794)	—	8,605,410
Other Provisions	16,380,094	(899,675)	—	(555,159)	—	14,925,260
Other Deferred Taxes	(10,260,085)	(2,290,049)	2,464	2,512	(548,505)	(13,093,663)
Capitalization of expenses for issuance of financial debt	(11,412,738)	721,203		—	—	(10,691,535)
Monetary Correction - Argentina	(657,871)	191,281		—	(548,505)	(1,015,095)
Other Deferred Taxes	1,810,524	(3,202,533)	2,464	2,512	—	(1,387,033)
Deferred taxes Assets/(Liabilities)	(227,436,402)	160,551,634	1,923,974	5,465,682	(548,505)	(60,043,617)

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		Changes
Recognized in others in comprehensive income	Net balance as of January 1, 2019	Recognized in profit or loss	Recognized in others in comprehensive income	Foreign currency translation difference	Other increases (decreases)	Net balance as of December 31, 2019
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Depreciations (1)	(349,976,401)	(5,668,543)	—	(1,561,204)	(36,595,467)	(393,801,615)
Obligations for post-employment benefits	5,709,648	126,352	2,099,845	—	(197,612)	7,738,233
Revaluations of financial instruments	—	—	710,523	—	(253,635)	456,888
Tax loss	36,921,157	14,343,314	—	2,096,339	27,793,826	81,154,636
Provisions	55,080,385	24,123,136	—	795,123	7,276,897	87,275,541
Dismantling Provision	23,627,264	20,711,621	—	34,574	112,252	44,485,711
Provision for Civil Contingencies	4,108,710	(606,549)	—	—	—	3,502,161
Provision Contingencies Workers	430,900	61,622	—	—	—	492,522
Provision for doubtful trade accounts	13,253,612	1,302,403	—	128	(431)	14,555,712
Provision of Human Resources accounts	7,432,939	3,233,471	—	(13,109)	(2,793,960)	7,859,341
Other Provisions	6,226,960	(579,432)	—	773,530	9,959,036	16,380,094
Other Deferred Taxes	(6,643,613)	373,614	992	—	(3,991,078)	(10,260,085)
Capitalization of expenses for issuance of financial debt	(11,202,063)	(407,318)	—	—	196,643	(11,412,738)
Monetary Correction - Argentina	(425,687)	(207,916)	—	—	(24,268)	(657,871)
Other Deferred Taxes	4,984,137	988,848	992	—	(4,163,453)	1,810,524
Deferred taxes Assets/(Liabilities)	(258,908,824)	33,297,873	2,811,360	1,330,258	(5,967,069)	(227,436,402)

(1) See Note 16, c), iv).

Recovery of deferred tax assets will depend on whether sufficient taxable profits are obtained in the future. The Company’s Management believes that the future profit projections for its subsidiaries will allow these assets to be recovered.

As of December 31, 2020, the Group has not recognized deferred tax assets related to tax loss carry forwards of for ThCh$4,551,790 (ThCh$4,625,940 as of December 31, 2019) (see Note 3.p).

Concerning temporary differences related to investments in consolidated entities and certain joint ventures, the Group has not recognized deferred tax liabilities associated with undistributed profits, in which the position of control exercised by the Group over such consolidated entities allows it to manage the time of their reversal, and it is estimated that they will not be reversed in the near future. The total amount of these taxable temporary differences, for which no deferred tax liabilities have been recognized as of December 31, 2020, amounts to ThCh$1,317,729,055 (ThCh$1,323,714,721 as of December 31, 2019). Additionally, no deferred tax assets have been recorded in relation to the deductible temporary differences associated with investments in consolidated entities and certain joint ventures. Such temporary differences are not expected to be reversed in the foreseeable future or tax gains will not be available for their use. As of December 31, 2020, such deductible temporary differences amount to ThCh$999,207,087 (ThCh$691,241,687 as of December 31,2019).

The Group companies are potentially subject to income tax audits by the tax authorities of each country in which the Group operates. Such tax audits are limited to a number of annual tax periods and once these have expired, audits of these periods can no longer be performed.

Tax audits by nature are often complex and can require several years to complete. Tax years potentially subject to examination are 2017 to 2019.

Given the range of possible interpretations of tax standards, the results of any future inspections carried out by tax authorities for the years subject to audit can give rise to tax liabilities that cannot currently be quantified objectively. Nevertheless, the Company’s Management estimates that the liabilities, if any, that may arise from such audits, would not significantly impact the Group companies’ future results.

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The effects of deferred taxes on the components of other comprehensive income attributable to both controlling and non-controlling interests for the years ended 2020, 2019 and 2018, are as follows:

	2020			2019			2018
Effects of Income Tax on the Components of	Amount Before Tax	Income Tax Expense (Benefit)	Amount After Tax	Amount Before Tax	Income Tax Expense (Benefit)	Amount After Tax	Amount Before Tax	Income Tax Expense (Benefit)	Amount After Tax
Other Comprehensive Income	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Financial assets at fair value with changes in other comprehensive income	(9,125)	2,464	(6,661)	(3,673)	992	(2,681)	(411)	111	(300)
Cash flow hedge	267,540,328	(72,741,119)	194,799,209	(139,174,121)	36,883,401	(102,290,720)	(221,906,855)	60,650,786	(161,256,069)
Share of other comprehensive income from associates and joint ventures accounted for using the equity method	18,982	—	18,982	0	—	—		—	—
Foreign currency translation	(69,218,245)	—	(69,218,245)	73,114,966	—	73,114,966	107,492,316	—	107,492,316
Actuarial gains(losses) on defined-benefit pension plans	(8,545,834)	2,308,510	(6,237,324)	(7,777,204)	2,099,845	(5,677,359)	37,881	(10,228)	27,653
Income tax related to components of other income and expenses with a charge or credit in equity	189,786,106	(70,430,145)	119,355,961	(73,840,032)	38,984,238	(34,855,794)	(114,377,069)	60,640,669	(53,736,400)

The following table shows the reconciliation of deferred tax movements between balance sheet and income taxes in other comprehensive income as of December 31, 2020, 2019 and 2018:

	For the years ended December 31,
	2020	2019	2018
Deferred taxes of components of other comprehensive income	ThCh$	ThCh$	ThCh$
Total increases (decreases) for deferred taxes of other comprehensive income from continuing operations	1,923,974	2,811,360	(10,117)
Income tax of changes in cash flow hedge transactions	(72,354,119)	36,172,878	60,650,786
Total income tax relating to components of other comprehensive income	(70,430,145)	38,984,238	60,640,669

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20.  OTHER FINANCIAL LIABILITIES.

The balance of other financial liabilities as of December 31, 2020 and 2019 is as follows:

	12-31-2020		21-31-2019
	Current	Non-current	Current	Non-current
Other financial liabilities	ThCh$	ThCh$	ThCh$	ThCh$
Interest –bearing borrowings	152,076,992	1,467,421,655	158,562,319	1,667,271,871
Hedging derivatives (*)	5,398,864	16,167,471	48,225,766	25,208,326
Non-hedging derivatives (**)	23,285	—	2,026,476	124,048
Total	157,499,141	1,483,589,126	208,814,561	1,692,604,245

(*) See Note 23.2.a

(**)See Note 23.2.b

20.1 Interest-bearing borrowings

The detail of current and non-current interest-bearing borrowings as of December 31, 2020 and 2019 is as follows:

	12-31-2020		12-31-2019
	Current	Non-current	Current	Non-current
Classes of Interest-bearing borrowings	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing borrowings	152,076,992	1,467,421,655	158,562,319	1,667,271,871
Secured bank loans	106,783,562	21,315,003	113,247,263	135,297,019
Unsecured bank loans	4	—	5	—
Unsecured obligations with the public	45,293,426	1,446,106,652	45,315,051	1,531,974,852
Total	152,076,992	1,467,421,655	158,562,319	1,667,271,871

Bank borrowings by currency and contractual maturity as of December 31, 2020 and 2019 are as follows:

F-92

- Summary of bank borrowings by currency and maturity

					Maturity			Maturity
Country	Currency	Effective Interest	Nominal Interest	Secured / Unsecured	One to three months	Three to twelve months	Total Current 12-31-2020	One to two years	Two to three years	Total Non- Current
		Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	1.77%	1.77%	Secured	-	106,783,562	106,783,562	21,315,003	-	21,315,003
Chile	CLP	6.00%	6.00%	Unsecured	4	-	4	-	-	-
				Total	4	106,783,562	106,783,566	21,315,003	-	21,315,003
					Maturity			Maturity
Country	Currency	Effective  Interest	Nominal  Interest	Secured / Unsecured	One to three  months	Three to twelve months	Total Current 12-31-2019	One to two years	Two to three  years	Total Non- Current
		Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	3.31%	3.31%	Sí	134,532	113,112,731	113,247,263	112,747,516	22,549,503	135,297,019
Chile	CLP	6.00%	6.00%	No	5	-	5	-	-	-
				Total	134,537	113,112,731	113,247,268	112,747,516	22,549,503	135,297,019

Fair value measurement and hierarchy

The fair value of current and non-current bank borrowings as of December 31, 2020 is ThCh$127,771,152 (ThCh$247,030,075 as of December 31,2019). The borrowings has been categorized as Level 2 fair value measurement based on the entry data used in the valuation techniques (see Note 3.h).

F-93

Identification of bank borrowings by company

											12-31-2020
											Current			Non-current
Taxpayer ID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Type of Amortization	Secured	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Total Non- Current ThCh$
96.800.570-7	Enel Distribución Chile S.A.	Chile	97.036.000-k	Banco Santander (Overdraft line)	Chile	CLP	6.00%	6.00%	Upon expiration	No	1	—	1	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-k	Banco Santander (Overdraft line)	Chile	CLP	6.00%	6.00%	Upon expiration	No	3	—	3	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	2.10%	2.10%	Upon expiration	Yes	—	—	0	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Foreign	Inter-American Development Bank ( BID )	E.E.U.U.	US$	1.50%	1.50%	Upon expiration	Yes	—	39,966	39,966	21,315,003	—	—
76.321.458-3	Almeyda Solar SPA	Chile	91.018.000-1	Scotiabank Chile	Chile	US$	2.03%	2.03%	Upon expiration	Yes	—	106,743,596	106,743,596	—	—	—
							Total				4	106,783,562	106,783,566	21,315,003	—	21,315,003
											12-31-2019
											Current			Non-current
Taxpayer ID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Type of Amortization	Secured	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Total Non- Current ThCh$
96.800.570-7	Enel Distribución Chile S.A.	Chile	97.036.000-k	Banco Santander (Overdraft line)	Chile	CLP	6.00%	6.00%	Upon expiration	No	1	—	1	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-k	Banco Santander (Overdraft line)	Chile	CLP	6.00%	6.00%	Upon expiration	No	4	—	4	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	2.10%	2.10%	Upon expiration	Yes	134,532	112,747,516	112,882,048	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	Foreign	Inter-American Development Bank ( BID )	E.E.U.U.	US$	1.50%	1.50%	Upon expiration	Yes	—	43,220	43,220	—	22,549,503	22,549,503
76.321.458-3	Almeyda Solar SPA	Chile	91.018.000-1	Scotiabank Chile	Chile	US$	2.03%	2.03%	Upon expiration	Yes	—	321,995	321,995	112,747,516	—	112,747,516
							Total				134,537	113,112,731	113,247,268	112,747,516	22,549,503	135,297,019

20.2 Unsecured liabilities

The detail of Unsecured Liabilities by currency and maturity as of December 31, 2020 and 2019, is as follows:

Summary of Unsecured liabilities by currency and maturity

								Non-Current
					Maturity			Maturity
		Effective Interest	Nominal Interest	Secured	Less than 90 days	Three to Twelve months	Total Current 12-31-2020	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12/31/2020
Country	Currency	Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.71%	6.49%	No	9,140,614	2,551,520	11,692,134	—	—	282,085,533	—	914,327,429	1,196,412,962
Chile	UF	6.00%	5.48%	No	—	33,601,292	33,601,292	32,474,175	32,474,175	32,474,175	32,474,175	119,796,990	249,693,690
				Total	9,140,614	36,152,812	45,293,426	32,474,175	32,474,175	314,559,708	32,474,175	1,034,124,419	1,446,106,652
								Non-Current
					Maturity			Maturity
		Effective Interest	Nominal Interest	Secured	Less than 90 days	Three to Twelve months	Total Current 12-31-2019	One to two years	Two to three years	Three to four years	Four to five years	More than five years	Total Non- Current 12/31/2019
Country	Currency	Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.59%	6.49%	No	7,700,030	4,755,019	12,455,049	—	—	—	296,420,703	961,519,091	1,257,939,794
Chile	U.F.	6.00%	5.48%	No	—	32,860,002	32,860,002	31,624,776	31,624,776	31,624,776	31,624,776	147,535,954	274,035,058
				Total	7,700,030	37,615,021	45,315,051	31,624,776	31,624,776	31,624,776	328,045,479	1,109,055,045	1,531,974,852

F-94

Individual identification of Unsecured liabilities by debtor.

											12-31-2020
											Current			Non-Current
Taxpayer ID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Maturity	Secured	Less than 90 days ThCh$	Three to Twelve months	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Total Non- Current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-1	E.E.U.U	US$	7,96%	7,88%	Upon expiration	No	4,802,802	—	4,802,802	—	—	—	—	145,773,744	145,773,744
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-2	E.E.U.U	US$	7,40%	7,33%	Upon expiration	No	1,535,840	—	1,535,840	—	—	—	—	49,297,180	49,297,180
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-3	E.E.U.U	US$	8,26%	8,13%	Upon expiration	No	972,757	—	972,757	—	—	—	—	23,349,497	23,349,497
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Unica 24296	E.E.U.U	US$	4,32%	4,25%	Upon expiration	No	—	2,551,520	2,551,520	—	—	282,085,533	—		282,085,533
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander -317 Serie-H	Chile	UF	7,17%	6,20%	Semestral	No	—	6,682,676	6,682,676	6,046,629	6,046,629	6,046,629	6,046,629	15,431,031	39,617,547
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander 522 Serie-M	Chile	UF	4,82%	4,75%	Semestral	No	—	26,918,616	26,918,616	26,427,546	26,427,546	26,427,546	26,427,546	104,365,959	210,076,143
76.536.353-5	Enel Chile S.A.	Chile	Foreign	BNY Mellon - Unica	E.E.U.U	US$	5,24%	4,88%	Upon expiration	No	1,829,215	—	1,829,215					695,907,008	695,907,008
										Total Unsecured Bonds	9,140,614	36,152,812	45,293,426	32,474,175	32,474,175	314,559,708	32,474,175	1,034,124,419	1,446,106,652
											12-31-2019
											Current			Non-Current
Taxpayer ID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Maturity	Secured	Less than 90 days ThCh$	Three to Twelve months	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Total Non- Current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-1	E.E.U.U	US$	7,96%	7,88%	Upon expiration	No	5,058,091	—	5,058,091	—	—	—	—	153,480,285	153,480,285
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-2	E.E.U.U	US$	7,40%	7,33%	Upon expiration	No	1,617,476	—	1,617,476	—	—	—	—	51,960,662	51,960,662
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-3	E.E.U.U	US$	8,26%	8,13%	Upon expiration	No	1,024,463	—	1,024,463	—	—	—	—	24,876,133	24,876,133
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Unica 24296	E.E.U.U	US$	4,32%	4,25%	Upon expiration	No	—	2,828,573	2,828,573	—	—	—	296,420,703	—	296,420,703
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander -317 Serie-H	Chile	UF	7,17%	6,20%	Semestral	No	—	6,592,332	6,592,332	5,888,467	5,888,467	5,888,467	5,888,467	20,428,651	43,982,519
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander 522 Serie-M	Chile	UF	4,82%	4,75%	Semestral	No	—	26,267,670	26,267,670	25,736,309	25,736,309	25,736,309	25,736,309	127,107,303	230,052,539
76.536.353-5	Enel Chile S.A.	Chile	Foreign	BNY Mellon - Unica	E.E.U.U	US$	5,24%	4,88%	Upon expiration	No	—	1,926,446	1,926,446	—	—	—	—	731,202,011	731,202,011
										Total Unsecured Bonds	7,700,030	37,615,021	45,315,051	31,624,776	31,624,776	31,624,776	328,045,479	1,109,055,045	1,531,974,852

20.3 Secured liabilities

As of December 31, 2020 and 2019, there were no secured bonds.

Fair value measurement and hierarchy

The fair value of the current and non-current secured and unsecured liabilities as of December 31, 2020 ThCh$1,866,198,159 (ThCh$1,941,481,412 as of December 31, 2019). These liabilities has been categorized as Level 2 (See Note 3.h). It is important to note that these financial liabilities are measured at amortized cost (See Note 3.g.4).

20.4 Hedged debt

The debt denominated in U.S. dollars for ThCh$1,931,705,893 held by the Group as of December 31, 2020, is related to future cash flow hedges for the Group’s U.S. dollar-linked operating revenues (ThCh$1,585,140,233 as of December 31, 2019) (see Note 3.g.5).

F-95

The following table details changes in “Reserve for cash flow hedges” as of December 31, 2020, 2019 and 2018, due to exchange differences from this debt:

	For the years ended December 31,
	2020	2019	2018
	ThCh$	ThCh$	ThCh$
Balance in hedging reserves (hedging income) at the beginning of the period, net	(189,813,409)	(127,508,852)	(27,168,007)
Exchange differences recorded in shareholders' equity, net	98,288,849	(77,347,380)	(101,790,308)
Exchange differences charged to income, net	31,178,897	15,042,823	12,478,369
Other (OPA 33.57% 02.04.2018 on Enel Generación Chile)	—	—	(11,028,906)
Balance in hedging reserves (hedging income) at the end of the period, net	(60,345,663)	(189,813,409)	(127,508,852)

20.5 Other information

As of December 31, 2020, the Group has unconditional long-term lines of credit for ThCh$140,143,000 (ThCh$146,268,500  as of December 31, 2019) at its disposal.

20.6 Future Undiscounted debt flows.

The following tables are the estimates of undiscounted flows by type of financial debt:

a) Summary of secured and unsecured bank borrowings

			Current			Non-Current					Current			Non-Current
			Maturity		Current	Maturity				Total Non-Current	Maturity		Current	Maturity				Total Non-Current
Country	Currency	Nominal Interest Rate	One to Three Months	Three to twelve months	as of 12-31-2020	One to two years	Two to Three Years	Three to four years	More than five years	as of 12-31-2020	One to Three Months	Three to twelve months	as of 12-31-2020	One to two years	Two to Three Years	Three to four years	More than five years	as of 12-31-2020
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$			ThCh$
Chile	US$	1.77%	845,182	109,110,564	109,955,746	21,608,084	-	-	-	21,608,084	2,542,588	120,375,278	122,917,866	118,121,339	22,859,559	-	-	140,980,898
Chile	CLP	6.00%	4	-	4	-	-	-	-	-	5	-	5	-	-	-	-	-
Totals			845,186	109,110,564	109,955,750	21,608,084	-	-	-	21,608,084	2,542,593	120,375,278	122,917,871	118,121,339	22,859,559	-	-	140,980,898

b) Summary of Guaranteed and Unsecured bonds

						Non-Current						Current			Non-Current
			Maturity		Total Current	Maturity					Total Non-Current	Maturity		Total Current	Maturity					Total Non-Current
Country	Currency	Nominal Interest Rate	One to Three Months	Three to twelve months	as of 12-31-2020	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2020	One to Three Months	Three to twelve months	as of 12-31-2019	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2019
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.49%	16,734,114	50,202,339	66,936,453	66,936,453	66,936,453	342,771,185	54,388,490	1,256,555,902	1,787,588,483	17,750,370	53,251,108	71,001,478	71,001,479	71,001,479	71,001,479	362,787,755	1,387,871,953	1,963,664,145
Chile	U.F.	5.48%	3,570,187	42,691,404	46,261,591	44,640,241	43,018,892	41,397,542	39,776,193	138,302,651	307,135,519	6,136,022	49,438,671	55,574,693	53,077,463	50,580,233	48,083,003	45,585,772	186,005,287	383,331,758
Totals			20,304,301	92,893,743	113,198,044	111,576,694	109,955,345	384,168,727	94,164,683	1,394,858,553	2,094,724,002	23,886,392	102,689,779	126,576,171	124,078,942	121,581,712	119,084,482	408,373,527	1,573,877,240	2,346,995,903

-

F-96

21.  LEASE LIABILITIES

As of December 31, 2020 and 2019, the balance of lease liabilities is as follows:

	12-31-2020		12-31-2019
Lease liability	Current	Non-Current	Current	Non-Current
Lease liability	7,007,711	44,857,807	5,842,015	47,565,674
Total	7,007,711	44,857,807	5,842,015	47,565,674

21.1. Individualization of Lease Liabilities

									December 31, 2020									December 31, 2019
									Current			Non-Current ThCh$
Taxpayer ID Number	Company	Country	Taxpayer ID Number	Company	Country	Currency	Effective Interest Rate	Maturity	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Total Non- Current	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Total Non- Current
91.081.000-6	Enel Generación Chile S.A.	Chile	76.555.400-4	Transelec S.A	Chile	US$	6,50%	Monthly	613,801	1,900,462	2,514,263	2,677,690	5,044,096	—	—	—	7,721,786	606,973	1,879,324	2,486,297	2,647,907	2,820,020	5,312,211	—	—	10,780,138
91.081.000-6	Enel Generación Chile S.A.	Chile	10.579.624-2	Marcelo Alberto Amar Basulto	Chile	UF	2,06%	Monthly	4,631	13,872	18,503	18,828	19,215	19,610	20,014	193,632	271,299	4,067	13,237	17,304	17,966	18,335	18,713	19,097	208,057	282,168
91.081.000-6	Enel Generación Chile S.A.	Chile	91.004.000-6	Productos Fernandez S.A.	Chile	UF	2,09%	Monthly	13,012	26,063	39,075	35,386	36,127	36,882	37,654	384,022	530,071	12,399	24,861	37,260	33,755	34,460	35,182	35,917	410,646	549,960
91.081.000-6	Enel Generación Chile S.A.	Chile	61.216.000-7	Empresa de Ferrocarriles del Estado	Chile	UF	1,07%	Biannual	1,163	578	1,741	—	—	—	—	—	—	1,104	557	1,661	1,123	—	—	—	—	1,123
91.081.000-6	Enel Generación Chile S.A.	Chile	78.392.580-K	Agricola el Bagual LTDA.	Chile	UF	1,91%	Annual	1,205	—	1,205	588	597	—	—	—	1,185	1,152	—	1,152	564	573	581	—	—	1,718
91.081.000-6	Enel Generación Chile S.A.	Chile	99.527.200-8	Rentaequipos Tramaca S.A.	Chile	UF	0,83%	Monthly	144,460	—	144,460	—	—	—	—	—	—	144,436	—	144,436	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	96.565.580-8	Compañía de Leasing Tattersall S A.	Chile	UF	0,83%	Monthly	9,546	—	9,546	—	—	—	—	—	—	6,607	—	6,607	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	8.992.234-8	Roberto Guzman Borquez	Chile	CLP	1,37%	Monthly	367	1,099	1,466	1,483	1,377	—	—	—	2,860	—	—	—	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	19.048.130-1	Yaritza Alexandra Bernal	Chile	UF	1,37%	Monthly	379	1,140	1,519	1,538	1,431	—	—	—	2,969	—	—	—	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	71.024.400-6	Corporación Comunidades V.	Chile	CLP	1,07%	Monthly	1,034	3,005	4,039	—	—	—	—	—	—	—	—	—	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.643.660-3	INMOBILIARIA EL ROBLE S.A.	Chile	UF	1,41%	Monthly	19,023	38,171	57,194	—	—	—	—	—	—	12,589	41,263	53,852	48,574	—	—	—	—	48,574
96.800.570-7	Enel Distribución Chile S.A.	Chile	2.859.481-K	NURIA FERRER PARES	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	2.478.836-9	JUANA FERRER PARES	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	3.800.735-1	CARMEN ELVIRA ECHAVARRY DE LA SIERRA	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	5.742.701-9	JORGE FERRER PARES	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	5.120.460-3	CARMEN FERRER PARES	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	70.015.730-K	MUTUAL DE SEGUROS DE CHILE	Chile	UF	1,91%	Monthly	21,619	47,378	68,997	64,225	65,453	66,704	67,977	57,639	321,998	13,990	45,274	59,264	61,373	62,545	63,741	64,959	111,258	363,876
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.596.523-3	CAPITAL INVESTI	Chile	UF	1,91%	Monthly	17,765	38,732	56,497	52,505	53,508	54,530	55,571	47,121	263,235	11,479	37,011	48,490	50,173	51,131	52,108	53,104	90,955	297,471
96.800.570-7	Enel Distribución Chile S.A.	Chile	77.651.230-3	INVERSIONES TAPIHUE LTDA	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	10,501	—	10,501	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.253.641-2	BCYCLE LATAM S.P.A	Chile	CLP	6,24%	Annual	60,000	—	60,000	16,679	17,719	18,825	—	—	53,223	—	20,000	20,000	15,699	16,679	17,719	18,825	—	68,922
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.203.089-6	RENTAS INMOBILIARIAS AMANECER S.A.	Chile	UF	1,56%	Monthly	4,563	39,724	44,287	17,803	—	—	—	—	17,803	12,239	24,679	36,918	51,480	14,593	—	—	—	66,073
96.800.570-7	Enel Distribución Chile S.A.	Chile	61.219.000-3	EMPRESA DE TRANSPORTE DE PASAJEROS METRO S.A	Chile	US$	5,99%	Annual	—	327,074	327,074	111,940	118,640	125,742	133,269	1,249,650	1,739,241	—	350,227	350,227	114,222	120,634	130,857	132,426	1,476,550	1,974,689
96.800.570-7	Enel Distribución Chile S.A.	Chile	85.208.700-5	RENTAEQUIPOS LEASING S.A.	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	774	—	774	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	COMPAÑIA DE LEASING TATTERSALL S A.	Chile	UF	1,41%	Monthly	6,122	3,174	9,296	—	—	—	—	—	—	1,628	5,363	6,991	4,544	—	—	—	—	4,544
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.013.489-9	INVERSIONES DON ISSA LTDA	Chile	UF	1,67%	Monthly	23,746	54,777	78,523	73,305	30,904	—	—	—	104,209	16,118	51,903	68,021	70,215	71,388	24,186	—	—	165,789

F-97

96.800.570-7	Enel Distribución Chile S.A.	Chile	76.164.095-K	INMOBILARIA MIXTO RENTA SpA	Chile	UF	1,07%	Monthly	—	—	—	—	—	—	—	—	—	16,530	—	16,530	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	COMPAÑIA DE LEASING TATTERSALL S A.	Chile	UF	1,41%	Monthly	2,735	—	2,735	—	—	—	—	—	—	278	3,392	3,670	652	—	—	—	—	652
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	COMPAÑIA DE LEASING TATTERSALL S A.	Chile	UF	1,41%	Monthly	3,734	1,864	5,598	—	—	—	—	—	—	988	3,231	4,219	2,736	—	—	—	—	2,736
96.800.570-7	Enel Distribución Chile S.A.	Chile	99.530.420-1	INMOBILIARIA NIALEM SA	Chile	UF	0,40%	Monthly	42,897	128,922	171,819	172,496	173,183	173,873	43,576	—	563,128	—	—	—	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.164.095-K	INMOBILIARIA MIXTO RENTA SPA	Chile	UF	0,10%	Monthly	27,018	81,066	108,084	9,011	—	—	—	—	9,011	—	—	—	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	COMPAÑIA DE LEASING TATTERSALL S A.	Chile	UF	0,10%	Monthly	178,447	267,473	445,920	356,941	29,760	—	—	—	386,701	—	—	—	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.013.489-9	INVERSIONES DON ISSA LTDA	Chile	UF	1,87%	Monthly	17,661	51,992	69,653	70,469	71,799	73,155	30,888	—	246,311	—	—	—	—	—	—	—	—	—
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	35,148	35,148	28,589	29,315	30,060	30,824	710,142	828,930	—	36,519	36,519	27,274	27,967	28,677	29,406	723,912	837,236
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	25,341	25,341	20,609	21,133	21,670	22,220	511,934	597,566	—	26,329	26,329	19,661	20,161	20,673	21,198	521,858	603,551
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	29,576	29,576	24,055	24,666	25,293	25,936	597,533	697,483	—	30,727	30,727	22,949	23,532	24,130	24,743	609,121	704,475
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	26,576	26,576	21,613	22,162	22,725	23,303	536,865	626,668	—	27,615	27,615	20,619	21,143	21,680	22,231	547,270	632,943
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	3,334	3,334	2,524	2,591	2,659	2,729	86,937	97,440	—	3,738	3,738	2,793	2,864	2,937	3,011	74,129	85,734
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	47,443	47,443	43,329	44,481	45,664	46,879	1,249,297	1,429,650	—	47,317	47,317	44,688	45,824	46,988	48,182	1,190,338	1,376,020
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	31,209	—	31,209	19,136	19,622	20,121	20,632	508,573	588,084	31,087	—	31,087	18,256	18,720	19,195	19,683	517,037	592,891
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	28,607	—	28,607	16,343	16,772	17,213	17,665	530,780	598,773	29,105	—	29,105	17,619	18,066	18,525	18,996	467,606	540,812
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	634	—	634	401	412	422	433	9,973	11,641	628	—	628	383	393	403	413	10,169	11,761
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	1,982	1,982	716	734	753	772	19,605	22,580	—	1,331	1,331	683	700	718	736	20,591	23,428
76.412.562-2	Enel Green Power Chile S.A.	Chile	76.400.311-K	Fundo Los Buenos Aires SpA	Chile	UF	2,54%	Annual	109,911	—	109,911	70,851	72,651	74,497	76,389	1,408,792	1,703,180	—	111,365	111,365	67,592	69,309	71,070	72,876	1,450,422	1,731,269
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.131-K	Federico Rioseco Garcia	Chile	UF	4,94%	Annual	33,580	—	33,580	3,163	3,320	3,484	3,656	98,672	112,295	7,914	—	7,914	2,949	3,095	3,248	3,408	99,995	112,695
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.132-8	Juan Rioseco Garcia	Chile	UF	4,94%	Annual	38,089	—	38,089	6,968	7,313	7,674	8,054	188,256	218,265	15,877	—	15,877	6,496	6,817	7,154	7,507	185,500	213,474
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.132-8	Juan Rioseco Garcia	Chile	UF	4,94%	Annual	13,834	—	13,834	1,582	1,660	1,742	1,828	49,336	56,148	3,961	—	3,961	1,474	1,547	1,624	1,704	49,994	56,343
76.412.562-2	Enel Green Power Chile S.A.	Chile	4.595.479-K	Adriana Castro Parra	Chile	UF	4,94%	Annual	33,522	—	33,522	13,937	14,626	15,349	16,108	363,230	423,250	31,828	—	31,828	12,991	13,633	14,307	15,015	370,630	426,576
76.412.562-2	Enel Green Power Chile S.A.	Chile	7.256.021-3	Alicia Freire Hermosilla	Chile	UF	4,31%	Annual	97,512	—	97,512	—	—	—	—	—	—	93,160	—	93,160	88,809	—	—	—	—	88,809
76.412.562-2	Enel Green Power Chile S.A.	Chile	77.378.630-5	Agricola Santa Amalia	Chile	UF	4,94%	Annual	22,346	—	22,346	13,937	14,626	15,349	16,108	363,230	423,250	31,828	—	31,828	12,991	13,633	14,307	15,015	370,631	426,577
76.412.562-2	Enel Green Power Chile S.A.	Chile	77.894.990-3	Orafti Chile S.A.	Chile	UF	4,94%	Annual	8,966	—	8,966	6,640	6,968	7,313	7,674	183,027	211,622	15,918	—	15,918	6,190	6,496	6,817	7,154	192,635	219,292
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	4,87%	Annual	250,048	—	250,048	243,730	255,590	268,028	281,070	4,158,235	5,206,653	—	472,736	472,736	227,365	238,428	250,031	262,197	4,335,384	5,313,405
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	4,94%	Annual	13,703	—	13,703	14,008	14,701	15,428	16,190	513,821	574,148	41,389	—	41,389	13,058	13,704	14,381	15,092	520,042	576,277
76.412.562-2	Enel Green Power Chile S.A.	Chile	78.201.750-0	Sociedad Agricola Parant	Chile	UF	4,94%	Annual	19,817	—	19,817	2,297	2,411	2,530	2,655	67,813	77,706	5,605	—	5,605	2,141	2,247	2,359	2,475	66,716	75,938
76.412.562-2	Enel Green Power Chile S.A.	Chile	78.201.750-0	Sociedad Agricola Parant	Chile	UF	4,94%	Annual	46,780	—	46,780	39,840	41,810	43,877	46,046	1,138,013	1,309,586	95,241	—	95,241	37,137	38,973	40,900	42,922	1,156,961	1,316,893
76.412.562-2	Enel Green Power Chile S.A.	Chile	3.750.131-K	Federico Rioseco Garcia	Chile	UF	4,94%	Annual	233,017	—	233,017	3,320	3,484	3,656	3,837	94,835	109,132	7,935	—	7,935	3,095	3,248	3,408	3,577	96,415	109,743
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	70,834	—	70,834	45,685	46,846	48,036	49,256	1,134,814	1,324,637	76,055	—	76,055	43,584	44,691	45,827	46,991	1,156,664	1,337,757
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	91,996	91,996	44,907	46,048	47,218	48,418	1,039,441	1,226,032	—	117,630	117,630	42,842	43,930	45,047	46,191	1,066,692	1,244,702
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	71,401	—	71,401	17,423	17,866	18,320	18,785	463,049	535,443	29,696	—	29,696	16,622	17,044	17,477	17,921	439,871	508,935
76.412.562-2	Enel Green Power Chile S.A.	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	43,930	43,930	20,454	20,973	21,506	22,052	508,069	593,054	—	29,189	29,189	19,513	20,009	20,517	21,038	548,843	629,920
76.126.507-5	Parque Eólico Talinay Oriente S.A.	Chile	76.248.317-3	Agricola Alto Talinay	Chile	EUR	4,61%	Annual	374,657	—	374,657	218,600	228,677	239,219	250,247	2,840,625	3,777,368	—	367,982	367,982	201,806	211,109	220,842	231,022	2,951,326	3,816,105
76.321.458-3	Almeyda Solar SPA	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	EUR	5,02%	Annual	—	596,278	596,278	181,888	191,016	200,603	210,671	2,441,450	3,225,628	—	260,072	260,072	167,261	175,655	184,471	193,729	2,532,578	3,253,694
76.321.458-3	Almeyda Solar SPA	Chile	76.259.106-5	Inmobiliaria Terra Australis Tres S.A.	Chile	UF	6,39%	Biannual	32,757	19,025	51,782	39,084	40,507	41,981	43,509	1,177,273	1,342,354	—	46,597	46,597	54,543	55,929	57,350	58,807	1,012,677	1,239,306
76.321.458-3	Almeyda Solar SPA	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	6,39%	Annual	—	99,022	99,022	74,302	76,190	78,126	80,111	1,845,677	2,154,406	—	98,189	98,189	70,885	72,686	74,533	76,427	1,881,835	2,176,366
76.321.458-3	Almeyda Solar SPA	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,23%	Annual	47,369	—	47,369	39,288	40,165	41,061	41,978	224,377	386,869	48,681	—	48,681	37,594	38,433	39,291	40,168	258,481	413,967
76.321.458-3	Almeyda Solar SPA	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,36%	Annual	32,932	—	32,932	23,945	24,511	25,090	25,683	292,688	391,917	32,269	—	32,269	22,884	23,424	23,978	24,545	311,762	406,593
76.321.458-3	Almeyda Solar SPA	Chile	79.938.160-5	Soc. Serv. Com.. Multiservice F.L.	Chile	UF	2,94%	Annual	—	101,743	101,743	36,866	37,949	39,065	40,213	963,970	1,118,063	—	35,334	35,334	35,034	36,064	37,124	38,215	981,212	1,127,649

F-98

76.321.458-3	Almeyda Solar SPA	Chile	61.402.000-8	Ministerio de Bienes Nacionales	Chile	UF	2,54%	Annual	—	26,523	26,523	10,430	11,006	11,613	12,254	571,751	617,054	—	34,408	34,408	25,058	25,694	26,347	27,017	621,989	726,105
76.536.353-5	Enel Chile S.A.	Chile	96.565.580-8	COMPAÑIA DE LEASING TATTERSALL S A.	Chile	UF	0,10%	Monthly	2,710	4,065	6,775	5,426	476	—	—	—	5,902	—	—	—	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	78.822.300-5	Inversiones Cardinal S.A	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	9,281	24,801	34,082	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	78.822.300-5	Inversiones Cardinal S.A	Chile	UF	1,20%	Monthly	—	—	—	—	—	—	—	—	—	9,714	19,465	29,179	—	—	—	—	—	—
							Total Leasing		2,829,163	4,178,548	7,007,711	5,036,773	7,067,087	2,026,666	1,903,134	28,824,147	44,857,807	1,512,244	4,329,771	5,842,015	4,515,822	4,565,526	7,061,634	1,783,940	29,638,752	47,565,674

21.2. Undiscounted debt cash flows.

Undiscounted debt cash flows are detailed as follows:

						Non-Current						Current			Non-Current
			Maturity		Total Current	Maturity					Total Non-Current	Maturity		Total Current	Maturity					Total Non-Current
Country	Currency	Nominal Interest Rate	One to Three Months	Three to twelve months	as of 12-31-2020	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2020	One to Three Months	Three to twelve months	as of 12-31-2019	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2019
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.25%	805,609	2,544,526	3,350,135	3,343,654	5,400,991	227,6 22	219,295	1,598,935	10,790,497	859,011	2,802,479	3,661,490	3,570,048	3,554,711	5,731,772	258,317	2,063,704	15,178,552
Chile	EUR	4.82%	427,451	-	427,451	582,405	563,152	543,900	524,648	2,334,458	4,548,563	80,971	240,372	321,343	499,678	485,713	471,749	457,785	2,453,454	4,368,379
Chile	UF	2.74%	2,058,130	2,175,978	4,234,108	3,289,984	2,954,856	2,808,037	2,598,818	30,660,789	42,312,484	821,084	2,293,383	3,114,467	2,895,029	2,523,717	2,462,599	2,412,029	30,885,469	41,178,843
Chile	Ch$	2.89%	24,156	-	24,156	20,234	19,173	18,112	-	-	57,519	1,180	23,113	24,293	17,847	16,967	16,087	15,207	-	66,108
Totals			3,315,346	4,720,504	8,035,850	7,236,277	8,938,172	3,597,671	3,342,761	34,594,182	57,709,063	1,762,246	5,359,347	7,121,593	6,982,602	6,581,108	8,682,207	3,143,338	35,402,627	60,791,882

F-99

22.  RISK MANAGEMENT POLICY

The Group companies follow the guidelines of the Risk Management Control System (SCGR) defined at  the parent level (Enel SpA), which establishes rules for managing risks through the respective standards, procedures, systems, etc., applicable to the different levels of the Group companies, in the ongoing business risk identification, analysis, evaluation, treatment, and communication processes. These are approved by the Enel SpA Board of Directors, which includes a Risk and Controls Committee responsible for supporting the Enel Chile Board’s evaluation and decisions regarding internal control and risk management system, as well as those related to the approval of periodic financial statements.

To comply with this, each company has its own specific Control Management and Risk Management policy, which is reviewed and approved at the beginning of each year by the Enel Chile Board of Directors, observing and applying all local requirements in terms of the risk culture.

The Company seeks protection against all risks that could affect the achievement of the business objectives. In January 2020, a new risk taxonomy has been approved for the Enel Group, which considers 6 macro-categories and 37 sub-categories.

The Enel Group risk management system considers three lines of action (defense) to obtain effective and efficient risk management and controls. Each of these three “lines” plays a different role within the organization's broader governance structure (Business and Internal Control areas acting as the first line, Risk Control as the second line, and Internal Audit as the third line of defense). Each line of defense has the obligation to report to and keep upper Management and the Directors up-to-date on risk management. In this sense, the first and second lines of defense report to upper Management, and the second and third lines report to the Board of Directors.

Within each of the Group's companies, the risk management is decentralized. Each manager responsible for the operating process in which the risk arises is also responsible for treating the risk and adopting risk control and mitigation measures.

22.1 Interest rate risk

Changes in interest rates affect the fair value of assets and liabilities bearing fixed interest rates, as well as, the expected future cash flows of assets and liabilities subject to floating interest rates.

The objective of managing interest rate risk exposure is to achieve a balance in the debt structure to minimize the cost of debt with reduced volatility in profit or loss.

The comparative structure of the Group's financial debt, according to the fixed and/or protected interest rate on gross debt, after the contracted derivatives, is the following:

	For the years ended December 31,
	2020	2019
	%	%
Fixed interest rate	99%	98%

Depending on the Group's estimates and the objectives of the debt structure, hedging transactions are conducted by entering into derivative contracts to mitigate these risks.

Risk control through specific processes and indicators allows companies to limit possible adverse financial impacts and, at the same time, optimize the debt structure with an adequate degree of flexibility. In this sense, the volatility that characterized the financial markets during the first phase of the pandemic, in many cases went back to pre-COVID-19 levels and was offset by effective risk mitigation actions using derivative financial instruments.

22.2 Exchange rate risk

Exchange rate risks involve basically the following transactions:

- Debt taken on by the Group’s companies that is denominated in a currency other than the currency in which its cash flows are indexed.

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- Payments to be made in a currency other than that in which its cash flows are indexed for the acquisition of project-related materials and for corporate insurance policies.

- Income in Group companies directly linked to changes in currencies other than the currency of its cash flows.

In order to mitigate foreign currency risk, the Group seeks to maintain a balance between flows indexed to US$ or local currencies, if any, and the levels of assets and liabilities denominated in such currencies. The objective is to minimize the exposure to variability in cash flows that are attributable to foreign exchange risk.

The hedging instruments currently being used to comply with the policy are currency swaps and forward exchange contracts.

During the last quarter of 2020, exchange rate risk management continued in the context of complying with the previously mentioned risk management policy, without difficulty to access the derivatives market. It should be noted that the volatility that characterized the financial markets during the first phase of the pandemic, in many cases went back to pre-COVID-19 levels and was offset by risk mitigation actions through derivative financial instruments.

22.3 Commodities risk

The Group has a risk exposure to price fluctuations in certain commodities, basically due to:

- Purchases of fuel used to generate electricity.

- Energy purchase/sale transactions that take place in local markets.

To reduce the risk in situations of extreme drought, the Group has designed a commercial policy that defines the levels of sales commitments in line with the capacity of its generating power plants in a dry year. It also includes risk mitigation terms in certain contracts with unregulated customers and with regulated customers subject to long-term tender processes, establishing indexation polynomials that allow for reducing commodities exposure risk.

Considering the operating conditions faced by the power generation market, with drought and highly volatile commodity prices on international markets, the Company is constantly evaluating the use of hedging to minimize the impacts that these price fluctuations have on its results.

As of December 31, 2020, there were current transactions for 1,782 kBbl from Brent to be settled in 2021 and 16.8 Tbtu from Henry Hub to be settled in 2021.

As of December 31, 2019, there were current transactions for 1,412 kTon from API2 to be settled in 2020,  1,059 kBbl from Brent to be settled in 2020, and 4.79 TBtu from HH to be settled in 2020.

Depending on the Group’s permanently updated operating conditions, these hedges may be modified, or include other commodities.

Thanks to the mitigation strategies implemented, the Group was able to minimize the effects of basic product price volatility on the results of the fourth quarter of 2020.

22.4 Liquidity risk

The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets.

The projected needs mentioned above include maturities of financial debt net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial derivatives (see Notes 20 and 23).

As of December 31, 2020, the Group recorded liquidity in the amount of ThCh$ 332,036,013 in cash and cash equivalents and ThCh$140,643,000 in unconditionally available long-term lines of credit. As of December 31,

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2019, the Group recorded liquidity of ThCh$235,684,500 in cash and cash equivalents and ThCh$146,268,500 in unconditionally available long-term lines of credit.

22.5 Credit risk

The Group closely monitors its credit risk.

Trade receivables:

The credit risk for receivables from the Group’s commercial activity has historically been very low, due to the short-term period of collections from customers, resulting in non-significant cumulative receivables amounts. This situation applies to the electricity generating and distribution lines of business.

In the Company’s electricity generating business, regulations allow disconnecting the energy service to customers in payment default, and most contracts have termination clauses for payment default. The Company monitors its credit risk on an ongoing basis and measures quantitatively its maximum exposure to payment default risk, which, as stated above, is very low.

In the Company’s electricity distribution company, the disconnection of energy service to customers in payment default is applied in accordance with current regulations. This improves the ease of the process for evaluating and controlling credit risk, which is also limited. However, the action to disconnect energy service to customers recording payment default was suspended  by Enel Distribución Chile from March 2020 to support its most vulnerable customers, and subsequently, to comply with Law No. 21,249 and Law No. 21,301 which were enacted in August 2020 and December 2020, respectively, and will remain in force until May 2021 (see Note 4.b.iv).

Regarding the impact of COVID-19, the results of specific internal analyses did not reveal significant statistical correlations between the main economic indicators (GDP, unemployment rate, etc.) and solvency. However, impairment losses have increased in 2020 as a consequence of an increase in expected credit losses from counterparties (see Notes 3.g.3 and 9.d).

Financial assets:

Cash surpluses are invested in the highest-rated local and foreign financial entities (with risk rating equivalent to investment grade where possible) with thresholds established for each entity.

Banks that have received investment grade ratings from the three major international rating agencies (Moody’s, S&P, and Fitch) are selected for making investments.

Investments may be supported through Chilean treasury bonds and/or commercial paper issued by the highest rated banks; the latter are preferable as they offer higher returns (always in line with current investment policies).

It is noted that the downturn in the macroeconomic scenario due to COVID-19 had no significant impact on counterparties’ credit quality.

22.6 Risk measurement

The Group measures the Value at Risk (VaR) of its debt positions and financial derivatives, in order to monitor the risk assumed by the company, thereby reducing volatility in the income statement. The portfolio of positions included for purposes of calculating the present VAR include:

- Financial debt.

- Hedge derivatives for debt.

The VaR determined represents the potential variation in value of the portfolio of positions described above in a quarter with a 95% confidence level. To determine the VaR, we take into account the volatility of the risk variables affecting the value of the portfolio of positions, including:

- U.S. dollar LIBOR interest rate.

- The exchange rates of the various currencies used in the calculation.

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The calculation of VaR is based on generating possible future scenarios (at one quarter) of market values of the risk variables based on scenarios based on real observations for the same period (at one quarter) during five years.

The quarter 95% confidence VaR number is calculated as the 5% percentile most adverse of the quarterly possible fluctuations.

Taking into consideration the assumptions previously described, the quarter VaR of the previously discussed positions was ThCh$308,778,352.

This value represents the potential increase of the Debt and Derivatives’ Portfolio, thus these VaR are inherently related, among other factors, to the Portfolio’s value at each quarter end.

23.  FINANCIAL INSTRUMENTS

23.1 Financial instruments classified by type and category

a) The detail of financial assets, classified by type and category, as of December 31, 2020 and 2019 is as follows:

		12-31-2020
	Financial assets at fair value with changes in results	Financial assets measured at amortized cost	Financial assets at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Equity instruments	—	—	127,854	—
Trade and other accounts receivable	—	592,856,895	—	—
Derivative instruments	3,033,502	—	18,387,261	1,000,964
Other financial assets	—	808,692	—	—
Total Current	3,033,502	593,665,587	18,515,115	1,000,964
Equity instruments	—	—	2,326,480	—
Trade and other accounts receivable	—	493,375,481	—	—
Derivative instruments	1,911,233	—	—	16,422,737
Other financial assets	—	—	—	—
Total Non-current	1,911,233	493,375,481	2,326,480	16,422,737
Total	4,944,735	1,087,041,068	20,841,595	17,423,701
		12-31-2019
	Financial assets at fair value with changes in results	Financial assets measured at amortized cost	Financial assets at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Equity instruments	—	—	127,854	—
Trade and other accounts receivable	—	576,740,203	—	—
Derivative instruments	1,618,318	—	1,323,556	277,702
Other financial assets	—	860,425	—	—
Total Current	1,618,318	577,600,628	1,451,410	277,702
Equity instruments	—	—	2,349,221	—
Trade and other accounts receivable	—	347,981,527	—	—
Derivative instruments	—	—	—	4,871,397
Other financial assets	—	2	—	—
Total Non-current	—	347,981,529	2,349,221	4,871,397
Total	1,618,318	925,582,157	3,800,631	5,149,099

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The carrying amount of trade accounts receivable and payable approximates their fair value.

b) The detail of financial liabilities, classified by type and category, as of December 31, 2020 and 2019 is as follows:

	12-31-2020
	Financial liabilities at fair value with changes in results	Financial liabilities measured at amortized cost	Financial liabilities at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing loans	—	152,076,992	—	—
Trade and other accounts payable	—	757,965,390	—	—
Derivative instruments	4,841,020	—	45,543	581,129
Other financial liabilities	—	7,007,711	—	—
Total Current	4,841,020	917,050,093	45,543	581,129
Interest-bearing loans	—	1,467,421,655	—	—
Trade and other accounts payable	—	1,281,254,521	—	—
Derivative instruments	—	—	—	16,167,471
Other financial liabilities	—	44,857,807	—	—
Total Non-current	—	2,793,533,983	—	16,167,471
Total	4,841,020	3,710,584,076	45,543	16,748,600
	12-31-2019
	Financial liabilities at fair value with changes in results	Financial liabilities measured at amortized cost	Financial liabilities at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing loans	—	164,404,334	—	—
Trade and other accounts payable	—	750,103,757	—	—
Derivative instruments	2,026,476	—	8,924,831	48,225,766
Other financial liabilities	—	—	—	—
Total Current	2,026,476	914,508,091	8,924,831	48,225,766
Interest-bearing loans	—	1,714,837,545	—	—
Trade and other accounts payable	—	840,623,569	—	—
Other financial liabilities	124,048	—	—	25,208,326
Total Non-current	124,048	2,555,461,114	—	25,208,326
Total	2,150,524	3,469,969,205	8,924,831	73,434,092

23.2        Derivative instruments

The risk management policy of the Group uses primarily interest rate and foreign exchange rate derivatives to hedge its exposure to interest rate and foreign currency risks.

The Company classifies its hedges as follows:

- Cash flow hedges: Those that hedge the cash flows of the underlying hedged item.

- Fair value hedges: Those that hedge the fair value of the underlying hedged item.

- Non-hedge derivatives: Financial derivatives that do not meet the requirements established by IFRS to be designated as hedging instruments are recognized at fair value through profit or loss (financial assets held for trading).

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a) Assets and liabilities for hedge derivative instruments

As of December 31, 2020 and 2019, financial derivative qualifying as hedging instruments resulted in recognition of the following assets and liabilities in the statement of financial position:

	12-31-2020
	Assets		Liabilities
	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	—	—	1,947,377	12,944,130
Cash flow hedge	—	—	1,947,377	12,944,130
Exchange rate hedge:	1,000,964	16,422,737	3,451,487	3,223,341
Cash flow hedge	1,000,964	16,422,737	3,451,487	3,223,341
Total	1,000,964	16,422,737	5,398,864	16,167,471
	12-31-2019
	Assets		Liabilities
	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	322,316	8,447	—	7,743,401
Cash flow hedge	322,316	8,447	—	7,743,401
Exchange rate hedge:	—	4,862,950	48,225,766	17,464,925
Cash flow hedge	—	4,862,950	48,225,766	17,464,925
Total	322,316	4,871,397	48,225,766	25,208,326

- General information Related to Hedging Derivative Instruments

Hedging derivative instruments and their corresponding hedged instruments are shown in the following table:

			Fair value of	Fair value of
Type of	Description	Description	hedged item	hedged item	Type
hedge	of hedged	of hedged	12-31-2020	12-31-2019	of
instrument	risk	item	ThCh$	ThCh$	risk hedged
SWAP	Interest rate	Others	—	(699,158)	Cash flow
SWAP	Exchange rate	Unsecured obligations (bonds)	12,763,777	(9,530,240)	Cash flow
SWAP	Interest rate	Loans with Related Companies	(12,944,129)	(6,991,184)	Cash flow
SWAP	Interest rate	Bank loans	(1,947,377)	277,703	Cash flow
FORWARD	Exchange rate	Operational Income	(1,967,328)	(51,297,500)	Cash flow
FORWARD	Interest rate	Others	(77,558)	—	Cash flow
FORWARD	Exchange rate	Other	29,981	—	Cash flow

As of December 31, 2020, and 2019, the Group has not recognized significant gains or losses for ineffective cash flow hedges.

At the reporting date, the Group did not establish fair value hedging relationships.

b) Financial derivative instruments assets and liabilities at fair value through profit or loss

As of December 31, 2020 and 2019, financial derivative transactions recognized at fair value through profit or loss, resulted in the recognition of the following liabilities in the statement of financial position:

	12-31-2020				12-31-2019
	Current Assets	Current Liabilities	Non-Current Assets	Non-Current Liabilities	Current Assets	Current Liabilities	Non-Current Assets	Non-Current Liabilities
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Non-hedging derivative instrument	1,414,895	23,285	1,911,233	—	—	2,026,476	—	124,048
Total	1,414,895	23,285	1,911,233	—	—	2,026,476	—	124,048

These derivative instruments correspond to forward contracts entered into by the Group, whose purpose is to hedge the exchange rate risk related to future obligations arising from civil works contracts linked to the

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construction of the Los Cóndores Plant. Although these hedges have an economic substance, they do not qualify for hedge accounting because they do not strictly comply with the hedge accounting requirements established in IFRS 9 Financial Instruments.

c) Other information on derivatives:

The following table sets forth the fair value of hedging and non-hedging derivatives entered into by the Group as well as the remaining contractual maturities as of December 31, 2020 and 2019.

	12-31-2020
		Notional Amount
	Fair value	Less than 1 year	1-2 years	2-3 years	3-4 years	4-5 years	Total
Financial derivatives	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	(14,891,507)	106,642,500	284,380,000	—	—	—	391,022,500
Cash flow hedge	(14,891,507)	106,642,500	284,380,000	—	—	—	391,022,500
Exchange rate hedge:	10,748,873	143,449,971	3,390	—	504,391,045	95,129,590	742,973,996
Cash flow hedge	10,748,873	143,449,971	3,390	—	504,391,045	95,129,590	742,973,996
Derivatives not designated for hedge accounting	3,302,843	30,063,763	21,189,518	8,742,828	285,368	—	60,281,477
Total	(839,791)	280,156,234	305,572,908	8,742,828	504,676,413	95,129,590	1,194,277,973
	12-31-2019
		Notional Amount
	Fair value	Less than 1 year	1-2 years	2-3 years	3-4 years	4-5 years	Total
Financial derivatives	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	(7,412,638)	112,311,000	112,311,000	299,496,000	—	—	524,118,000
Cash flow hedge	(7,412,638)	112,311,000	112,311,000	299,496,000	—	—	524,118,000
Exchange rate hedge:	(60,827,741)	490,799,070	40,581,708	—	—	517,637,686	1,049,018,464
Cash flow hedge	(60,827,741)	490,799,070	40,581,708	—	—	517,637,686	1,049,018,464
Derivatives not designated for hedge accounting	(2,150,524)	31,746,086	2,061,840	—	—	—	33,807,926
Total	(70,390,903)	634,856,156	154,954,548	299,496,000	—	517,637,686	1,606,944,390

The contractual maturities of hedging and non-hedging derivatives do not represent the Group’s total risk exposure, as the amounts presented in the above tables have been drawn up based on undiscounted contractual cash inflows and outflows for their settlement.

23.3 Fair value hierarchies

Financial instruments recognized at fair value in the consolidated statement of financial position are classified based on the hierarchies described in Note 3.h.

The following table presents financial assets and liabilities measured at fair value as of December 31, 2020 and 2019:

6
		Fair Value Measured at End of Reporting Period Using:
	12-31-2020	Level 1	Level 2	Level 3
Financial Instruments Measured at Fair Value	ThCh$	ThCh$	ThCh$	ThCh$
Financial Assets:
Financial derivatives designated as cash flow hedges	17,423,701	—	17,423,701	—
Financial derivatives not designated for hedge accounting	3,326,128	—	3,326,128	—
Derivatives of commodities designated as non-hedging of cash flow at fair value through profit or loss	1,618,607	—	1,618,607	—
Derivatives of commodities designated as cash flow hedges at fair value with changes in other comprehensive income	18,387,261	—	18,387,261
Equity instruments at fair value with changes in other comprehensive income	2,454,334	2,326,480	127,854	—
Total	43,210,031	2,326,480	40,883,551	—
Financial Liabilities:
Financial derivatives designated as cash flow hedges	21,566,335	—	21,566,335	—
Financial derivatives not designated for hedge accounting	23,285	—	23,285	—
Derivatives of commodities designated as cash flow hedges at fair value with changes in other comprehensive income	45,543	—	45,543	—
Total	21,635,163	—	21,635,163	—

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		Fair Value Measured at End of Reporting Period Using:
	12-31-2019	Level 1	Level 2	Level 3
Financial Instruments Measured at Fair Value	ThCh$	ThCh$	ThCh$	ThCh$
Financial Assets:
Financial derivatives designated as cash flow hedges	5,193,713	—	5,193,713	—
Derivatives of commodities designated as non-hedging of cash flow at fair value through profit or loss	1,573,704	—	1,573,704	—
Derivatives of commodities designated as cash flow hedges at fair value with changes in other comprehensive income	1,323,556	—	1,323,556	—
Equity instruments at fair value with changes in other comprehensive income	2,477,077	2,349,223	127,854
Total	10,568,050	2,349,223	8,218,827	—
Financial Liabilities:
Financial derivatives designated as cash flow hedges	73,434,092	—	73,434,092	—
Financial derivatives not designated for hedge accounting	2,150,524	—	2,150,524	—
Derivatives of commodities designated as cash flow hedges at fair value with changes in other comprehensive income	8,924,831	—	8,924,831	—
Total	84,509,447	—	84,509,447	—

24.  CURRENT AND NON-CURRENT PAYABLES

The detail of Trade and Other Current Payables as of December 31, 2020 and 2019 is as follows:

	Current		Non-current
	12-31-2020	12-31-2019	12-31-2020	12-31-2019
Trade and Other Payables	ThCh$	ThCh$	ThCh$	ThCh$
Energy suppliers (1)	135,817,661	178,153,813	112,895,627	53,941,373
Fuel and gas suppliers	36,735,748	55,179,023	—	—
Payables for goods and services	153,883,621	183,848,556	487	487
Payables for assets acquisition	251,679,169	100,307,602	4,233,657	2,281,051
Subtotal Trade Payables	578,116,199	517,488,994	117,129,771	56,222,911
Other Payables
Dividends payable to third parties	5,755,000	41,582,444	—	—
Accounts payables to employees	35,256,939	33,495,586	—	—
Other payables	8,829,884	6,696,184	80,288	27,174
Subtotal other current payables	49,841,823	81,774,214	80,288	27,174
Total	627,958,022	599,263,208	117,210,059	56,250,085

(1) The non-current portion shows delays in payments for energy purchases, generated by the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established in Law No. 21,185 (see Note 9).

The description of the liquidity risk management policy is detailed in Note 22.4.

The details of trade payables, both current and past due as of December 31, 2020 and 2019 are presented in Appendix 3.

25.  PROVISIONS

a) The detail of provisions as of December 31, 2020 and 2019, is detailed as follows:

	Current		Non-current
	12-31-2020	12-31-2019	12-31-2020	12-31-2019
Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Provision for legal proceedings	1,492,140	2,320,885	14,843,034	11,210,305
Decommissioning or restoration (*)	—	—	191,867,939	160,649,977
Other provisions	1,942,664	1,745,080	3,530,698	—
Total	3,434,804	4,065,965	210,241,671	171,860,282

(1) See Note 3.a.

Considering the new environmental regulation in Chile, the provision for decommissioning arises from recent clarifications concerning the scope of rights and obligations related to environmental permits. Therefore, the allowance has been adjusted to reflect the best estimate at the closing date of these financial statements.

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The expected timing and amount of any cash outflows related to the above provisions is uncertain and depends on the resolution of specific matters related to each one. For example, specifically for litigation, this depends on the final resolution of the corresponding legal claim. Management believes that provisions recognized in the financial statements cover the related risks appropriately.

Changes in provisions as of December 31, 2020 and 2019, are as follows:

	Legal Proceedings	Decommissioning or Restoration	Environmental Issues and Other Provisions	Total
Changes in Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2020	13,531,190	160,649,977	1,745,080	175,926,247
Increase (decrease) in existing provisions (1)	5,905,427	29,964,811	3,728,282	39,598,520
Provisions used	(1,471,151)	(1,743,534)	—	(3,214,685)
Reversal of unused provision	(1,474,149)	—	—	(1,474,149)
Increase from adjustment to time value of money (2)	—	4,115,292	—	4,115,292
Foreign currency translation	(156,143)	(1,118,607)	—	(1,274,750)
Total changes in provisions	2,803,984	31,217,962	3,728,282	37,750,228
Balance as of December 31, 2020	16,335,174	191,867,939	5,473,362	213,676,475
	Legal Proceedings	Decommissioning or Restoration	Environment and Other Provisions	Total
Changes in Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Balance as of January 1, 2019	17,352,876	92,402,517	1,704,768	111,460,161
Increase (decrease) in existing provisions (1)	3,749,833	62,688,286	40,168	66,478,287
Provisions used	(3,946,144)	(31,436)	(11)	(3,977,591)
Reversal of unused provision	(3,612,445)	—	—	(3,612,445)
Increase from adjustment to time value of money (2)	—	4,356,650	—	4,356,650
Foreign currency translation	(12,930)	1,233,960	155	1,221,185
Total changes in provisions	(3,821,686)	68,247,460	40,312	64,466,086
Balance as of December 31, 2019	13,531,190	160,649,977	1,745,080	175,926,247

1) The increase in the allowances for decommissioning or restoration during 2020 is explained primarily by the process to closure the Bocamina II plant’s operations. This resulted in an increase in the present value of the obligation, as a consequence of the adjustment to the previously established terms for making the disbursements, along with performing an update to the estimated values thereof (see Note 16.c.iv).

2) The variation in allowances for decommissioning or restoration during the year ended December 31, 2019 is primarily due to the increase in expected disbursements for the early closure of the Tarapacá and Bocamina I plants, framed within the Group's agreement with the Ministry of Energy to progressively cease operations of coal-fired generation plants (see Note 16.c.iv); and, to a lesser degree, an increase in the present value of provisions, due to a relevant decrease in the discount rates applied.

3) Corresponds to a financial restatement, see Note 34.

26.  POST-EMPLOYMENT BENEFIT OBLIGATIONS.

26.1 General information:

Enel Chile S.A. and certain subsidiaries granted various post-employment benefits to either all or certain active or retired employees. These benefits are calculated and recognized in the financial statements according to the criteria described in Note 3.m.1, and include primarily the following:

Defined benefit plans:

● Employee severance indemnities: The beneficiary receives a certain number of contractual salaries on the date of his retirement. This benefit becomes enforceable once the employee has provided services for a minimum period that, depending on the company, ranges from 5 to 15 years.

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● Complementary pension: The beneficiary is entitled to receive a monthly amount that supplements the pension obtained from the respective social security system.

● Electricity supply: The beneficiary receives a monthly bonus, which covers a part of the billing for their home consumption.

● Healthcare benefits: The beneficiary receives additional coverage that supplements the coverage provided by the social security regime.

26.2 Details, changes and presentation in financial statements:

a)  The post-employment obligations associated with defined benefits plans and the related plan assets as of December 31, 2020 and 2019.

	12-31-2020	12-31-2019
	ThCh$	ThCh$
Employee severance indemnities	50,011,279	42,697,317
Complementary Pension	18,896,906	17,853,600
Health Plans	3,145,989	3,090,670
Energy Supply Plans	3,484,091	2,521,903
Total post-employment obligations, net	75,538,265	66,163,490

The increase in post-employment liabilities is explained primarily by the adjustment to the discount rate applied by the Group at the year ended December 31, 2020, due to the decrease in this actuarial assumption (by 80 base points from the close of 2019), based on changes in the macroeconomic and financial environments due to the COVID-19 pandemic (see Notes 2.3 and 35.5).

b) The following amounts were recognized in the consolidated statement of comprehensive income for the years ended December 31, 2020, 2019 and 2018.

	For the years ended December 31,
Expense Recognized in	2020	2019	2018
Comprehensive Income	ThCh$	ThCh$	ThCh$
Cost of current defined benefit plan service	(2,132,231)	(1,928,868)	(1,920,262)
Defined benefit plan interest cost (1)	(2,146,386)	(2,639,738)	(2,750,376)
Past service cost	—	(1,224,527)	39,060
Expenses recognized in Profit or Loss	(4,278,617)	(5,793,133)	(4,631,578)
Gains (losses) from remeasurement of defined benefit plans	(8,545,834)	(7,777,204)	37,881
Total expense recognized in the Statement of Comprehensive Income	(12,824,451)	(13,570,337)	(4,593,697)

(1) See Note 34

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c)    The balance and changes in post-employment defined benefit obligations as of December 31, 2020 and 2019 are as follows:

Actuarial Value of Post-employment Obligations	ThCh$
Balance at January 1, 2019	56,602,664
Current service cost	1,928,868
Interest cost	2,639,738
Actuarial (gains) losses from changes in financial assumptions	5,724,985
Actuarial (gains) losses from changes in experience adjustments	2,052,219
Foreign currency translation	9,786
Past Service Cost Defined Benefit Plan Obligation	1,224,527
Contributions paid	(4,068,988)
Transfer of employees	49,691
Balance at December 31, 2019	66,163,490
Current service cost	2,132,231
Interest cost	2,146,386
Actuarial (gains) losses from changes in financial assumptions	4,695,927
Actuarial (gains) losses from changes in experience adjustments	3,849,907
Foreign currency translation	102,073
Contributions paid	(3,335,366)
Transfer of employees	(216,383)
Closing balance December 31, 2020	75,538,265

The Group makes no contributions to funds for financing the payment of these benefits.

26.3 Other disclosures:

● Actuarial assumptions:

As of December 31, 2020, and 2019, the following assumptions were used in the actuarial calculation of defined benefit plans:

	12-31-2020	12-31-2019
Discount rates used	2.60%	3.40%
Expected rate of salary increases	3.80%	3.80%
Turnover rate	7.10%	5.24%
Mortality tables	CB-H-2014 and RV-M-2014	CB-H-2014 / RV-M-2014

● Sensitivity:

As of December 31, 2020, the sensitivity of the value of the actuarial liability for post-employment benefits to variations of 100 basis points in the discount rate assumes a decrease of ThCh$5,602,670 (ThCh$5,330,365 as of December 31, 2019) if the rate rises and an increase of ThCh$6,136,668 (ThCh$5,829,095 as of December 31, 2019) if the rate falls.

● Defined contribution:

According to the available estimate, the disbursements foreseen to cover the defined benefit plans for 2021 amount to ThCh$8,445,218.

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● Length of commitments

Enel Chile´s obligations have a weighted average length of 7.98 years and the outflows of benefits for the next 10 years is expected to be as follows:

Years	ThCh$
1	8,445,218
2	6,484,023
3	5,441,166
4	6,022,293
5	5,467,563
6 to10	25,094,378

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27.  EQUITY

27.1.Equity attributable to the owners of Enel Chile

27.1.1. Subscribed and paid capital and number of shares

The issued capital of Enel Chile for the years ended December 31, 2020 and 2019 is ThCh$3,882,103,470 divided into 69,166,557,220 authorized, subscribed and paid shares. All of the shares issued by the Company are subscribed and paid, and they are listed for trade on the Bolsa de Comercio de Santiago de Chile, the Bolsa Electrónica de Chile, and the New York Stock Exchange (NYSE).

27.1.2. Treasury shares

As of December 31, 2020, and 2019, there are no treasury shares in the Group's portfolio. As of December 31, 2018, the treasury shares totaled ThCh$72,388,009 and represented 967,520,597 shares, which were acquired as a result of the merger with Enel Green Power Latin América Ltda. (“EGPL”). On April 29, 2019, these shares were legally deducted from the number of shares issued, as they had not been sold within one year from the date of acquisition, in accordance with the provisions of Article 27 of the Corporations Law No. 18,046.

27.1.3. Changes in Paid-in Capital as a Result of the Corporate Reorganization

Due to the corporate reorganization process (as described in Note 5), the Company increased its share capital in the voluntary tender offer of the shares of its subsidiary Enel Generación Chile and the merger with the company EGPL, in which the renewable assets of Enel SpA were incorporated into Enel Chile. The phases of this process are described below.

-Tender Offer for the acquisition of the shares “OPA by its Spanish acronym” of Enel Generación Chile

During the tender offer period between February 16 and March 22, 2018, the Company received acceptances and sale orders for a total of 2,582,336,287 shares of Enel Generación Chile and 5,691,996 ADSs equivalent to 170,759,880 shares of Enel Generación Chile; accordingly, the Company increased its interest and acquired 2,753,096,167 shares issued by Enel Generación Chile. According to the terms and conditions established in the transaction, the shareholders of Enel Generación Chile who agreed to sell their shares, would allocate 40% of the established purchase price (Ch$590 per share) to the subscription of newly issued shares of Enel Chile, thus receiving, in exchange for that 40%, 2.87807 shares in Enel Chile for each share issued by Enel Generación Chile and sold in the tender offer. By virtue of the above, the shareholders of Enel Generación Chile received Ch$1,624,326,738,530 in cash, divided into Ch$1,523,578,409,330 for Chilean shareholders and Ch$100,748,329,200 for foreign shareholders. Likewise, these shareholders subscribed shares of Enel Chile for a total of Ch$649,730,695,412 equivalent to 7,923,600,070 shares.

-Right to the preferential subscription of shares

According to the provisions of the Public Corporations Law, the Company's existing shareholders have a preferential right to subscribe the shares issued in a capital increase, in proportion to their holdings in the Company. Any shareholder existing at the time of the Enel Chile capital increase, could exercise such right by paying exclusively in cash for those shares. On March 16, 2018, the preferential subscription option was exercised for 47,860,124 shares, paying a price of Ch$82.00 for each share, thus increasing Capital by  Ch$3,924,530,168.

-Merger with Enel Green Power Latin América

The reorganization concluded with the merger of EGPL and Enel Chile, which occurred once the tender offer was declared successful and became effective on April 2, 2018. As a result of this merger, Enel Chile’s share capital increased by Ch$1,071,727,278,668, , equivalent to 13,069,844,862 shares, corresponding to 827,205,371 shares of EGPL owned by Enel SpA, at an exchange rate of 15.8 Enel Chile shares for each EGPL share.

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Changes in the number of Enel Chile’s shares as a result of the abovementioned corporate reorganization process are detailed as follows:

Number of outstanding shares of Enel Chile prior to the reorganization			49,092,772,762
	Number of shares	Ratio for exchange of shares	Number of shares
Public Tender Offer Shares of Enel Generation (1):
Purchased shares - national market	2,582,336,287	2.88	7,432,144,598
Purchased shares - ADS	170,759,880	2.88	491,455,472
Total Public Tender Offer for Shares	2,753,096,167		7,923,600,070
Enel Chile Preemtive right shares (2):
Shares paid for by shareholders	47,860,124		47,860,124
Total Preemtive Rights	47,860,124		47,860,124
Merger with EGPL (3):
Shares issued to Enel SpA	827,205,371	15.8	13,069,844,862
Total Merger with EGPL	827,205,371		13,069,844,862
Repurchase of shares (4):
Withdrawal Rights exercised by minority shareholders of Enel Chile	(967,520,598)		(967,520,598)
Total repurchase of shares	(967,520,598)		(967,520,598)
Number of issued shares in Enel Chile after merger			69,166,557,220
Total number of shares issued			70,134,077,818
Total number of treasury shares			(967,520,598)
Number of issued shares in Enel Chile after merger			69,166,557,220

(1) The total amount for the issuance of these new shares was ThCh$649,730,695.

(2) The payment made by the minority shareholders of Enel Chile was ThUS$3,924,530.

(3) The valuation of the capital increase due to the merger was ThCh$1,071,727,279.

(4) The total amount paid for the repurchase of shares was ThCh$72,388,009.

27.2 Dividends

Dividend No.	Type of Dividend	Agreement date	Payment Date	Total Amount M$	Pesos per Share	Charged to Fiscal
4	Interim	12-20-2017	01-26-2018	37,134,944	0.75642	2017
5	Final	04-25-2018	05-18-2018	155,025,509	2.24134	2017
6	Interim	11-29-2018	01-25-2019	31,288,371	0.45236	2018
7	Final	04-29-2019	05-17-2019	185,737,592	2.68537	2018
8	Interim	11-26-2019	01-31-2020	30,933,437	0.44723	2019
9	Final	04-29-2020	05-27-2020	146,758,726	2.12182	2019
9	Eventual	04-29-2020	05-27-2020	114,883,119	1.66096	(1)

(1) On April 29, 2020, the distribution of the obligatory minimum dividend (final dividend No. 9) was agreed upon, with charge to the profit for 2019. Additionally, and to offset the resulting impairment of the subsidiary Enel Generación Chile in 2019 (see Note 16.c.iv, Development during 2019), the distribution of a provisional dividend (No. 9) was approved with charge to the retained earnings for previous years.

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27.3 Foreign currency translation reserves

The detail by company of the translation differences attributable to owners of the Group, of the consolidated statement of financial position as of December 31, 2020, 2019 and 2018, is as follows:

	For the years ended December 31,
	12-31-2020	12-31-2019	12-31-2018
Reserves for Accumulated Currency Translation Differences	ThCh$	ThCh$	ThCh$
Enel Generación Chile S.A.	(7,746,933)	(3,292,629)	302,222
GNL Chile S.A.	907,869	1,022,047	900,483
Grupo Enel Green Power Chile	110,921,404	168,387,151	100,452,131
Enel AMPCI Ebus Chile SpA	(432,247)	—	—
TOTAL	103,650,093	166,116,569	101,654,836

27.4 Restrictions on subsidiaries transferring funds to the parent

Our subsidiary Enel Generación Chile must comply with certain financial ratios or covenants, which require a minimum level of equity or contain other characteristics that restrict the transfer of assets to the Parent. As of December 31, 2020, the Company's interest in the net restricted assets of Enel Generación Chile amounts to ThCh$ 712,519,037 (ThCh$752,696,419 as of December 31, 2019).

27.5 Other reserves

Other reserves for the years ended December 31, 2020 and 2019, are as follows:

	01.01.2020	2020 Changes	12-31-2020
Detail of other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	166,116,569	(62,466,476)	103,650,093
Cash flow hedges	(291,006,520)	188,060,425	(102,946,095)
Financial assets at fair value with changes in other comprehensive income	8,384	(6,601)	1,783
Other miscellaneous reserves	(2,280,627,568)	2,296,302	(2,278,331,266)
TOTAL	(2,405,509,135)	127,883,650	(2,277,625,485)
	01.01.2019	2019 Changes	12-31-2019
Detail of other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	101,654,836	64,461,733	166,116,569
Cash flow hedges	(191,870,545)	(99,135,975)	(291,006,520)
Financial assets at fair value with changes in other comprehensive income	11,041	(2,657)	8,384
Other miscellaneous reserves	(2,285,467,896)	4,840,328	(2,280,627,568)
TOTAL	(2,375,672,564)	(29,836,571)	(2,405,509,135)
	01.01.2018	2018 Changes	12-31-2018
Detail of other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	6,976,383	94,678,453	101,654,836
Cash flow hedges	(32,849,736)	(159,020,809)	(191,870,545)
Financial assets at fair value with changes in other comprehensive income	11,284	(243)	11,041
Other miscellaneous reserves	(971,468,479)	(1,313,999,417)	(2,285,467,896)
TOTAL	(997,330,548)	(1,378,342,016)	(2,375,672,564)

a) Reserves for exchange differences on translation: These reserves arise primarily from exchange differences relating to the translation of financial statements of the Company’s consolidated entities with functional currencies other than the Chilean peso (see Note 2.7.3).

b) Cash flow hedge reserves: These reserves represent the cumulative effective portion of gains and losses on cash flow hedges (see Note 3.g.5 and 3.h).

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c) Other miscellaneous reserves:

The main items and their effects are the following:

	For the years ended
	2020	2019	2018
Other Miscellaneous Reserves	ThCh$	ThCh$	ThCh$
Company restructuring reserve ("Division") (i)	(534,057,733)	(534,057,733)	(534,057,733)
Reserve for transition to IFRS (ii)	(457,221,836)	(457,221,836)	(457,221,836)
Reserve for subsidiaries transactions (iii)	12,502,494	12,502,494	12,502,494
Reserves for Tender Offer of Enel Generation “Reorganization of Renewable Assets” (iv)	(910,437,224)	(910,437,224)	(910,437,224)
Reserves “Reorganization of Renewable Assets” (v)	(407,354,462)	(407,354,462)	(407,354,462)
Argentine hyperinflation (vi)	11,216,652	8,939,332	3,508,753
Other miscellaneous reserves (vii)	7,020,843	7,001,861	7,592,112
TOTAL	(2,278,331,266)	(2,280,627,568)	(2,285,467,896)

i) Corporate restructuring reserve (Division): This represents the effect generated by the corporate reorganization of Enersis S.A. (currently Enel Américas), concluded in 2016, by which the company divided its businesses between Chile and the rest of South America. The new company was called Enersis Chile (now Enel Chile), and was assigned the equity corresponding to the related business in Chile.

ii) Reserves for transition to IFRS: In compliance with the provisions of Circular No. 456 by the Financial Market Commission, the price-level restatement of accumulated paid-in capital has been incorporated in this category from the date of the Company’s transition to IFRS, i.e., January 1, 2004, through December 1, 2008.

iii) Reserves for business combinations: These represent the effect generated by the purchases of interest under common control.

iv) "Reorganization of Renewable Assets” Enel Generación Chile Takeover Reserve: This represents the difference between the carrying amount of non-controlling interest acquired as part of the tender offer aimed at acquiring all shares issued by the subsidiary Enel Generación Chile (see Note 5.i).

v) "Reorganization of Renewable Assets” Reserve: This corresponds to the reserve constituted by the merger between Enel Green Power Latin América and Enel Chile on April 2, 2018. It represents the recognition of the difference produced by the capital increase in Enel Chile (corresponding to the market value of interest in Enel Green Power Chile and subsidiaries) and the carrying amount of Enel Green Power Latin América's equity that was incorporated under share capital in the net equity distributable to the owners of Enel Chile, as a result of the merger.

vi) Hyperinflation in Argentina: This corresponds to the calculated effect of the application of IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch held by the Enel Generación Chile Group in Argentina (see Note 2.9).

vii) Other miscellaneous reserves This reserve derives from transactions performed in prior years.

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27.6 Non-controlling Interests

The detail of non-controlling interests as of December 31, 2020, 2019 and 2018, is as follows:

		Non-controlling Interests
		Equity			Profit (Loss)
	12-31-2020	12-31-2020	12-31-2019	2020	2019	2018
Companies	%	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Distribución Chile S.A.	0,91%	8,188,827	7,691,319	749,261	1,079,941	1,112,709
Enel Generación Chile S.A.	6,45%	111,567,532	126,700,973	(10,006,037)	12,667,880	42,883,953
Empresa Eléctrica Pehuenche S.A.	7,35%	10,113,358	10,079,858	6,403,829	6,241,062	6,885,422
Sociedad AgrÍcola de Cameros Ltda.	42,50%	2,068,169	1,837,612	230,557	(504,550)	(254,604)
Geotermica del Norte SA	15,41%	55,283,359	57,871,809	645,440	(264,158)	(187,989)
Empresa Nacional de Geotermia SA	49,00%	11,134	995,614	(515,293)	(74,963)	41,780
Parque Eolico Talinay Oriente SA	39,09%	55,283,519	57,586,860	945,454	868,127	662,374
Others		(157,189)	(178,379)	20,267	(73,726)	(5,825)
TOTAL		242,358,709	262,585,666	(1,526,522)	19,939,613	51,137,820

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28.  REVENUE AND OTHER OPERATING INCOME

The detail of revenue presented in the statement of comprehensive income for the years ended December 31, 2020, 2019 and 2018, is as follows:

	For the years ended December 31,
	2020	2019	2018
Revenues	ThCh$	ThCh$	ThCh$
Energy sales (1)	2,380,736,600	2,405,903,242	2,202,078,088
Generation	1,111,508,158	1,090,021,527	1,034,975,160
Regulated customers (2)	480,168,004	540,017,333	643,494,066
Unregulated customers	571,587,710	524,559,735	357,725,928
Spot market sales	59,752,444	25,444,459	33,755,166
Distribution	1,269,228,442	1,315,881,715	1,167,102,928
Residential (2)	608,703,250	552,124,205	455,840,910
Business	366,874,872	450,108,855	378,092,990
Industrial	168,931,181	181,595,960	209,252,478
Other consumers (3)	124,719,139	132,052,695	123,916,550
Other sales	58,870,872	124,113,792	123,345,383
Gas sales	38,808,266	97,564,262	103,717,558
Sales of goods and services	20,062,606	26,549,530	19,627,825
Revenue from other services	108,776,845	94,559,289	84,936,988
Tolls and transmission	41,859,311	31,232,252	20,311,403
Metering equipment leases	3,387,302	2,131,427	4,702,334
Services and Business Advisories provided (Public lighting, connections and electrical advisories)	53,121,851	47,455,465	45,904,638
Other services	10,408,381	13,740,145	14,018,613
Total Revenues	2,548,384,317	2,624,576,323	2,410,360,459
Other Income	ThCh$	ThCh$	ThCh$
Temporary leasing of generating facilities	10,662,952	2,777,404	—
Commodity derivative income	4,473,463	5,967,739	9,819,777
Income from early termination of electricity supply contracts (4)	—	121,117,605	—
Income from insurance claims	10,799,437	5,952,589	25,442,309
Other income (5)	11,082,028	10,442,700	11,538,881
Total other income	37,017,880	146,258,037	46,800,967

(1)As of December 31, 2020, a total of ThCh$434,442,879 is included in total revenue, corresponding to estimated and unbilled sales, which are related to estimations made of energy sold in the month of December 2020, including PEC and node prices. As of December 31, 2019 and 2018, the amounts correspond to ThCh$310,301,370 and ThCh$209,288,934, respectively.

(2)For the year ended December 31, 2020, this line item includes an effect of ThCh$77,973,766 corresponding to the differences between the prices of electricity supply contracts and regulated prices, which will be billed in the future in accordance with the schedule established in Law No. 21,185 (see Note 9). Of this amount, ThCh$25,154,565 correspond to income that the Group will have to transfer to final customers through its subsidiary Enel Distribución Chile.

(3)For the year ended December 31, 2020, Other customers includes revenues from the sale of energy to municipalities of ThCh$35,598,366 (ThCh$45,768,456 and ThCh$36,878,861 as of December 31, 2019 and 2018, respectively), governmental entities of ThCh$17,334,983 (ThCh$20,432,048 and ThCh$20,246,633 as of December 31, 2019 and 2018, respectively), agricultural sector companies of ThCh$10,324,464 (ThCh$9,100,691 and ThCh$6,173,077 as of December 31, 2019 and 2018, respectively), utilities and telecommunications companies of ThCh$27,014,443 (ThCh$24,818,503 and ThCh$26,636,066 as of December 31, 2019 and 2018, respectively), education sector of ThCh$5,749,102 (ThCh$9,367,933 and ThCh$12,470,709 as of December 31, 2019 and 2018, respectively), healthcare

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services of ThCh $21,407,325 (ThCh$18,975,909 and ThCh$19,629,502 as of December 31, 2019 and 2018, respectively) and other of ThCh$ 7,290,456 (ThCh$ 3,589,156 and ThCh$ 1,881,702 as of December 31, 2019 and 2018, respectively).

(4)In February 2019, Anglo American Sur S.A. notified Enel Generación Chile of its decision to terminate early three electricity supply contracts, which both parties had signed in 2016. As stipulated in the termination clauses of the respective contracts, the notice of early termination granted Enel Generación Chile the right to receive termination compensation, consisting of a cash payment by Anglo American Sur S.A., which would be determined according to a predefined calculation mechanism.

It is important to note that between the date of notice of the early termination and the date of effective termination of the contracts, there were no performance obligations pending delivery by Enel Generación Chile, as the original contracts established the start of supply in January 2021. Therefore, following the accounting criteria described in Note 3.q), income of ThCh$121,117,605 was recognized.

On June 21, 2019, Enel Generación Chile made a non-recourse assignment of the cash flows of this   agreement. Consequently, the cash inflow resulted in the derecognition of the account receivable from Anglo American Sur S.A. existing at that date.

(5) For the year ended December 31, 2020, Other income includes revenue recovery from customers with unrecorded   consumption of ThCh$3,084,840 (ThCh$2,746,764 and ThCh$ 2,847,740 for the years ended December 31, 2019 and 2018, respectively), income from late cancellation of ThCh$456,781 (ThCh$485,684 and ThCh$675,202 for the years ended December 31, 2019 and 2018, respectively) sale of demineralized water of ThCh$1,408,798 (ThCh$498,577 and ThCh$542,927 for the years ended December 31, 2019 and 2018, respectively), and other income of ThCh$6,131,609 (ThCh$6,711,675 and ThCh$7,473,012 for the years ended December 31, 2019 and 2018, respectively).

29.  RAW MATERIALS AND CONSUMABLES USED

The detail of raw materials and consumables used presented in profit or loss for the years ended December 31, 2020, 2019 and 2018, is as follows:

	For the years ended December 31,
	2020	2019	2018
Raw materials and consumables used	ThCh$	ThCh$	ThCh$
Energy purchases	(864,863,454)	(835,284,742)	(747,646,603)
Fuel consumption	(231,176,489)	(230,944,415)	(231,028,169)
Gas	(149,734,219)	(134,127,365)	(140,145,010)
Oil	(6,100,077)	(3,326,061)	(11,146,001)
Coal	(75,342,193)	(93,490,989)	(79,737,158)
Transportation costs	(141,539,687)	(196,848,788)	(166,875,801)
Gas sales costs	(34,332,998)	(74,998,608)	(80,477,713)
Other raw materials and consumables	(102,533,011)	(83,128,698)	(66,148,830)
Total	(1,374,445,639)	(1,421,205,251)	(1,292,177,116)

30.  EMPLOYEE BENEFITS EXPENSE

The detail of employee expenses for the years ended December 31, 2020, 2019 and 2018, is as follows:

	For the years ended December 31,
	2020	2019	2018
Employee Benefits Expense	ThCh$	ThCh$	ThCh$
Wages and salaries	(117,220,406)	(109,101,737)	(102,897,710)
Post-employment benefit obligations expense	(2,132,231)	(3,153,395)	(1,881,202)
Social security and other contributions	(12,346,828)	(14,334,587)	(13,405,944)
Other employee expenses	(5,527,283)	(3,015,237)	(4,945,478)
Total Employee Benefits Expenses	(137,226,748)	(129,604,956)	(123,130,334)

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31.  DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSS OF PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS UNDER-IFRS 9

a) The detail of depreciation and amortization for the years ended December 31, 2020, 2019 and 2018, is as follows:

	For the years ended December 31,
	2020	2019	2018
	ThCh$	ThCh$	ThCh$
Depreciation	(215,581,938)	(224,724,380)	(202,971,892)
Amortization	(14,375,081)	(11,903,007)	(12,215,408)
Total	(229,957,019)	(236,627,387)	(215,187,300)

b) The detail of the items related to impairment for the years ended December 31, 2020, 2019 and 2018, is as follows:

	For the years ended December 31,
	Generation			Distribution			Other			Total
	2020	2019	2018	2020	2019	2018	2020	2019	2018	2020	2019	2018
Information on Impairment Losses by Reportable Segment	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Property, Plant and Equipment (see Note 16)(*)	(698,235,380)	(280,020,263)	—	—	—	—	—	—	—	(698,235,380)	(280,020,263)	—
Intangibles (see Note 14)	(217,658)	—	—	—	—	—	—	—	—	(217,658)	—	—
Investment Property (see Note 17)	—	—	—	—	—	—	646,597	(742,389)	(779,825)	646,597	(742,389)	(779,825)
Total Reversal of impairment losses (impairment losses) recognized in profit or loss	(698,235,380)	(280,020,263)	—	—	—	—	646,597	(742,389)	(779,825)	(697,806,441)	(280,762,652)	(779,825)
Impairment gain and reversals from impairment losses in accordance with IFRS 9 (see note 10.d)	(1,305,341)	(1,338,599)	(106,264)	(12,998,719)	(8,153,419)	(4,676,808)	(863,647)	(554,982)	—	(15,167,707)	(10,047,000)	(4,783,072)

(*) Relates to the process to closure the operations of Bocamina II for ThCh$697,856,387 mainly, see Note 16, paragraph c), iv).

32.  OTHER EXPENSE, BY NATURE

Other miscellaneous operating expense for the years ended December 31, 2020, 2019 and 2018, are detailed as follows:

	For the years ended December 31,
	2020	2019	2018
Other Expenses by nature	ThCh$	ThCh$	ThCh$
Professional, outsourced and other services	(74,630,728)	(60,819,733)	(69,692,677)
Administrative expenses	(7,214,238)	(8,893,785)	(5,991,676)
Repairs and maintenance	(49,051,950)	(50,846,851)	(41,829,409)
Indemnities and fines	(1,029,517)	(1,243,376)	(455,825)
Taxes and charges	(5,675,978)	(6,802,176)	(4,415,819)
Insurance premiums	(19,992,385)	(19,200,681)	(15,794,761)
Leases and rental costs	(4,958,760)	(3,824,195)	(3,775,007)
Marketing, public relations and advertising	(2,491,884)	(3,274,693)	(2,440,070)
Write-off Property, Plant and Equipment (*)	—	(3,510,591)	—
Travel expenses	(2,223,358)	(3,991,349)	(2,436,407)
Environmental expenses	(8,313,182)	(9,886,690)	(9,664,683)
Other supplies and services	(15,011,354)	(11,849,020)	(10,713,687)
Total	(190,593,334)	(184,143,140)	(167,210,021)

(*) See explanation in Note 16 e) paragraph vi).

F-119

33.  OTHER GAINS (LOSSES)

The detail of other gains (losses) for the years ended December 31, 2020, 2019 and 2018 is as follows:

	For the years ended December 31,
	2020	2019	2018
Other Gains (Losses)	ThCh$	ThCh$	ThCh$
Gain on sale of Property, Plant and Equipment	9,384,038	1,530,689	3,024,549
Result of other investments	104,777	262,512	385,830
Total	9,488,815	1,793,201	3,410,379

34.  FINANCIAL RESULTS.

Finance income and costs for the years ended December 31, 2020, 2019 and 2018, are as follows:

	For the years ended December 31,
	2020	2019	2018
Finance Income	ThCh$	ThCh$	ThCh$
Income from deposits and other financial instruments	7,324,057	8,973,606	9,612,575
Interests charged to customers in energy accounts and billing	12,477,393	8,057,203	7,140,984
Financial income by Law N°21,185 (1)	15,328,829	5,225,739
Other financial income	1,030,181	5,142,727	3,180,909
Total Finance Income	36,160,460	27,399,275	19,934,468

	For the years ended December 31,
	2020	2019	2018
Finance Costs	ThCh$	ThCh$	ThCh$
Finance Costs	(127,408,771)	(164,897,900)	(122,184,189)
Bank loans	(7,151,030)	(14,487,700)	(20,701,774)
Bonds payable to the public not guaranteed	(84,268,247)	(81,818,564)	(62,255,300)
Lease obligations	(2,128,360)	(1,815,170)	(739,069)
Valuation of financial derivatives for cash flow hedging	(5,887,498)	1,775,749	1,183,228
Financial update of provisions (2)	(4,115,292)	(4,356,650)	(3,176,001)
Post-employment benefit obligations (3)	(2,146,386)	(2,639,738)	(2,750,376)
Debt formalization expenses and other associated expenses	(2,646,906)	(4,710,012)	(9,373,412)
Capitalized borrowing costs	33,109,819	9,321,354	6,435,646
Financial cost related companies	(35,079,947)	(31,304,382)	(23,228,947)
Financial cost by Law N°21,185 (1)	(4,518,268)	(19,062,333)	—
Other financial costs	(12,576,656)	(15,800,454)	(7,578,184)
(Loss) gain from indexed assets and liabilities, net	2,085,768	(2,982,268)	(818,146)
Foreign currency exchange differences	(23,272,231)	(10,412,110)	(7,807,197)
Total Finance Costs	(148,595,234)	(178,292,278)	(130,809,532)
Total Financial Results	(112,434,774)	(150,893,003)	(110,875,064)

(1) Relates to finance income and costs generated by the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established in Law No. 21,185 (see Note 9).

(2) See Note 25.

(3) See Note 26.2 b).

F-120

The origins of the effects on results for the application of adjustment units and foreign exchange gains (losses) are as follows:

	For the years ended December 31,
	2020	2019	2018
Gains (losses) from Indexed Assets and Liabilities (*)	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	—	36,797	—
Other non-financial assets	—	—	45,108
Trade and other receivables	2,212,324	1,410,408	1,197,498
Current tax assets and liabilities	1,026,963	2,557,465	3,424,644
Other financial liabilities (financial debt and derivative instruments)	980,933	(1,637,291)	(1,714,216)
Trade and other payables	241,532	16,939	15,145
Other provisions	(196,777)	—	—
Other non-financial liabilities	(643)	(1,688)	—
Sub total	4,264,332	2,382,630	2,968,179
Intangible assets other than goodwill	142	203	180
Property, plant and equipment	764,982	1,132,453	1,035,084
Deferred tax liabilities	(548,505)	—	—
Equity	(2,434,384)	(5,805,120)	(3,743,959)
Other Provision of Services	(1,246)	—	(1,189,452)
Energy Sales	—	(1,352,295)	—
Energy Purchases	—	432	—
Other variable supplies and services	—	—	21,503
Work for the Fixed Assets	—	103,512	—
Personal expenses	130,213	166,715	143,148
Other fixed operating expenses	108,226	23,714	147,975
Financial income	(204,137)	(367,059)	(268,511)
Financial expenses	6,145	732,547	67,707
Sub total Hyperinflation result (1)	(2,178,564)	(5,364,898)	(3,786,325)
Gains from indexed assets and liabilities, net	2,085,768	(2,982,268)	(818,146)
	For the years ended December 31,
	2020	2019	2018
Foreign Currency Exchange Differences (**)	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	10,110,166	(937,177)	(415,962)
Other financial assets	6,316,333	2,052,540	5,733,173
Other non-financial assets	6,086,388	(1,712,690)	(534,401)
Trade and other receivables (2)	(24,504,740)	8,847,969	726,347
Current tax assets and liabilities	(4,361,506)	(1,633,471)	(1,903,963)
Other financial liabilities (financial debt and derivative instruments)	(10,265,859)	(8,147,939)	(5,726,246)
Trade and other payables (2)	(5,755,302)	(9,381,721)	(5,379,210)
Other non-financial liabilities	(897,711)	500,379	(306,935)
Total Foreign Currency Exchange Differences	(23,272,231)	(10,412,110)	(7,807,197)

(5) Corresponds to the financial effect derived from the application of IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch held by the Enel Generación Chile Group in Argentina (see Note 2.9).

(6) This includes the foreign currency translation difference due to the dollarization of trade receivables and payables in the amount of ThCh$(36,494,889) and ThCh$ 11,234,506 respectively, as a result of the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established in Law No. 21,185 (see Note 9).

F-121

35.  INFORMATION BY SEGMENT

35.1. Basis of segmentation

The Group’s activities operate under a matrix management structure with dual and cross management responsibilities (based on business and geographical areas of responsibility), and its subsidiaries are engaged in either the Generation and Transmission Business or the Distribution Business.

The Group adopted a “bottom-up” approach to determine its reportable segments. The Generation and Transmission and the Distribution reportable segments have been defined based on IFRS 8.9 and on the criteria described in IFRS 8.12.

Generation Segment: The electricity generation segment is comprised of a group of electricity companies that own electricity generating plants, whose energy is transmitted and distributed to end consumers. The Generation Business in Chile is conducted by the Company’s subsidiaries Enel Generación Chile S.A. and Empresa Eléctrica Pehuenche S.A., and the Company’s group is engaged in the development and exploitation of renewable energies with the wind power subsidiaries Parque Eólico Tal Tal SpA and Parque Talinay Oriente S.A., and the geothermal subsidiary Geotérmica del Norte S.A., as well as the wind and solar power from Enel Green Power Chile S.A., and the subsidiary Almeyda Solar SpA, which is engaged in hydro, solar and wind power generation.

Distribution Business: The Distribution reportable segment is comprised of the company Enel Distribución Chile S.A., operating under a public utility concession, with service obligations and regulated tariffs for supplying regulated customers.

Each of the operating segments generates separate financial information, which is aggregated into one combined set of information for the Generation Business, and another set of combined information for the Distribution Business at the reportable segment level. In addition, in order to assist the decision maker process, the Planning & Control Department at the parent company level prepares internal reports containing combined information at the reportable segment level about the main key performance indicators (KPIs), such as: Gross Operating Income, Gross Margin, Total Capex, Total Opex, Net income, Total Energy Generation and Transmission, among others. The presentation of information under this business approach has been made taking into consideration that the KPIs are similar in each of the following aspects:

a) the nature of the activities: generation on one hand, and distribution on the other;

b) the nature of the production processes: The Generation Business deals with the generation of electricity and its transmission to dispatch centers, while the Distribution Business does not generate electricity, but distributes electricity to end customers;

c) the type or class of customer for their products and services: the Generation Business provides services mainly to unregulated customers, while the Distribution Business provides services to regulated customers;

d) the methods used to distribute their products or provide their services: generators generally sell energy through energy auctions, while distributors provide energy in their concession area; and

e) the nature of the regulatory environment (public utilities): the regulatory frameworks differ in the Generation and Transmission Business and the Distribution Business.

The Company’s chief operating decision maker (“CODM”) in conjunction with managers in Chile reviews on a monthly basis these internal reports and uses the KPI information to make decisions on the allocation of resources and the assessment of the performance of the operating segments for each reportable segment.

The information disclosed in the following tables is based on the financial information of the companies forming each segment. The accounting policies used to determine the segment information are the same as those used in the preparation of the Group’s consolidated financial statements.

F-122

35.2 Generation and Distribution

	Generation		Distribution		Holdings, eliminations and others		Total
	12-31-2020	12-31-2019	12-31-2020	12-31-2019	12-31-2020	12-31-2019	12-31-2020	12-31-2019
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
ASSETS
CURRENT ASSETS	581,661,790	941,262,837	282,024,842	289,393,932	162,714,564	(212,444,109)	1,026,401,196	1,018,212,660
Cash and cash equivalents	4,971,820	26,391,853	3,657,471	2,331,365	323,406,722	206,961,282	332,036,013	235,684,500
Other current financial assets	2,562,093	489,658	29,977	64,220	760,334	756,717	3,352,404	1,310,595
Other current non-financial assets	11,665,802	8,908,239	2,830,106	8,868,077	5,305,665	16,858,247	19,801,573	34,634,563
Trade and other current receivables	285,241,891	230,670,997	259,172,712	260,840,410	10,472,036	19,943,923	554,886,639	511,455,330
Current accounts receivable from related companies	232,991,789	587,067,775	4,269,460	10,115,510	(179,285,124)	(529,001,152)	57,976,125	68,182,133
Inventories	18,163,284	34,705,515	3,397,415	3,150,943	1,749,330	1,815,792	23,310,029	39,672,250
Current tax assets	26,065,111	53,028,800	8,667,701	4,023,407	305,601	70,221,082	35,038,413	127,273,289
NON-CURRENT ASSETS	4,722,779,027	4,771,905,050	1,369,182,558	1,175,550,962	786,108,803	892,319,492	6,878,070,388	6,839,775,504
Other non-current financial assets	20,660,446	7,189,431	4	22,741	—	8,448	20,660,450	7,220,620
Other non-current non-financial assets	62,608,451	34,903,436	2,791,875	2,576,585	386,889	570,163	65,787,215	38,050,184
Trade and other non-current receivables	166,469,458	88,225,632	277,378,406	157,051,933	1,168,702	68,296,820	445,016,566	313,574,385
Non-Current accounts payable from related companies	141,649,129	80,926,788	—	—	(93,290,214)	(46,519,646)	48,358,915	34,407,142
Investments accounted for using the equity method	9,551,139	7,928,588	—	—	3,441,664	—	12,992,803	7,928,588
Intangible assets other than goodwill	94,464,506	76,077,944	65,335,352	51,360,795	5,314,663	4,839,854	165,114,521	132,278,593
Goodwill	32,682,252	33,135,272	2,240,478	2,240,478	880,782,639	881,977,224	915,705,369	917,352,974
Property, plant and equipment	4,037,877,000	4,370,419,860	1,015,249,248	957,752,454	(19,629,776)	(23,696,200)	5,033,496,472	5,304,476,114
Investment property	—	—	—	—	7,421,940	6,795,155	7,421,940	6,795,155
Assets for right of use	50,373,648	52,155,733	5,117,436	3,640,103	11,108	47,674	55,502,192	55,843,510
Deferred tax assets	106,442,998	20,942,366	1,069,759	905,873	501,188	—	108,013,945	21,848,239
TOTAL ASSETS	5,304,440,817	5,713,167,887	1,651,207,400	1,464,944,894	948,823,367	679,875,383	7,904,471,584	7,857,988,164

	Generation		Distribution		Holdings, eliminations and others		Total
	12-31-2020	12-31-2019	12-31-2020	12-31-2019	12-31-2020	12-31-2019	12-31-2020	12-31-2019
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
LIABILITIES AND EQUITY
CURRENT LIABILITIES	903,590,885	844,513,549	335,412,469	317,248,207	(193,523,189)	(120,461,904)	1,045,480,165	1,041,299,852
Other current financial liabilities	155,592,371	206,888,115	77,554	1	1,829,216	1,926,445	157,499,141	208,814,561
Current lease liabilities	5,495,257	5,039,971	1,505,677	738,782	6,777	63,262	7,007,711	5,842,015
Trade and other current payables	416,425,675	300,957,548	190,709,618	200,472,938	20,822,729	97,832,722	627,958,022	599,263,208
Current accounts payable to related companies	237,326,397	296,861,070	118,883,364	87,507,312	(226,155,799)	(224,558,495)	130,053,962	159,809,887
Other current provisions	2,933,069	3,619,734	—	—	501,735	446,231	3,434,804	4,065,965
Current tax liabilities	65,963,158	17,717,789	95,556	34,718	6,301,230	243,326	72,359,944	17,995,833
Other current non-financial liabilities	19,854,958	13,429,322	24,140,700	28,494,456	3,170,923	3,584,605	47,166,581	45,508,383
NON-CURRENT LIABILITIES	1,647,789,150	1,899,077,568	415,149,858	301,769,861	1,201,777,912	868,557,231	3,264,716,920	3,069,404,660
Other non-current financial liabilities	774,737,983	954,402,603	4	—	708,851,139	738,201,642	1,483,589,126	1,692,604,245
Non-current lease liabilities	41,147,046	44,572,348	3,704,860	2,993,326	5,901	—	44,857,807	47,565,674
Trade and other non-current payables	4,286,773	2,281,053	112,922,799	53,968,545	487	487	117,210,059	56,250,085
Non-current accounts payable to related companies	457,825,939	486,839,484	228,805,329	182,031,404	477,413,194	115,502,596	1,164,044,462	784,373,484
Other long-term provisions	194,653,912	160,006,401	15,587,759	11,853,881	—	—	210,241,671	171,860,282
Deferred tax liabilities	152,083,137	231,156,234	20,212,892	19,818,625	(4,238,467)	(1,690,218)	168,057,562	249,284,641
Non-current provisions for employee benefits	23,054,360	19,819,445	32,738,247	29,801,321	19,745,658	16,542,724	75,538,265	66,163,490
Other non-current non-financial liabilities	—	—	1,177,968	1,302,759	—	—	1,177,968	1,302,759
EQUITY	2,753,060,782	2,969,576,770	900,645,073	845,926,826	(59,431,356)	(68,219,944)	3,594,274,499	3,747,283,652
Equity attributable to Enel Chile	2,753,060,782	2,969,576,770	900,645,073	845,926,826	(59,431,356)	(68,219,944)	3,351,915,790	3,484,697,986
Issued capital	1,403,737,121	1,185,731,351	230,137,980	230,137,980	2,248,228,369	2,466,234,139	3,882,103,470	3,882,103,470
Retained earnings	1,473,514,878	1,735,720,458	988,991,623	933,560,288	(715,068,696)	(661,177,095)	1,747,437,805	2,008,103,651
Issuance premiums	85,511,492	85,511,492	354,220	354,220	(85,865,712)	(85,865,712)	—	—
Treasury shares in portfolio	(252,632,367)	—	—	—	252,632,367	—	—	—
Other reserves	42,929,658	(37,386,531)	(318,838,750)	(318,125,662)	(1,759,357,684)	(1,787,411,276)	(2,277,625,485)	(2,405,509,135)
Non-controlling interests	—	—	—	—	—	—	242,358,709	262,585,666
Total Liabilities and Equity	5,304,440,817	5,713,167,887	1,651,207,400	1,464,944,894	948,823,367	679,875,383	7,904,471,584	7,857,988,164

The Holding, Eliminations and Others column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

F-123

	Generation			Distribution			Holdings eliminations			Total
	12-31-2020	12-31-2019	12-31-2018	12-31-2020	12-31-2019	12-31-2018	12-31-2020	12-31-2019	12-31-2018	12-31-2020	12-31-2019	12-31-2018
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
REVENUES	1,577,422,263	1,726,611,508	1,580,653,088	1,382,068,220	1,412,871,738	1,263,224,072	(374,088,286)	(368,648,886)	(386,715,734)	2,585,402,197	2,770,834,360	2,457,161,426
Revenues	1,543,647,794	1,581,230,963	1,540,352,133	1,376,425,433	1,408,588,042	1,254,943,604	(371,688,910)	(365,242,682)	(384,935,278)	2,548,384,317	2,624,576,323	2,410,360,459
Energy sales	1,494,203,779	1,472,565,933	1,425,942,129	1,270,159,653	1,318,386,716	1,170,129,333	(383,626,832)	(385,049,407)	(393,993,374)	2,380,736,600	2,405,903,242	2,202,078,088
Other sales	38,825,239	97,870,470	103,779,801	6,601,069	9,365,186	16,411,425	13,444,564	16,878,136	3,154,157	58,870,872	124,113,792	123,345,383
Other services rendered	10,618,776	10,794,560	10,630,203	99,664,711	80,836,140	68,402,846	(1,506,642)	2,928,589	5,903,939	108,776,845	94,559,289	84,936,988
Other operating income	33,774,469	145,380,545	40,300,955	5,642,787	4,283,696	8,280,468	(2,399,376)	(3,406,204)	(1,780,456)	37,017,880	146,258,037	46,800,967
RAW MATERIALS AND CONSUMABLES USED	(616,852,308)	(678,187,609)	(709,506,221)	(1,116,324,483)	(1,114,936,281)	(972,499,918)	358,731,152	371,918,639	389,829,023	(1,374,445,639)	(1,421,205,251)	(1,292,177,116)
Energy purchases	(177,049,909)	(160,044,206)	(213,114,437)	(1,060,494,642)	(1,056,562,636)	(926,385,346)	372,681,097	381,322,099	391,853,181	(864,863,454)	(835,284,743)	(747,646,602)
Fuel consumption	(231,176,490)	(230,944,414)	(231,028,169)	—	—	—	—	—	—	(231,176,490)	(230,944,414)	(231,028,169)
Transportation expenses	(113,704,101)	(169,062,680)	(154,044,158)	(23,694,571)	(22,725,942)	(9,816,883)	(4,141,015)	(5,060,166)	(3,014,761)	(141,539,687)	(196,848,788)	(166,875,802)
Other miscellaneous supplies and services	(94,921,808)	(118,136,309)	(111,319,457)	(32,135,270)	(35,647,703)	(36,297,689)	(9,808,930)	(4,343,294)	990,603	(136,866,008)	(158,127,306)	(146,626,543)
CONTRIBUTION MARGIN	960,569,955	1,048,423,899	871,146,867	265,743,737	297,935,457	290,724,154	(15,357,134)	3,269,753	3,113,289	1,210,956,558	1,349,629,109	1,164,984,310
Other work performed by the entity and capitalized	15,581,738	8,887,421	8,663,737	9,805,315	8,723,440	6,667,947	152,263	—	1,379,279	25,539,316	17,610,861	16,710,963
Employee benefits expense	(65,564,485)	(62,871,525)	(61,991,737)	(37,496,730)	(34,828,194)	(32,598,818)	(34,165,533)	(31,905,237)	(28,539,779)	(137,226,748)	(129,604,956)	(123,130,334)
Other expenses	(121,366,276)	(120,522,841)	(104,190,567)	(79,580,559)	(70,678,241)	(64,179,201)	10,353,501	7,057,942	1,159,747	(190,593,334)	(184,143,140)	(167,210,021)
GROSS OPERATING INCOME	789,220,932	873,916,954	713,628,300	158,471,763	201,152,462	200,614,082	(39,016,903)	(21,577,542)	(22,887,464)	908,675,792	1,053,491,874	891,354,918
Depreciation and amortization expense	(185,479,080)	(196,623,025)	(179,901,682)	(45,583,947)	(40,705,580)	(36,677,957)	1,106,008	701,218	1,392,339	(229,957,019)	(236,627,387)	(215,187,300)
Impairment losses (reversal of impairment losses) recognized in profit or loss	(698,453,039)	(280,020,263)	—	—	—	—	646,598	(742,389)	(779,825)	(697,806,441)	(280,762,652)	(779,825)
Impairment gains and reversals of impairment losses (Impairment losses) determined in accordance with IFRS 9.	(1,305,341)	(1,338,599)	(106,264)	(12,998,719)	(8,153,419)	(4,676,808)	(863,647)	(554,982)	—	(15,167,707)	(10,047,000)	(4,783,072)
OPERATING INCOME	(96,016,528)	395,935,067	533,620,354	99,889,097	152,293,463	159,259,317	(38,127,944)	(22,173,695)	(22,274,950)	(34,255,375)	526,054,835	670,604,721
FINANCIAL RESULT	(80,090,891)	(101,324,905)	(86,621,659)	5,929,058	5,232,127	6,088,801	(38,272,941)	(54,800,225)	(30,342,206)	(112,434,774)	(150,893,003)	(110,875,064)
Financial income	15,080,015	15,241,046	8,727,356	22,717,208	22,742,687	11,166,433	(1,636,763)	(10,584,458)	40,679	36,160,460	27,399,275	19,934,468
Cash and cash equivalents	597,718	3,556,554	5,673,621	1,562,194	1,456,253	1,633,373	5,164,145	3,960,799	2,305,581	7,324,057	8,973,606	9,612,575
Other financial income	14,482,297	11,684,492	3,053,735	21,155,014	21,286,434	9,533,060	(6,800,908)	(14,545,257)	(2,264,902)	28,836,403	18,425,669	10,321,893
Financial costs	(59,088,322)	(111,219,566)	(82,878,715)	(17,696,544)	(19,061,123)	(6,724,490)	(50,623,905)	(34,617,211)	(32,580,984)	(127,408,771)	(164,897,900)	(122,184,189)
Bank borrowings	(7,112,931)	(11,813,855)	(9,269,535)	(33,244)	(40,508)	(5,374)	(4,855)	(2,633,337)	(11,426,865)	(7,151,030)	(14,487,700)	(20,701,774)
Secured and unsecured obligations	(47,654,290)	(45,714,879)	(43,965,839)	—	—	—	(36,613,957)	(36,103,685)	(18,289,461)	(84,268,247)	(81,818,564)	(62,255,300)
Others	(4,321,101)	(53,690,832)	(29,643,341)	(17,663,300)	(19,020,615)	(6,719,116)	(14,005,093)	4,119,811	(2,864,658)	(35,989,494)	(68,591,636)	(39,227,115)
Income from indexation units	(703,130)	(5,157,076)	(2,480,291)	1,124,304	1,843,435	1,616,607	1,664,594	331,373	45,538	2,085,768	(2,982,268)	(818,146)
Foreign exchange profits (losses)	(35,379,454)	(189,309)	(9,990,009)	(215,910)	(292,872)	30,251	12,323,133	(9,929,929)	2,152,561	(23,272,231)	(10,412,110)	(7,807,197)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	2,424,250	366,089	3,190,240	—	—	—	1,085,142	—	—	3,509,392	366,089	3,190,240
Other gains (losses)	9,478,528	1,683,246	3,434,503	10,287	12	—	—	109,943	(24,124)	9,488,815	1,793,201	3,410,379
Gain (loss) from other investments	94,490	152,557	409,954	10,287	12	—	—	109,943	(24,124)	104,777	262,512	385,830
Gain (loss) from the sale of assets	9,384,038	1,530,689	3,024,549	—	—	—	—	—	—	9,384,038	1,530,689	3,024,549
Profit (loss) before taxes	(164,204,641)	296,659,497	453,623,438	105,828,442	157,525,602	165,348,118	(75,315,743)	(76,863,977)	(52,641,280)	(133,691,942)	377,321,122	566,330,276
Income tax	97,419,625	(40,347,869)	(113,783,941)	(23,421,217)	(38,748,555)	(42,967,123)	7,306,699	17,868,520	3,268,545	81,305,107	(61,227,904)	(153,482,519)
PROFIT (LOSS)	(66,785,016)	256,311,628	339,839,497	82,407,225	118,777,047	122,380,995	(68,009,044)	(58,995,457)	(49,372,735)	(52,386,835)	316,093,218	412,847,757
	—		—	—		—	—		—	—	—	—
Profit (loss) attributable to	(66,785,016)	256,311,628	339,839,497	82,407,225	118,777,047	122,380,995	(68,009,044)	(58,995,457)	(49,372,735)	(52,386,835)	316,093,218	412,847,757
Profit (loss) attributable to owners of the parent	—	—	—	—	,	—	—	—	—	(50,860,313)	296,153,605	361,709,937
Profit (loss) attributable to non-controlling interests	—	—	—	—	—	—	—	—	—	(1,526,522)	19,939,613	51,137,820
	Generation			Distribution			Holdings eliminations			Total
	12-31-2020	12-31-2019	12-31-2018	12-31-2020	12-31-2019	12-31-2018	12-31-2020	12-31-2019	12-31-2018	12-31-2020	12-31-2019	12-31-2018
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENT OF CASH FLOWS
Net cash flows from (used in) operating activities	551,979,917	754,113,794	638,607,494	111,689,249	50,246,845	117,692,384	92,197,032	(60,648,920)	(20,774,356)	755,866,198	743,711,719	735,525,522
Net cash flows from (used in) investing activities	(100,557,328)	(426,038,012)	(451,284,432)	(111,939,127)	(28,896,947)	(123,070,452)	(342,154,935)	143,403,148	(1,307,204,810)	(554,651,390)	(311,531,811)	(1,881,559,694)
Net cash flows from (used in) financing activities	(469,832,875)	(453,927,358)	(249,051,150)	1,578,034	(23,901,991)	(32,268,227)	340,585,507	37,393,661	1,247,896,253	(127,669,334)	(440,435,688)	966,576,876

The Holding, Eliminations and Others column corresponds to transactions between companies in different lines of business and country, primarily purchases and sales of energy and services.

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36.  GUARANTEES WITH THIRD PARTIES, CONTINGENT ASSETS AND, LIABILITIES, AND OTHER COMMITMENTS

36.1 Direct guarantees

As of December 31, 2020, Enel Chile had future energy purchase commitments amounting to ThCh$6,458,055,505 (ThCh$7,647,064,710 as of December 31, 2019).

36.2 Indirect guarantees

			Debtor			Outstanding balance as of
Contract	Maturity	Creditor of Guarantee	Company	Relationship	Type of Guarantee	Currency	12-31-2020	12-31-2019
Bonds Series B (*)	October 2028	Bondholders of Enel Américas’ Bonds	Enel Américas	Entities demerged from original debtor Enersis S.A. (codebtor Enel Chile S.A.)	Codebtor	UF	7,672,851	11,646,991
Credit agreement	December 2020	Scotiabank Chile	Enel Green Power Chile S.A.	Subsidiary	Guarantor	USD	-	112,882,048
Credit agreement	November 2022	Pto. GDN BID	Enel Green Power Chile S.A.	Subsidiary	Guarantor	USD	21,368,491	22,592,723
Credit agreement	December 2021	Scotiabank Chile	Enel Green Power Chile S.A.	Subsidiary	Guarantor	USD	106,811,188	113,069,511
Guarantee contract	December 2027	Enel Finance International N.V.	Enel Green Power Chile S.A.	Subsidiary	Guarantor	USD	458,115,841	484,341,824

(*)Upon the demerger of the original issuer, Enersis (currently Enel Américas), and in accordance with the bond indenture, all entities arising from the demerger are liable for the debt, regardless of the fact that that the payment obligation remains in Enel Américas

36.3 Lawsuits and Arbitration Proceedings

As of the date of these consolidated financial statements, the most relevant litigation involving the Company and its subsidiaries are as follows:

1. Inversiones Tricahue filed a tort liability lawsuit against Enel Chile S.A., claiming its alleged liability for the economic losses suffered as a result of the corporate restructuring. In this lawsuit, Inversiones Tricahue and its subsidiary seek ThCh$72,558,025 and ThCh$12,431,395, respectively. The claim was notified on October 29, 2020. Enel Chile S.A. filed a plea claiming that this matter was not under the jurisdiction of the court, which was rejected by the court on December 22, 2020. Enel Chile S.A. filed an appeal, which is pending hearing and ruling. On January 5, 2021, the lawsuit was answered.

2. Mrs. Evelyn del Carmen Molina González, on behalf of herself and her minor daughters Maite Alué Letelier Molina and Daniela Anaís Letelier Molina, filed a claim for compensation of damages against Chilectra S.A. (currently Enel Distribución Chile S.A.) and its subcontractor Sociedad de Servicios Personales para el Área Eléctrica Limitada (“SSPAEL”) for a total amount of ThCh$2,000,000  (ThCh$1,000,000 for the first plaintiff and  ThCh$500,000 for  each of the latter two plaintiffs) for punitive damages due to the death of their spouse and father, respectively, Mr. David Letelier Riveros (deceased), which occurred on May 25, 2013 as a result of the injuries sustained after receiving an electric shock and falling from the height of a public street lighting post on which he was working. A judgment was issued on November 7, 2017 which found SSPAEL and Enel Distribución Chile (Chilectra) jointly liable to pay the sum of ThCh$90,000 for punitive damages to the plaintiffs , plus adjustments and costs. On November 24, 2017 Enel Distribución Chile filed an appeal against the judgment, submitting the background information to the Court of Appeals of Santiago, on December 4, 2017. On December 21, 2018 the judgment was confirmed by the Court of Appeals reducing the punitive damages to ThCh$70,000. On January 10, 2019 an appeal was filed. (14th Civil Court of Santiago, Case C-7304-2014).

3. Mrs. Ximena Acevedo Herrera, Benjamín Jiménez Acevedo, Francisco Jiménez Acevedo, Nancy Garrido Muñoz, Juan Carlos Jiménez Rocuant, Carolina Jiménez Garrido and Natalia Jiménez Garrido filed a claim for compensation of damages against Ingeniería Eléctrica Azeta Ltda and Enel Distribución Chile S.A. for a total amount of ThCh$878,227   (ThCh$28,227) for loss of profits and ThCh$850,000 for punitive damages) due to the death of their spouse, father, son, and brother, Mr. Juan Pablo Jiménez Garrido (deceased), which occurred on February 22, 2013 as a result of a head trauma caused by a bullet that was lodged in his brain. Enel Distribución Chile S.A. is a defendant in its capacity as the contractor of Azeta. The trial period is over. The motion for abandonment of the proceedings is pending service on the plaintiff. (5th Civil Court of Santiago, Case C-233-2017).

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4. Mr. Víctor Hugo Coronado González and Mrs. Francia Magali Bustos Uribe, both on behalf of themselves and their minor daughter, Nicolson Rocío Coronado Bustos, and son, Víctor Ignacio Coronado Bustos, filed a claim for compensation of damages against Enel Distribución Chile S.A. for a total amount of ThCh$704,860 (ThCh$264,860 for loss of profits and ThCh$440,000 for punitive damages) due to an accident that occurred on June 22, 2015 that affected Mr. Coronado who received an electrical shock and suffered severe injuries. The trial period is over. A judgment of May 22, 2019 dismissed the lawsuit against Enel Distribución Chile S.A. On June 19, 2019, the plaintiffs filed an appeal, which is pending resolution. (7th Civil Court of Santiago, Case C-15965-2017).

5. Inmobiliaria Proyecto CR S.A. filed a claim for breach of contract and damages against Enel Distribución Chile S.A., in connection with contracts for the supply of electricity in the properties located at Lot 7A1, the entrance of which is located at Avenida Camino Real No. 4690 and Lot 7A2, the entrance of which is located at Avenida Camino Real No. 4680, district of Lo Barnechea. This company requested that Enel Distribución Chile S.A. pay UF 253,422, which is equivalent to ThCh$7,367,061. On September 12, 2020, the claim was answered. The discussion period concluded and the conciliation hearing is pending. (29th Civil Court of Santiago, Case No. C-15986-2020).

6. By means of Exempt Resolution No. 21,036 dated November 3, 2017, the Superintendency of Electricity and Fuels confirmed a fine of 35,611 UTM (ThCh$1,817,194) imposed on Enel Distribución Chile S.A. upon issuing a ruling against the request for reconsideration filed on January 14, 2016 against Exempt Resolution No. 11,750 dated December 29, 2015 because it determined that, in the period 2013-2014, Enel Distribución Chile had repeatedly exceeded the continuity of supply indices established by law. In opposition to this ruling, Enel Distribución Chile filed an appeal with the Court of Appeals of Santiago on November 28, 2017. On April 21, 2019, the expert witness submitted a report, which the Court of Appeals of Santiago accepted on April 30, 2019. On June 21, 2019 the claim was ready to be heard by the court. On June 26, 2019, the Constitutional Court issued a ruling, which gives effect to the principle of inapplicability due to unconstitutionality presented by Enel Distribución Chile. On June 28, 2019, the Court of Appeals of Santiago accepted the ruling issued by the Constitutional Court and thereby ordered the suspension of the proceeding, through an official letter to the Constitutional Court issued on June 28, 2019. On November 7, 2019, the Constitutional Court rejected the appeal for inapplicability due to unconstitutionality, resuming the litigation proceeding on November 22, 2019. Arguments were heard on January 16, 2020. On September 8, 2020, the court decided to reject the action filed by Enel Distribución Chile, and on September 22, 2020, Enel Distribución Chile filed an appeal against the decision. On October 20, 2020, the case was submitted to the Supreme Court. On November 5, 2020, the pleadings were held and the case was settled. On November 20, 2020, the court requested a report to the Superintendency, which should indicate the mathematical formula used by the Superintendency to apply the fines on the regulated parties. The report is intended to serve as a measure to facilitate judgment, and was issued on December 10, 2020, where Enel Distribución Chile S.A. made remarks on the contents on December 16, 2020. To date, the Court has not issued a ruling on the appeal.

7. By means of Exempt Resolution No. 24,805 dated July 20, 2018, the Superintendence of Electricity and Fuels confirmed a fine imposed on Enel Distribución Chile S.A. for 80,000 UTM (ThCh$4,082,320) when it issued a ruling against the request for reconsideration filed against Exempt Resolution No. 21,788 dated December 29, 2017 because it determined that Enel Distribución Chile S.A kept more than 100,000 customers without electricity supply for a period exceeding 20 hours, in relation to the power outage that occurred on July 15, 2017 (the snowstorm event). In opposition to this ruling, Enel Distribución Chile S.A filed an appeal with the Court of Appeals of Santiago on August 7, 2018. On March 7, 2019, Enel Distribución Chile S.A requested the court to appoint a new civil electrical engineer expert, who was appointed in a resolution dated March 15, 2019. The expert was notified on July 3, 2019 and accepted the appointment and proposed his fees on August 16, 2019. The court gave notice to the parties, and on September 5, 2019 the parties responded and accepted the expert’s fees and payment method. On November 28, 2019, the hearing to acknowledge this matter was held and subsequently on December 20, 2019, a certification of the end of the trial period was requested, which was issued by the clerk on January 7, 2020. On January 29, 2020, the appointed expert witness submitted his report. On February 5, 2020, Enel Distribución Chile S.A. requested the joinder of proceedings with case IC 339-2018 and to be heard at the Court of Appeals of Santiago, where the Superintendency imposed a fine on Enel Distribución Chile S.A. of

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10,000 UTM (ThCh$510,290) , with respect to events that also occurred during the wind and snow storm of July 2017. On February 6, 2019, the Court of Appeals of Santiago deemed the expert's report to have been issued and, with respect to the request for joinder of proceedings, requested the clerk to issue the corresponding certification. On February 10, 2020, the attesting official certified that, although there is a close relationship between the appeals, they challenged different administrative acts. By means of a resolution dated February 7, 2020, the Court of Appeals denied the request for joinder and on February 21, 2020, Enel Distribución Chile S.A. filed another appeal. In this regard, the Court of Appeals of Santiago gave notice to the Superintendency - dated February 27, 2020 - requesting its opinion on the matter. On March 12, 2020, it was certified that the Superintendency did not respond. On March 18, 2020, by means of a writ containing a petition that due note should be taken, Enel Distribución Chile S.A. suggested to the Court of Appeals certain points on which its decision to accept our motion for reconsideration should be based. On July 23, 2020, the court resolved to grant another hearing in respect of case 339-2018, joining the hearing of these two cases. On July 29, 2020, Enel Distribución Chile S.A. deposited the expert's money, thus fulfilling the obligation to pay the expert's fee. On August 5, 2020, the court noted that the payment was made and requested certification from the clerk of the court to determine whether the entire obligation regarding the payment of the expert had been fulfilled. On August 20, 2020, Enel Distribución Chile S.A. requested that the funds corresponding to the expert's services be transferred to the name of the expert and that the check be drawn. On August 21, 2020, the court pointed out that there were inconsistencies between the amounts and the deposit and asked for clarification. On August 26, 2020, Enel Distribución Chile S.A. filed a written statement clearing up such inconsistencies. On September 21, 2020, the court deemed the order to have been complied with, requesting the corresponding certification, certifying that the money was ready to be delivered to the expert on September 24, 2020. On October 2, 2020, it was finally resolved that the check had to be issued to the expert as payment for his report, which was delivered to the expert on November 16, 2020.

8. By means of Exempt Resolution No. 24,821 dated July 23, 2018, the Superintendency of Electricity and Fuels confirmed the fine imposed on Enel Distribución Chile S.A. of 10,000 UTM, (ThCh$510,290), when it issued a ruling against the request for reconsideration filed against Exempt Resolution No. 21,790 dated December 29, 2017 because it determined that Enel Distribución Chile S.A did not provide adequate and timely customer service during the power outage that occurred on July 15, 2017 (the snowstorm event), which resulted from not having adequate customer service and information systems. In opposition to this resolution, Enel Distribución Chile S.A filed an appeal with the Court of Appeals of Santiago on August 7, 2018. On February 1, 2019 Enel Distribución Chile S.A presented a list of witnesses, and such evidence was received on February 8, 2019, when Enel Distribución Chile S.A also requested a hearing for the appointment of an expert. The request was accepted and the Court hearing was scheduled for February 13, 2019. On February 28, 2019, Enel Distribución Chile S.A requested again that the Court appoint an expert, following the non-appearance of the counterparty at the hearing to designate an expert. On March 7, 2019, an expert was appointed, who accepted the appointment and proposed his fees on March 17, 2019. The Court acknowledged the acceptance of the appointment in a resolution dated March 25, 2019. On September 6, 2019, Enel Distribución Chile S.A recorded 50% of the expert’s fees, which the Court made effective on September 24, 2019. On November 27, 2019, the expert received the corresponding payment. On March 24, 2020, the Court of Appeals of Santiago suspended the procedure ex officio, based on the health emergency. On April 18, 2020, the appointed expert witness submitted his report, which was deemed to have been submitted on May 26, 2020, date on which the procedure resumed and the clerk was requested to certify whether the trial period had expired. On June 2, 2020 the expiration was certified, leaving the case ready to be reported on by the reporting judge. On June 22, 2020, Enel Distribución Chile S.A. submitted to the court the joinder request made in case IC No. 340-2018, determining in this case a schedule for the hearing of case IC No. 340-2018 on July 23, 2020. On July 29, 2020, money was deposited for the expert, which was requested on August 20, 2020, and it was resolved on September 11, 2020, that prior to the drawing of the check it was necessary to certify whether the corresponding amount was deposited, which was certified by the secretary of the court on October 8, 2020. Finally, in view of what was already certified, the drawing of the check was requested again on October 22, 2020, and the check was delivered to the expert on November 16, 2020

9. By means of Exempt Resolution No. 24,246 dated June 13, 2018, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 2,000 UTM (ThCh$102,058)  for operating its facilities in violation of current electrical regulations, by not maintaining its facilities in good condition, as evidenced by the electric shock produced in the insulator of portal No. 74 of the 110 Kv Cerro Navia-Lo Prado line, attributed to

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contamination from bird droppings, which affected the electricity supply of customers for more than 2 hours. In opposition to this resolution, Enel Distribución Chile S.A filed a request for reconsideration, which was rejected by Exempt Resolution No. 28,857 dated April 23, 2019. On May 14, 2019, an appeal was filed with the Court of Appeals of Santiago. On June 5, 2019, a resolution was issued that received the appeal and requested a report from the Superintendency of Electricity and Fuels. On July 24, 2019, the Superintendency of Electricity and Fuels issued a report, and the claim was ready to be heard on August 20, 2019. On October 29, 2019, the allegations of the parties were heard and subsequently, on December 6, 2019, the Court of Appeals of Santiago issued a ruling rejecting the appeal filed.  On December 18, 2019, Enel Distribución Chile S.A. filed an appeal requesting a hearing and judgment with the Supreme Court. On January 15, 2020, arguments were heard, the case was ready for judgment and Judge Sergio Muñoz Gajardo was appointed to draft the ruling. On May 25, 2020, the Supreme Court issued its ruling, confirming the fine imposed by the Superintendency. On October 28, 2020, the judgment of the Supreme Court was ordered for compliance. The payment of the fine is pending.

10. By means of Exempt Resolution No. 31,912, dated February 20, 2020, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 1,000 UTM (approx. ThCh$51,029), because it considered that Enel Distribución Chile S.A. had not complied with its obligation to maintain the medium voltage poles located in the district of Cerro Navia in good condition. Likewise, the Superintendency considered that Enel Distribución Chile S.A. committed a second violation when it found that connection conductors of circuits were not protected against current overloads, located in the same district. Against this resolution, Enel Distribución Chile S.A. filed an appeal before the Court of Appeals of Santiago, which was heard in IC No. 142-2020, and was the subject of a procedural order on April 21, 2020, requesting a report from the Superintendency, which issued it on April 28, 2020. The case was ready to be reported on by the reporting judge on May 4, 2020, and on July 21, 2020, the arguments of the case were heard, and the case was ready for judgment. On July 29, 2020, the court rejected Enel Distribución Chile S.A.'s arguments On August 10, 2020, the judgment of the Court of Appeals was appealed. On September 8, 2020, Enel Distribución Chile S.A. filed an appeal with the Supreme Court under case number 119225-2020, and it was ready to be reported on by the reporting judge since September 24, 2020, and on September 29, 2020, pleadings were scheduled for October 5, 2020. On that date, pleadings were held, where the ruling of the Court of Appeals was finally confirmed. On November 9, 2020, the Supreme Court's sentence was ordered for compliance. The payment of the fine is pending.

11. By means of Exempt Resolution No. 21,789 dated December 29, 2017, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 20,000 UTM (approximately ThCh$1,020,580), for providing erroneous information to the regulatory body regarding the supply restoration, in relation to the outage that occurred on July 15, 2017 (snowstorm). Enel Distribución Chile S.A. filed a request for reconsideration against this resolution, which was partially accepted in Exempt Resolution No. 32,515, setting the fine at 10,000 UTM (ThCh$ 510,290). An appeal against this resolution was filed with the Court of Appeals of Santiago under Case Number 450-2020 on August 19, 2020, certifying the necessary judicial deposit for this type of claims on September 24, 2020. On October 2, 2020, the claim was processed, and a report was requested from the Superintendency on October 6, 2020, which was issued on October 20, 2020, and the case entered the reporting stage on October 21, 2020. Subsequently, the case was subject to hearing on November 25, 2020, where parties declared their arguments o To date, this case remains ready for judgment to date.

12. By means of Exempt Resolution No. 27,005 dated December 28, 2018 (received on January 28, 2019) the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 16,911 UTM (ThCh$862,951), for estimating that Enel Distribución Chile S.A. exceeded the standard established in the supply continuity index for the period 2015-2016. Enel Distribución Chile S.A. filed a request for reconsideration against this resolution, which was rejected in Exempt Resolution No. 32,760. Consequently, an appeal was filed against this resolution with the Court of Appeals of Santiago under Case Number 493-2020 on September 9, 2020. On September 10, 2020, a brief was submitted, which stated that the judicial deposit could not be made due to the computer problem of Banco Estado, accompanying a certificate from Banco Estado that reported the situation. On September 29, 2020, the deposit slip was attached. On October 5, 2020, the court requested that the deposit was certified, confirming that the deposit did not appear until October 7, 2020. On October 9, 2020, the court resolved that prior to issuing a procedural resolution, the deposit should be accounted for, resolution of which was sent on October 14, 2020, providing an additional certification that the amount had been deposited, and

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certifying on October 21, 2020 that the amounts had indeed been deposited. On October 26, 2020, the court again issued a warning, requesting Enel Distribución Chile S.A. to report the date on which it was notified of the resolution it was appealing. Enel Distribución Chile S.A. complied with the court's order on October 29, 2020.

13. By means of Exempt Resolution No. 32,555 dated May 13, 2020, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 10,000 UTM (approx. ThCh$510,290), because it considered that Enel Distribución Chile S.A. operated its owned facilities in violation of the electric regulations in force, by failing to maintain in good condition its facilities 11Kv El Salto- Almendros line on July 28, 2018, affecting 233,000 customers with this action. In addition, the resolution also included a penalty for delivering erroneous information to the National Electric Coordinator. Enel Distribución Chile S.A. filed a request for reconsideration, which was rejected by the authority through Exempt Resolution No. 33,230 dated August 31, 2020. Consequently, an appeal against such resolution was filed with the Court of Appeals of Santiago under Case Number 524-2020 on September 16, 2020. On September 24, 2020, Enel Distribución Chile S.A. was warned to correct the petition of the written document since the Exempt Resolution had been misidentified, and on September 29, 2020, Enel Distribución Chile S.A. complied with the order.

On October 6, 2020, it was certified that the money required to file the claim had been deposited. On October 9, 2020, the court again determined that the resolution dated September 24, 2020 had to be fully complied with, and therefore requested that Enel Distribución Chile S.A. complied with the order to set the date of notification of Resolution No. 332,030. Once the order was complied with on October 14, 2020, the court determined on October 29, 2020 that the claim was untimely, and therefore declared it inadmissible. On November 3, 2020, Enel Distribución Chile S.A. filed an alternative appeal to this resolution, which was rejected by the court on November 5, 2020, and consequently, the case was submitted to the Supreme Court for review of the admissibility of the claim. On November 20, 2020, the case was submitted to the Supreme Court under Case Number 138642-2020 of the Supreme Court. On December 1, 2020, the case was heard, and during the same day the court issued its judgment, in which Enel Distribución Chile S.A.’s arguments were rejected. However, the Supreme Court emended the decision of the Court of Appeals because, in its view, the deadlines were not appropriately calculated. As a result, given the criterion that was used by the Supreme Court, it was understood that the claim was filed within the deadline; therefore, it was declared to be admissible. On December 21, 2020, the Court of Appeals issued the order of enforcement.

14. By means of Exempt Resolution No. 33,048 dated August 5, 2020, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 1000 UTM (approx. ThCh$51,029), for considering that Enel Distribución S.A. is responsible for the poor condition of the power lines at 584 Atom Street, Maipú, for not maintaining the power poles in good condition which, in the Superintendency 's opinion, caused injuries to a 3-year old child and an 18-year old boy, who had indirect contact with the power lines. Enel Distribución Chile S.A. filed a request for reconsideration against this resolution, which was rejected by Exempt Resolution No. 33,404 dated October 7, 2020. Consequently, an appeal was filed against such resolution with the Court of Appeals of Santiago under Case Number 673-2020 on October 31, 2020, certifying the necessary deposit for this type of claim on November 6, 2020.

15. By means of Exempt Resolution No. 32,976 dated July 24, 2020, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 40,000 UTM (ThCh$2,041,160), for considering that Enel Distribución Chile S.A. did not comply with the provisions of Article 72-14 of the Electric Services Law, violation that occurred when it did not have the measurement of 80% of its feeders, within 18 months from the publication of the technical standard of service quality for the distribution system in the Official Gazette. Enel Distribución Chile S.A. filed a request for reconsideration, which was rejected by Exempt Resolution No. 33,498 dated October 27, 2020. Consequently, an appeal was filed against such resolution with the Court of Appeals of Santiago under Case Number 711-2020 on November 13, 2020, and the necessary deposit for this type of appeal was certified on November 17, 2020. On November 18, 2020, the claim was processed, requesting a report from the Superintendency, which was issued on December 1, 2020, and the case decision was referred to the reporting judge on December 4, 2020, and its hearing was scheduled for December 16, 2020. The hearing of the case was suspended by the Superintendency on December 15, 2020, pending its return to the docket.

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In relation to the litigation proceedings described above, the Group has established provisions for ThCh$10,882,854 as of December 31, 2020 (see Note 25). There are other sanctions that also have associated provisions but they are not described in this note since they individually represent immaterial amounts. Management believes that the provisions recorded adequately cover the risks due to penalties. Therefore, they do not expect additional liabilities to arise from other than those already registered.

Because of the characteristics of the risks covered by these provisions, it is not possible to determine a reasonable payment schedule, if any.

36.4. Financial restrictions.

Several debt contracts of the Company, and of some of its subsidiaries include the obligation to comply with certain financial ratios, which is common in contracts of this nature. There are also affirmative and negative covenants that require monitoring of these commitments. In addition, there are restrictions in the sections of events of default that must be fulfilled to avoid acceleration of the debt.

1.Cross Default

Some of the financial debt contracts contain cross default clauses.

Enel Chile's committed international credit facility under the law of the State of New York, entered into in June 2019 and expiring in June 2024, indicates that cross default for non-payment could be triggered by another debt of the same company, for any amount in default, provided that the principal amount of the debt giving rise to the cross default exceeds US$150 million in an individual debt, or its equivalent in other currencies. To accelerate the debt under this facility due to cross default on other debt, the amount in default on an individual debt must exceed US$150 million, or its equivalent in other currencies, and other conditions must also be satisfied, including the expiration of grace periods (if any in the defaulted contract), and a formal notice of the intention to accelerate the debt by creditors representing more than 50% of the amount due or committed under each contract. As of December 31, 2020, this credit line was not disbursed.

For Enel Chile's bonds registered with the Securities and Exchange Commission ("SEC") of the United States of America, commonly referred to as "Yankee Bonds", cross default for non-payment could be triggered by other debt of the same company, or any of its Chilean subsidiaries, for any amount in default, provided that the principal amount of the debt giving rise to the cross default exceeds US$ 150 million in an individual debt, or its equivalent in other currencies. Acceleration of the debt due to cross default is not automatic but must be required by the holders of at least 25% of the bonds of a certain series of Yankee Bonds. Enel Chile's Yankee Bond matures in 2028. At December 31, 2020, the amount due on the Yankee Bond totals ThCh$697,736,223.

For Enel Generación Chile's bonds registered with the Securities and Exchange Commission ("SEC") of the United States of America, commonly referred to as "Yankee Bonds", cross default for non-payment could be triggered by other debt of Enel Generación Chile, or any of its Chilean subsidiaries, for any amount in default, provided that the principal amount of the debt giving rise to the cross default exceeds US$ 30 million in an individual debt, or its equivalent in other currencies. Acceleration of debt due to cross default is not automatic but must be required by the holders of at least 25% of the bonds of a certain series of Yankee Bonds. Enel Generación Chile's Yankee Bonds mature in 2024, 2027, 2037 and 2097. In the case of the Yankee Bond maturing in 2024 (issued in April 2014), the principal amount of the debt individually giving rise to the cross default is US$50 million, or its equivalent in other currencies. As of December 31, 2020, the amount due on the Yankee Bonds totals ThCh$510,368,873.

Enel Generación Chile's bonds issued in Chile stipulate that cross default can be triggered only by the Issuer's own default, in cases where the amount in default exceeds US$ 50 million in an individual debt, or its equivalent in other currencies. In turn, the acceleration must be required at a bondholders' meeting by the holders of at least

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50% of the bonds of a given series. As of December 31, 2020, the amount owed for local bonds totals ThCh$283,294,982.

The bank borrowing that Enel Green Power Chile subscribed in February 2017 for US$30 million stipulates that cross default is triggered by default of the Debtor itself, i.e. Enel Green Power Chile, or of any material subsidiary, as contractually defined. To accelerate this debt due to cross default originating from other debt, the amount in default, whether on an individual debt or at the aggregate debt level, must exceed US$50 million, or its equivalent in other currencies. As of December 31, 2020, the amount outstanding on this borrowing totals ThCh$21,354,969.

Enel Distribución Chile's uncommitted credit lines stipulate that cross default may be triggered by a default of the Issuer's own individual debt in any obligation contracted in favor of any creditor. Upon the occurrence of the event of default, the bank will communicate to Enel Distribución Chile about the termination of the credit line. As of December 31, 2020, these credit lines were not disbursed.

2.Financial covenants

Financial covenants are contractual commitments with respect to minimum or maximum financial ratios that the Company is obliged to meet at certain periods of time (quarterly, annually, etc.) and in some cases only when certain conditions are met. Most of the financial covenants of the Company limit leverage and track the ability to generate cash flow that will service the companies’ indebtedness. Certain companies are also required to periodically certify these covenants. The types of covenants and their respective limits vary according to the type of debt and contract.

The Enel Generación Chile’s bonds issued in Chile include the following financial covenants, whose definitions and calculation formulas are set out in the respective contracts:

H Series

- Consolidated Indebtedness Level: The Financial Obligations to Total Capitalization ratio must remain equal to or less than 0.64. Financial Obligations is the sum of Current interest-bearing loans, Non-current interest-bearing loans, Other current financial liabilities, Other non-current financial liabilities, and Other obligations secured by the Issuer or its subsidiaries, while Total Capitalization is the sum of Financial Obligations and Total Equity. As of December 31, 2020, the Indebtedness Level was 0.31.

- Consolidated Equity: A Minimum Equity of Ch$761,684 million must be maintained, a limit adjusted at the end of each year as established in the indenture. Equity corresponds to net Equity attributable to the owners of the controller. As of December 31, 2020, the net Equity attributable to the owners of Enel Generación Chile's controller was Ch$1,729,218 million.

- Finance Expense Hedge Ratio: The company must maintain a Finance Expense Hedge Ratio equal to or greater than 1.85 The hedging of finance expenses is the quotient between: i) the Gross operating revenue, plus Finance revenue and dividends received from associated companies, and, ii) Financial expenses; both with respect to the period of four consecutive quarters ending at the close of the reporting quarter. As of December 31, 2020, this ratio was 19.75.

- Net Asset Position with Related Companies: A Net Asset Position with Related Companies must be maintained at or below the equivalent sum in Chilean pesos of US$500 million, according to the exchange rate prevailing at the date of calculation. The Net Asset Position with Related Companies is the difference between: i) the sum of Current Accounts Receivable from Related Companies and Non-Current Accounts Receivable from Related Companies and ii) the sum of Current Accounts Payable to Related Companies and Non-Current Accounts Payable to Related Companies. The foregoing must exclude the corresponding amounts that meet all of the following requirements: i) transactions with a duration of less than 180 days; and ii) transactions referring to balances in the barter accounts, documents and accounts of Enel Generación Chile or its subsidiaries, resulting from the ordinary course of business of Enel Generación Chile or its subsidiaries.

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Likewise, it must also exclude the transactions of the associated companies of Enel Generación Chile and its subsidiaries, as long as Enel Chile S.A. has no interest in the respective associated company, whether directly or indirectly through a subsidiary or associate of Enel Chile S.A., other than Enel Generación Chile and its subsidiaries. As of December 31, 2020, considering the exchange rate prevailing at that date, the Net Asset Position with Related Companies was US$244.15 million, indicating that Enel Generación Chile is a net creditor for its related companies.

M Series

-Consolidated Debt Level: Idem H Series.

-Consolidated Equity: Idem H Series.

-Finance Expense Hedge Ratio: Idem H Series.

The “Yankee Bonds” issued by Enel Generación Chile and Enel Chile are not subject to compliance with financial covenants.

As of December 31, 2020, Enel Generación Chile’s most restrictive financial covenant was the Consolidated Indebtedness Level.

The rest of the Group’s companies not mentioned in this Note are not subject to compliance with financial covenants.

Finally, in most of the contracts, debt acceleration due to non-compliance with these covenants does not occur automatically, but rather certain conditions must be met, such as the expiration of the remedial periods established therein, among other conditions.

As of December 31, 2020, neither Enel Chile or its subsidiaries record non-compliance with the financial covenants summarized herein, or with any other financial obligations that could lead to the accelerated maturity of its financial commitments.

36.5. COVID-19 contingency

On January 30, 2020, the World Health Organization (WHO) declared the outbreak of the new coronavirus 2019, or COVID-19, to be a "Public Health Emergency of International Concern." On March 11, 2020, the WHO confirmed that the outbreak of COVID-19 had reached the level of a pandemic, which could significantly affect Chile, as well as the Company’s commercial partners within and outside the country.

To address this international public health emergency due to COVID-19, on March 18, 2020, President Sebastián Piñera decreed a State of Constitutional Exception of Catastrophe, establishing containment measures, specifically designed to restrict the free movement of people, which include curfews, mandatory selective quarantines, prohibition of mass meetings, temporary closure of companies and businesses, among other measures.

Accordingly, the Company’s subsidiary Enel Distribución Chile announced it would adopt certain preventive measures, such as the suspension of meter readings and focusing field activities on essential operations for supply continuity. It also announced extraordinary measures to support the most vulnerable households, such as not disconnecting energy services due to customers being in payment default and offering payment installment plans, with no down payment or interest for customers in debt to the Company.

Additionally, the Group issued guidelines to guarantee compliance with the measures introduced by the Chilean government and has taken a number of actions to adopt the most appropriate procedures to prevent and/or

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mitigate the effects of COVID-19 contagion among employees, while guaranteeing business continuity. This has been made possible mainly due to:

• The use of telework for all employees whose jobs can be performed remotely (75% of the staff). This work mode was introduced in the Group a few years ago, which thanks to digitalization investments, allows work to be performed remotely with the same level of efficiency and effectiveness;

• Digitalization of processes and infrastructure, which ensure the normal operation of the Company’s generation assets, continuity of the electrical service, and remote management of all activities related to the market and customer relations.

All the Company's efforts continue to focus on guaranteeing the correct and safe operation of the Company’s businesses, while safeguarding the health and safety of the Company’s people.

On August 5, 2020, Law No. 21,249 on Basic Utilities Services was enacted. This law includes extraordinary measures to support the most vulnerable customers, although Enel Distribución Chile had already been applying most of these measures. These measures include not disconnecting energy services due to customers being in payment default and the possibility of signing agreements to pay off electricity debt in installments, in both cases, for a group of vulnerable customers. The benefit associated with not disconnecting energy services due to customers being in payment default was effective for  90 days following the enactment of the Law, and debts accumulated by customers covered by this measure must be paid within a maximum of 12 installments from the end of the grace period.

Subsequently, on December 29, 2020, Law No. 21,301 was enacted, which extended the terms defined in Law No. 21,249, setting the duration of the benefit to 270 days following the enactment of this new Law instead of the initial 90 days. Also, the number of installments was modified to a maximum of 36 instead of the 12 maximum installments previously defined.

In relation to the degree of uncertainty generated in the macroeconomic and financial environments in which the Group operates and their effects on the Company's income as of December 31, 2020, these are fundamentally related to an increase in the impairment loss on trade receivables (see Notes 2.3, 3.g.3, 9.d and 26.2).

37.  HEADCOUNT

Enel Chile's personnel, as of December 31, 2020 and 2019, is as follows:

8
	12-31-2020
Country	Managers and key executives	Professionals and Technicians	Staff and others	Total
Chile	55	2,025	117	2,197
Argentina	—	5	17	22
Total	55	2,030	134	2,219
Average	54	2,010	138	2,202
	12-31-2019
Country	Managers and key executives	Professionals and Technicians	Staff and others	Total
Chile	56	1,915	139	2,110
Argentina	—	6	17	23
Total	56	1,921	156	2,133
Average	58	1,887	159	2,104

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38.  SANCTIONS.

The following Group companies have received sanctions from administrative authorities:

1. Enel Generación Chile S.A.

As of December 31, 2020, the request for reconsideration of the sanction proceedings initiated by the Bío Bío Regional Health Ministry, by Act 180566, which imposed a fine in the amount of 500 UTM (ThCh$25,515), for alleged breaches by Enel Generación Chile S.A. of obligations and regulations related to waste disposal regulations in the Cantarrana landfill is pending.

As of December 31, 2020, the Valparaíso Regional Health Ministry initiated sanction proceedings with respect to inspection report No. 1705213, for alleged breaches of obligations and regulations related to the Noise Exposure Protocols and other health surveillance regulations at the Quintero plant. The amount of this fine is 500 UTM (ThCh$25,515).

As of December 31, 2020, the Tarapacá Regional Health Ministry initiated sanction proceedings under inspection report No. 000766, in the amount of 500 UTM (ThCh$25,515), for the alleged breach by Celta in the use of lime in the Tarapacá Thermal Power Station, which is pending resolution.

As of December 31, 2020, the Coquimbo Regional Health Ministry initiated sanction proceedings under inspection report No. 10066, dated June 21, 2016, in the amount of 500 UTM (ThCh$25,515) for the alleged violation committed by Gasatacama, currently Enel Generación Chile, for keeping waste in an unauthorized area, which is pending resolution.

As of December 31, 2020, the Regional Health Ministry of the Metropolitan Region initiated sanction proceedings under Exempt Resolution No. 20131261, in the amount of 50 UTM (ThCh$2,551), for the alleged violation of health regulations due to COVID-19, which is pending resolution.

2. Enel Distribución Chile S.A.

By means of Exempt Resolution No. 13,630 dated May 23, 2016, the Superintendency of Electricity and Fuels imposed on Enel Distribution Chile S.A. a fine equivalent to 2,000 UTM (ThCh$102,058) for Enel Distribución Chile S.A.’s failure to fulfill its obligation to maintain its electrical installations in good condition to meet quality requirements and supply continuity, with regard to the fire that affected the San Joaquin substation on May 19, 2015. Enel Distribución Chile S.A. has filed a request for reconsideration against this fine, which is pending of resolution.

By means of Exempt Resolution No. 32,918 dated July 14, 2020, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 10,000 UTM (ThCh$510,290), alleging that on March 7, 2019 it failed to comply with its duty to maintain the electric service by disconnecting the 12 KVN1 bus and the transfer busbar in Substation Brasil, due to the failure of the electric arc caused by a closing maneuver and subsequent opening of a connector under load, by field personnel, during the performance of works in the substation. Enel Distribución Chile S.A. filed a request for reconsideration against this fine, which is pending resolution.

By means of Exempt Resolution No. 33,196 dated August 25, 2020, the Superintendency of Electricity and Fuels imposed a fine on Enel Distribución Chile S.A. of 22,000 UTM (ThCh$1,122,638), alleging that it did not comply with Article 4-2 on technical quality standards for distribution services, which is evidenced by the information provided by Enel Distribución Chile S.A. in the proceeding referred to as "2018 Outages", which indicates that it has exceeded the maximum SAIDI limit, established in the current standards in at least 4 municipalities. Enel Distribución Chile S.A. filed a request for reconsideration against this fine, which is pending resolution.

In relation to the sanctions described above, the Group has established provisions for ThCh$1,839,490 as of December 31, 2020 (see Note 25). There are other sanctions that also have associated provisions but they are not described in this note since they individually represent smaller amounts. Management believes that the provisions recorded adequately cover the risks due to penalties. Therefore, they do not expect additional liabilities to arise from other than those already registered.

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39.  ENVIRONMENT

Environmental expenses for the years ended December 2020, 2019 and 2018, are as follows:

				12-31-2020						12-31-2019
Disbursing Company	Project Name	Environmental Description	Project status [Finished, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements	Amount of prior period disbursement
Pehuenche	PEHUENCHE CENTRAL	Waste Management	In progress	13,128	—	13,128	19,298	12-31-2021	32,426	3,165
		Environmental Sanitation	In progress	3,528	—	3,528	5,334	12-31-2021	8,862	1,988
		Materials Environment	In progress	4,993	—	4,993	24,720	12-31-2021	29,713	9,061
		Campaigns and Studies	In progress	4,235	—	4,235	6,180	12-31-2021	10,415	—
Enel Distribución Chile S.A.	VEGETATION CONTROL IN AT NETWORKS	It consists of cutting branches until reaching the safety conditions that the foliage must be left with respect to the drivers.	Completed	305,701	—	305,701	—	12-31-2020	305,701	2,600
		This activity contemplates the maintenance of the band of easement of high voltage lines between 34,5 y 500kv.	Completed	303,873	—	303,873	—	12-31-2020	303,873	67,291
	VEGETATION CONTROL IN MT/BT	Pruning of trees near the media network and low voltage.	Completed	3,296,066	—	3,296,066	—	12-31-2020	3,296,066	3,507,502
	IMPROVEMENTS IN THE MT NETWORK	Replacement underground transformers by Technical Standard (PCB)	Completed	91,353	91,353	—	—	12-31-2020	91,353	170,077
	REPLACE TRAFOS TRIFAS MEJ QUALITY BT	This project corresponds to: - replacement of traditional network by Calpe BT - replacement of concentrical network by Calpe BT - replacement of transformers with loadability problems	Completed	3,649,294	3,649,294	—	—	12-31-2020	3,649,294	1,168,343
	ENVIRONMENTAL MANAGEMENT IN SSEE	The service consists of the maintenance of green areas with replacement of species and grass in Enel substation enclosures. Maintenance tree planting of SSEE and removal of weeds, debris and garbage, exterior perimeter. The withdrawal and transfer was carried out.	Completed	340,704	—	340,704	—	12-31-2020	340,704	64,737
	RESPEL MANAGEMENT	Hazardous waste removal and treatment management	Completed	19,122	—	19,122	—	12-31-2020	19,122	103,847
	SEC STANDARDIZATION PROJECT (CAPEX)	Maintenance of trees, SSEE and removal of weeds, debris and garbage, exterior perimeter.	Completed	1,774,155	1,774,155	—	—	12-31-2020	1,774,155
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in the Metropolitan Park.	Completed	1,374	—	1,374	—	12-31-2020	1,374	2,337
	OIL ANALYSIS AT POWER TD (OPEX)	The waste material was removed and transferred to a dump from a Substation.	Completed	32,096	—	32,096	—	12-31-2020	32,096	—
Enel Generación Chile S.A.	ENVIRONMENTAL EXPENSES CC.CC.	The main expenses incurred are: Operation and maintenance, monitoring air quality and meteorological stations, Environmental audit monitoring network once a year, Annual CEMS Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Isokinetic Measurements, SGI Works (NC objective, inspections, audits and supervision) ISO 14001, OHSAS certification, CEMS operation and maintenance service.	In progress	595,987	95,976	500,011	599,144	12-31-2021	1,195,131	2,307,825
	ENVIRONMENTAL EXPENSES CC.TT.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In progress	2,048,635	158,028	1,890,607	1,520,333	12-31-2021	3,568,968	7,151,486
	ENVIRONMENTAL EXPENSES CC.HH.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric plants (C.H.)	In progress	263,737	—	263,737	—	12-31-2020	263,737	759,980
Enel Green Power Chile S.A.	Waste management	Contracts for the removal of hazardous and non-hazardous waste, and removal of household waste.	In progress	84,113	—	84,113	148,447	12-31-2021	232,560	33,841
	Environmental Sanitation	Contracts for vector control, deratization, disinsection.	In progress	46,957	—	46,957	104,448	12-31-2021	151,405	36,175
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	—	—	35,266	44,588	12-31-2021	—	—
	Rent/Vehicle Expenses	Vehicle rental for environmental trips (field visits / Plants)	In progress	51,716	—	51,716	66,741	12-31-2021	118,457	—
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	189,321	—	189,321	355,550	12-31-2021	544,871	147,392
	Technical Counterpart Environmental Studies	Technical Counterpart Environmental Studies	In progress	—	—	—	5,287	12-31-2021	5,287	—
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	32,032	—	32,032	40,578	12-31-2021	72,610	4,822
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	8,066	—	8,066	31,591	12-31-2021	39,657	17,629
	Outsourced Services	Other services (contracts with third parties)	In progress	222,291	—	222,291	297,167	12-31-2021	519,458	53,970
	Travel Environment	Tickets - accommodation and viatics for site visit in facilities	In progress	56,820	—	56,820	85,150	12-31-2021	140,368	—
Geotérmica del Norte S.A.	Waste management	Contracts for the removal of hazardous and non-hazardous waste, and removal of household waste.	In progress	21,992	—	21,992	32,918	12-31-2021	54,910	—
	Environmental Sanitation	Contracts for vector control, deratization, disinsection.	In progress	6,500	—	6,500	14,319	12-31-2021	20,819	—
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	313,280	—	313,280	339,170	12-31-2021	652,450	—
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	91	—	91	3,559	12-31-2021	3,650	—
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	4,816	—	4,816	1,324	12-31-2021	6,140	—
Parque Eólico Talinay Oriente S.A.	Waste management	Contracts for the removal of hazardous and non-hazardous waste, and removal of household waste.	In progress	13,064	—	13,064	18,580	12-31-2021	31,644	11,865
	Environmental Sanitation	Contracts for vector control, deratization, disinsection.	In progress	6,939	—	6,939	4,109	12-31-2021	11,048	—
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	76,595	—	76,595	—	12-31-2021	76,595	63,666
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	2,087	—	2,087	—	12-31-2021	2,087	1,738
Almeyda Solar SpA	Waste management	Contracts for the removal of hazardous and non-hazardous waste, and removal of household waste.	In progress	39,521	—	39,521	31,508	12-31-2021	71,029	37,904
	Environmental Sanitation	Contracts for vector control, deratization, disinsection.	In progress	33,992	—	33,992	36,542	12-31-2021	70,534	33,467
	Water Analysis	Monitoring and analysis of drinking water and sewage	In progress	—	—	—	24,435	12-31-2020	24,435	—
	Campaigns and Studies	Contracts for Environmental Monitoring (Collision of Birds- Flora and Fauna- Archeology, others)	In progress	63,736	—	63,736	64,160	12-31-2021	127,896	121,506
	Environmental Materials	Buy environmental materials (containers, spill kit, others)	In progress	16,663	—	16,663	28,702	12-31-2021	45,365	394
	Sewage Treatment Plant	Contract for removal and cleaning of pits and sewage	In progress	8,149	—	8,149	12,795	12-31-2021	20,944	17,419
		Total		14,046,722	5,768,806	8,313,182	3,966,677		17,967,209	15,902,027

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				12-31-2019
Disbursing Company	Project Name	Environmental Description	Project status [Finished, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements
Pehuenche	PEHUENCHE CENTRAL	Waste Management	In progress	3,165	-	3,165	-	-	3,165
		Environmental Sanitation	In progress	1,988	-	1,988	-	-	1,988
	CURILLINQUE CENTRAL	Campaigns and Studies	In progress	9,061	-	9,061	-	-	9,061
		Environmental Sanitation	In progress	882	-	882	-	-	882
	LOMA ALTA CENTRAL	Environmental Sanitation	In progress	882	-	882	-	-	882
Enel Distribución Chile S.A.	CHANGE OF TRAD X CALPE NETWORK	Concentrical network replacement by Calpe (Pre-assembled aluminum cable) BT	In progress	1,476,780	1,476,780	-	-	12-31-2019	1,476,780
	VEGETATION CONTROL IN AT NETWORKS	It consists of cutting branches until reaching the safety conditions that the foliage must be left with respect to the drivers.	Completed	2,600	-	2,600	-	12-31-2019	2,600
		This activity contemplates the maintenance of the band of easement of high voltage lines between 34,5 y 500kv.	Completed	67,291	-	67,291	-	12-31-2019	67,291
	VEGETATION CONTROL IN MT/BT	Pruning of trees near the media network and low voltage.	Completed	3,507,502	-	3,507,502	-	12-31-2019	3,507,502
		The service consists of the maintenance of green areas with replacement of species and grass in Enel substation enclosures. Maintenance tree planting of SSEE and removal of weeds, debris and garbage, exterior perimeter.	Completed	64,737	-	64,737	-	12-31-2019	64,737
	ENVIRONMENTAL MANAGEMENT IN SSEE	The service consists of weeding and weed control in electrical power substation enclosures in order to keep the enclosures free of weeds, ensuring a good operation of these facilities.	Completed	19,706	-	19,706	-	12-31-2019	19,706
		The removal and transfer to waste dump from a Substation was carried out.	Completed	21,719	-	21,719	-	12-31-2019	21,719
	MANEJO AMBIENTAL	Environmental Management of Reforestation in Metropolitan Park.	Completed	2,337	-	2,337	-	12-31-2019	2,337
	MEJORAS EN LA RED MT	Replacement of MT network with protected cable	In progress	170,077	170,077	-	-	12-31-2019	170,077
	GESTIÓN DE RESPEL	Hazardous waste removal and treatment management	Completed	103,847		103,847	-	12-31-2019	103,847
	REPLACE TRIFAS TRIFAS MEJ QUALITY BT	Replacement of transformers with chargeability problems	In progress	1,168,343	1,168,343	-	-	12-31-2019	1,168,343
	REPLACEMENT TD DAE CONCENTRICA X TD. TRIF. RED CALPE	Concentrical network replacement by Calpe (Pre-assembled aluminum cable) BT	In progress	492,260	492,260	-	-	12-31-2019	492,260
Enel Generación Chile S.A.	ENVIRONMENTAL MONITORING	Environmental Monitoring Contract with SK Ecology, operation and maintenance CEMS.	In progress	576,519	-	576,519	-	-	576,519
	CEMS STANDARDIZATION	Warehouse standardization, environmental management, regularization of environmental impact assessment (EIA)	In progress	207,966	207,966	-	-	-	207,966
	HYDRAULIC CENTRALS	Waste management and sanitation	In progress	2,315	-	2,315	-	-	2,315
	ENVIRONMENTAL EXPENSES CC.CC.	The main expenses incurred are: Bocamina U1-2: Operation and maintenance, monitoring air quality and meteorological stations, Environmental audit monitoring network once a year, CEMS Annual Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Measurements Isokineticas, Trabajos SGI (NC objective, inspections, audits and supervision) ISO 14001, OHSAS certification, CEMS operation and maintenance service.	In progress	1,452,158	855,667	596,491	855,667	12-31-2020	2,307,825
	ENVIRONMENTAL EXPENSES CC.TT.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In progress	5,387,657	1,763,829	3,623,828	1,763,829	12-31-2020	7,151,486
	ENVIRONMENTAL EXPENSES CC.HH.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric plants (C.H.)	In progress	339,103	-	339,103	420,877	12-31-2020	759,980
	CENTRAL QUINTERO	CEMS Central Quinteros	In progress	458,001	110,923	347,078	37,983	12-31-2020	495,984
Enel Green Power del Sur Spa.	Carrera Pinto	Waste Management	Completed	4,432	-	4,432	-	-	4,432
		Environmental Sanitation	Completed	6,466	-	6,466	-	-	6,466
		Wastewater Treatment Plant	Completed	4,436	-	4,436	-	-	4,436
	Finis Terrae	Waste Management	Completed	10,954	-	10,954	-	-	10,954
		Environmental Sanitation	Completed	7,674	-	7,674	-	-	7,674
		Wastewater Treatment Plant	Completed	2,154	-	2,154	-	-	2,154
	La Silla	Environmental Sanitation	Completed	2,902	-	2,902	-	-	2,902
	Los Buenos Aires	Waste Management	Completed	1,509	-	1,509	-	-	1,509
		Campaigns and Studies	Completed	20,613	-	20,613	-	-	20,613
		Environmental Sanitation	Completed	3,989	-	3,989	-	-	3,989
		Wastewater Treatment Plant	Completed	882	-	882	-	-	882
		Materials Environment	Completed	5,589	-	5,589	-	-	5,589
	Pampa Norte	Waste Management	Completed	5,098	-	5,098	-	-	5,098
		Environmental Sanitation	Completed	6,618	-	6,618	-	-	6,618
		Wastewater Treatment Plant	Completed	3,459	-	3,459	-	-	3,459
	Renaico	Waste Management	Completed	2,281	-	2,281	-	-	2,281
		Campaigns and Studies	Completed	83,820	-	83,820	-	-	83,820
		Environmental Sanitation	Completed	5,226	-	5,226	-	-	5,226
		Wastewater Treatment Plant	Completed	982	-	982	-	-	982
		Materials Environment	Completed	4,822	-	4,822	-	-	4,822
		Outsourced Services	Completed	53,970	-	53,970	-	-	53,970
	Sierra Gorda	Waste Management	Completed	13,999	-	13,999	-	-	13,999
		Campaigns and Studies	Completed	42,959	-	42,959	-	-	42,959
		Environmental Sanitation	Completed	3,300	-	3,300	-	-	3,300
		Wastewater Treatment Plant	Completed	127	-	127	-	-	127
Empresa Electrica Panguipulli S.A.	Chañares	Waste Management	Completed	1,613	-	1,613	-	-	1,613
		Campaigns and Studies	Completed	7,981	-	7,981	-	-	7,981
		Environmental Sanitation	Completed	5,262	-	5,262	-	-	5,262
		Wastewater Treatment Plant	Completed	5,591	-	5,591	-	-	5,591
	Lalackama	Waste Management	Completed	1,678	-	1,678	-	-	1,678
		Environmental Sanitation	Completed	7,091	-	7,091	-	-	7,091
		Wastewater Treatment Plant	Completed	3,273	-	3,273	-	-	3,273
	Pilmaiquen	Waste Management	Completed	1,450	-	1,450	-	-	1,450
		Environmental Sanitation	Completed	6,822	-	6,822	-	-	6,822
	Pullinque	Waste Management	Completed	785	-	785	-	-	785
		Campaigns and Studies	Completed	2,627	-	2,627	-	-	2,627
		Environmental Sanitation	Completed	4,129	-	4,129	-	-	4,129
		Materials Environment	Completed	394	-	394	-	-	394

F-136

	Talinay Poniente	Campaigns and Studies	Completed	46,026	-	46,026	-	-	46,026
Parque Eolico Tal Tal S.A.	Taltal	Waste Management	Completed	10,745	-	10,745	-	-	10,745
		Campaigns and Studies	Completed	44,656	-	44,656	-	-	44,656
		Environmental Sanitation	Completed	2,476	-	2,476	-	-	2,476
		Wastewater Treatment Plant	Completed	2,515	-	2,515	-	-	2,515
Parque Eolico Valle De Los Vientos S.A.	Valle de los Vientos	Waste Management	Completed	11,546	-	11,546	-	-	11,546
		Campaigns and Studies	Completed	20,216	-	20,216	-	-	20,216
		Environmental Sanitation	Completed	2,471	-	2,471	-	-	2,471
Parque Eolico Talinay Oriente S.A.	Talinay Oriente	Waste Management	Completed	11,865	-	11,865	-	-	11,865
		Campaigns and Studies	Completed	63,666	-	63,666	-	-	63,666
		Environmental Sanitation	Completed	9,419	-	9,419	-	-	9,419
		Wastewater Treatment Plant	Completed	1,738	-	1,738	-	-	1,738
Almeyda Solar Spa	Diego de Almagro	Waste Management	Completed	10,087	-	10,087	-	-	10,087
		Environmental Sanitation	Completed	5,216	-	5,216	-	-	5,216
		Wastewater Treatment Plant	Completed	6,040	-	6,040	-	-	6,040
Total			16,132,535		6,245,845	9,886,690	3,078,356		19,210,891

				12-31-2018
Disbursing Company	Project Name	Environmental Description	Project status [Finished, in progress]	Disbursement amount	Capitalized amount	Expense amount	Future disbursement amount	Estimated date of future disbursement	Total disbursements
Pehuenche	ENVIRONMENTAL EXPENSES HYDROELECTRIC POWER PLANTS	C.H. Pehuenche E E Pehuenche S.A. Supply of flow measurement equipment. .	In progress	48,574	48,574	-	-		48,574
		Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In progress	62,560	-	62,560	-	-	62,560
Enel Distribución Chile S.A.	VEGETATION CONTROL IN AT NETWORKS	It consists of cutting branches until reaching the safety conditions that the foliage must be left with respect to the drivers.	In progress	134,394	-	134,394	19,654	12-31-2018	154,048
		Tree pruning near the medium voltage network.	In progress	5,790,042	2,472,768	3,317,274	502,599	03-31-2019	6,292,641
	RESPEL MANAGEMENT	Hazardous waste management.	Completed	1,780	-	1,780	-	06-30-2018	1,780
	ENVIRONMENTAL MANAGEMENT IN SSEE	The service consists of the maintenance of green areas with replacement of species and grass in Enel substation enclosures.	Completed	15,383	-	15,383	36,633	12-31-2018	52,016
		The service consists of weeding and weed control in electrical power substation enclosures in order to keep the enclosures free of weeds, ensuring a good operation of these facilities.	En proceso	46,339	-	46,339	568	03-31-2018	46,907
	ENVIRONMENTAL PERMITS	Environmental Impact Statement: 1) New Lampa Sectioning Substation and 2) Ochagavia - Florida Line, Sanjon La Aguada section.	In progress	1,767	1,767	-	5,203	03-31-2019	6,970
	VEGETATION CONTROL IN MT / BT NETWORKS	Improvement in the traditional network by calpe (pre-assembled aluminum cable)	In progress	19,416	19,416	-	373,059	03-31-2019	392,475
	IMPROVEMENTS IN THE MT NETWORK	Replacement of MT bare network by shielded cable	In progress	158,086	158,086	-	18,056	03-31-2019	176,142
	CHANGE OF NETWORK TRAD X CALPE	Replacement of traditional network by Calpe (Pre-assembled aluminum cable) BT	In progress	851,792	851,792	-	530,712	03-31-2019	1,382,504
	REPLACEMENT TD DAE CONCENTRICA X TD. TRIF. RED CALPE	Concentrical network replacement by Calpe (Pre-assembled aluminum cable) BT	In progress	712,455	712,455	-	295,961	03-31-2019	1,008,416
	REPLACEMENT OF TRAFOS TRIFAS QUALITY BT	Replacement of transformers with chargeability problems	In progress	1,288,155	1,288,155	-	1,353,909	03-31-2019	2,642,064
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in Cerro Chena and Metropolitan Park.	In progress	5,831	-	5,831	803	03-31-2019	6,634
	Asbestos removal from underground cables	Removal of asbestos flame retardant tape from the MT underground network.	In progress	265,577	146,300	119,277	118,337	03-31-2019	383,914
Enel Generación Chile S.A.	ENVIRONMENTAL MONITORING	Environmental Monitoring Contract with SK Ecology, operation and maintenance CEMS	In progress	797,543	-	797,543	-	-	797,543
	CEMS STANDARDIZATION	Winery standardization, environmental management, environmental impact assessment regularization (EIA)	In progress	645,302	645,302	-	-	-	645,302
	HYDRAULIC CENTRALS	Waste Management e higienización	In progress	11,567	-	11,567	-	-	11,567
	ENVIRONMENTAL EXPENSES CC.TT.	The main expenses incurred are: Bocamina U1-2: Operation and maintenance, monitoring air quality and meteorological stations, Environmental audit monitoring network once a year, CEMS Annual Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Measurements Isokineticas, Trabajos SGI (NC objective, inspections, audits and supervision) ISO 14001, OHSAS certification, CEMS operation and maintenance service.	In progress	2,102,056	-	2,102,056	-	-	2,102,056
		Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In progress	2,867,523	-	2,867,523	-	-	2,867,523
	ENVIRONMENTAL EXPENSES CC.HH.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric plants (C.H.)	In progress	183,156	-	183,156	-	-	183,156
	C.H. RALCO	Ralco Plan: Reforestation according to an agreement with the Universidad Católica and electrification of homes in Ayin Maipú.	In progress	4,542,216	4,542,216	-	-	-	4,542,216
	CENTRAL QUINTERO	CEMS Central Quinteros	In progress	417,194	417,194	-	-	-	417,194
Total				20,968,708	11,304,025	9,664,683	3,255,494		24,224,202

F-137

40.  FINANCIAL INFORMATION ON SUBSIDIARIES, SUMMARIZED

As of December 31, 2020, 2019 and 2018, summarized financial information of the Company’s principal consolidated subsidiaries prepared under IFRS is as follows:

	12-31-2020
	Financial	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Equity and Liabilities	Revenues	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income before Taxes	Income tax	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
	Statements	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Grupo Enel Distribución Chile	Consolidated	582,076,850	1,069,130,548	1,651,207,398	394,984,535	355,577,789	900,645,074	1,651,207,398	1,382,068,218	(1,116,324,483)	265,743,735	158,471,761	99,889,095	5,929,058	105,828,440	(23,421,217)	82,407,223	(3,032,588)	79,374,635
Enel Generación Chile	Separate	450,585,522	2,568,790,911	3,019,376,433	346,738,652	962,018,025	1,710,619,756	3,019,376,433	1,454,983,823	(906,062,618)	548,921,205	421,458,046	(355,272,815)	(47,019,373)	(311,920,879)	154,534,331	(157,386,549)	97,628,933	(59,757,615)
Enel Distribución Chile	Separate	577,456,051	1,060,265,626	1,637,721,677	377,127,464	355,408,175	905,186,038	1,637,721,677	1,378,024,639	(1,115,217,690)	262,806,949	156,516,439	99,162,164	5,643,080	104,815,531	(23,518,908)	81,296,623	(3,031,870)	78,264,753
Empresa Eléctrica Pehuenche S.A.	Separate	57,648,247	165,957,367	223,605,614	43,582,095	42,466,077	137,557,442	223,605,614	162,555,069	(29,660,883)	132,894,186	126,117,737	118,664,949	537,780	119,202,729	(32,100,661)	87,102,068	—	87,102,068
Enel Green Power Chile Ltda.	Separate	—	—	—	—	—	—	—	2,643,361	—	2,643,361	656,694	443,065	(728,828)	(285,763)	(27,623)	(313,386)	32,849,632	32,536,246
Empresa Electrica Panguipulli S.A.	Separate	—	—	—	—	—	—	—	36,961,169	(1,553,242)	35,407,927	30,644,413	17,824,133	(2,975,352)	14,848,781	(1,094,018)	13,754,763	3,300,577	17,055,341
Geotermica del Norte S.A.	Separate	6,236,103	400,007,251	406,243,354	47,175,660	322,246	358,745,448	406,243,354	29,621,783	(1,987,867)	27,633,916	22,284,312	4,542,775	(4,106)	4,538,668	(350,271)	4,188,397	(20,985,401)	(16,797,004)
Parque Eolico Talinay Oriente S.A.	Separate	80,718,677	81,224,769	161,943,446	3,322,615	24,923,743	133,697,088	161,943,446	13,327,199	(215,507)	13,111,692	10,119,202	2,877,967	569,821	3,447,787	(1,028,866)	2,418,922	(7,863,429)	(5,444,508)
Enel Green Power Chile S.A.	Separate	48,915,258	1,536,057,410	1,584,972,668	337,590,586	542,949,053	704,433,029	1,584,972,668	176,960,820	(30,028,125)	146,932,695	119,153,489	72,729,793	(24,394,047)	48,335,747	(14,300,689)	34,035,057	(61,492,284)	(27,457,227)
Almeyda Solar S.P.A	Separate	16,915,219	461,620,519	478,535,738	204,561,234	72,286,638	201,687,866	478,535,738	52,290,734	(2,463,593)	49,827,141	41,553,826	24,434,638	(7,386,090)	17,048,548	(4,556,211)	12,492,337	(21,883,149)	(9,390,812)
Grupo Enel Green Power	Consolidated	139,617,642	2,097,626,417	2,237,244,059	579,459,760	644,053,803	1,013,730,496	2,237,244,059	297,348,087	(12,123,965)	285,224,122	241,778,194	140,591,339	(33,609,299)	106,911,680	(25,014,045)	81,897,635	(63,316,482)	18,581,153
Grupo Enel Generación Chile	Consolidated	465,808,355	2,625,152,610	3,090,960,965	347,895,331	1,003,735,347	1,739,330,287	3,090,960,965	1,490,102,269	(811,503,735)	678,598,534	547,442,737	(236,607,867)	(46,481,593)	(271,116,321)	122,433,670	-148682651	97,437,499	(51,245,152)
	12-31-2019
	Financial	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Equity and Liabilities	Revenues	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income before Taxes	Income tax	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
	Statements	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Grupo Enel Distribución Chile	Consolidated	289,393,933	1,175,550,962	1,464,944,895	317,248,208	301,769,861	845,926,826	1,464,944,895	1,412,871,737	(1,114,936,281)	297,935,456	201,152,462	152,293,464	5,232,127	157,525,602	(38,748,555)	118,777,047	(5,268,320)	113,508,727
Enel Generación Chile	Separate	583,721,624	2,934,658,635	3,518,380,259	449,869,095	1,081,712,205	1,986,798,959	3,518,380,259	1,566,647,603	(1,015,974,072)	550,673,531	438,227,197	273,796,017	(61,735,905)	378,925,840	(47,979,392)	330,946,448	(51,590,095)	279,356,353
Enel Distribución Chile	Separate	281,307,184	1,166,614,368	1,447,921,552	293,190,807	301,606,886	853,123,859	1,447,921,552	1,409,434,510	(1,113,958,943)	295,475,567	200,130,596	151,879,931	4,770,147	156,650,077	(38,583,882)	118,066,195	(5,258,044)	112,808,151
Empresa Eléctrica Pehuenche S.A.	Separate	40,913,391	172,823,608	213,736,999	32,304,951	44,330,262	137,101,786	213,736,999	147,472,130	(19,725,956)	127,746,174	121,631,813	114,117,571	2,230,250	116,442,545	(31,554,368)	84,888,177	—	84,888,177
Enel Green Power Chile Ltda.	Separate	93,176,241	728,572,966	821,749,207	148,584,958	26,709,820	646,454,429	821,749,207	17,470,331	(5,891)	17,464,440	2,941,543	1,770,750	(3,819,658)	4,271,982	789,773	5,061,755	47,305,179	52,366,934
Empresa Electrica Panguipulli S.A.	Separate	11,883,401	268,737,935	280,621,336	35,237,664	152,717,912	92,665,760	280,621,336	65,392,897	(10,089,283)	55,303,614	45,295,840	25,634,374	(7,544,701)	18,091,741	(3,984,287)	14,107,454	4,145,983	18,253,437
Geotermica del Norte S.A.	Separate	21,392,710	389,334,650	410,727,360	34,868,730	316,179	375,542,451	410,727,360	25,736,468	(4,666,032)	21,070,436	16,240,808	985,760	(2,431,778)	(1,446,018)	(268,161)	(1,714,179)	28,824,398	27,110,219
Parque Eolico Talinay Oriente S.A.	Separate	75,985,899	91,924,981	167,910,880	3,479,000	25,290,284	139,141,596	167,910,880	12,662,715	(891,215)	11,771,500	8,846,598	1,956,884	1,076,843	3,033,727	(812,645)	2,221,082	10,644,581	12,865,663
Enel Green Power Chile S.A.	Separate	190,106,543	732,488,168	922,594,711	54,033,958	534,433,995	334,126,758	922,594,711	144,036,603	(25,778,573)	118,258,030	99,202,697	66,657,147	(23,438,689)	43,218,457	(9,496,203)	33,722,254	25,195,173	58,917,427
Grupo Enel Green Power	Consolidated	371,759,514	1,775,791,317	2,147,550,831	377,911,553	773,916,901	995,722,377	2,147,550,831	273,239,617	(26,298,083)	246,941,534	204,174,344	115,016,205	(42,962,825)	71,875,897	(16,890,333)	54,985,564	122,991,836	177,977,400
Grupo Enel Generación Chile	Consolidated	591,085,044	2,996,113,733	3,587,198,777	488,183,716	1,125,160,667	1,973,854,394	3,587,198,777	1,638,374,434	(834,936,802)	803,437,632	669,742,608	280,918,860	(58,362,079)	224,783,599	(23,457,536)	201,326,063	(55,986,126)	145,339,937
Grupo GasAtacama Chile S.A.	Consolidated	-	-	-	-	-	—	—	186,194,326	(54,061,747)	132,132,579	110,016,642	(107,102,417)	1,143,576	(103,917,448)	56,076,224	-47841224	(4,396,031)	(52,237,255)
	12-31-2018
	Financial	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Equity and Liabilities	Revenues	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income before Taxes	Income tax	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
	Statements	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Grupo Enel Distribución Chile	Consolidated	296,453,470	982,926,699	1,279,380,169	450,182,594	63,065,351	766,132,224	1,279,380,169	1,263,224,070	(972,499,916)	290,724,154	200,614,083	159,259,319	6,088,801	165,348,120	(42,967,123)	122,380,997	(600,422)	121,780,574
Enel Generación Chile	Separate	548,220,314	2,725,004,288	3,273,224,602	569,928,285	938,139,970	1,765,156,347	3,273,224,602	1,454,348,386	(1,051,644,602)	402,703,785	300,148,133	226,154,177	(49,980,539)	378,187,852	(42,255,124)	335,932,728	(101,720,204)	234,212,523
Enel Distribución Chile	Separate	288,632,068	975,441,251	1,264,073,319	424,550,547	62,721,352	776,801,421	1,264,073,320	1,259,689,827	(971,366,398)	288,323,429	199,676,810	159,625,438	5,418,883	165,044,321	(43,812,619)	121,231,702	(598,985)	120,632,717
Empresa Eléctrica Pehuenche S.A.	Separate	51,279,432	179,693,183	230,972,615	44,459,384	46,238,192	140,275,039	230,972,615	162,768,188	(21,539,174)	141,229,015	135,558,558	128,068,159	224,543	128,348,399	(34,669,191)	93,679,208	—	93,679,208
Enel Green Power Chile Ltda.	Separate	162,710,963	669,741,595	832,452,558	113,123,832	125,240,940	594,087,786	832,452,558	12,831,131	(15,655)	12,815,476	2,521,606	1,702,927	(5,337,680)	71,323,446	1,601,922	72,925,368	71,701,018	144,626,386
Empresa Electrica Panguipulli S.A.	Separate	16,052,462	255,481,676	271,534,138	59,681,465	131,671,924	80,180,749	271,534,138	45,097,744	(5,320,421)	39,777,324	32,476,777	18,680,884	(1,954,238)	16,726,646	(2,647,884)	14,078,762	(3,643,974)	10,434,788
Geotermica del Norte S.A.	Separate	21,765,295	347,871,452	369,636,747	20,910,840	293,675	348,432,232	369,636,747	17,023,794	(2,109,769)	14,914,025	13,168,978	2,001,882	(3,676,151)	(1,674,269)	454,355	(1,219,914)	45,243,420	44,023,506
Parque Eolico Talinay Oriente S.A.	Separate	63,831,605	87,493,829	151,325,434	6,173,259	18,876,242	126,275,934	151,325,435	10,058,036	(2,434,415)	7,623,621	5,310,400	1,014,857	1,312,902	2,327,759	(613,097)	1,714,661	16,552,523	18,267,184
Enel Green Power del Sur	Separate	129,849,852	655,431,547	785,281,399	44,078,091	467,399,245	273,804,063	785,281,399	94,473,391	(21,024,045)	73,449,347	60,053,812	37,537,228	(24,991,814)	12,545,413	(3,455,173)	9,090,240	34,497,623	43,587,863
Grupo Enel Green Power	Consolidated	344,469,181	1,628,444,820	1,972,914,001	334,639,971	768,719,376	869,554,654	1,972,914,001	183,008,879	(22,330,367)	160,678,512	131,378,740	69,236,957	(38,674,306)	30,471,438	(8,837,176)	21,634,262	173,923,954	195,558,216
Grupo Enel Generación Chile	Consolidated	672,467,353	2,996,760,726	3,669,228,079	593,881,208	1,077,855,824	1,997,491,047	3,669,228,079	1,529,364,081	(818,284,050)	711,080,031	582,249,559	464,383,396	(47,947,351)	423,152,001	(104,946,765)	318,205,236	(106,994,091)	211,211,145
Grupo GasAtacama Chile S.A.	Consolidated	154,726,337	601,914,918	756,641,255	61,155,091	94,466,222	601,019,942	756,641,255	271,433,789	(94,746,408)	176,687,381	146,123,452	109,465,013	1,808,644	115,039,230	(27,946,019)	87093211	(5,273,886)	81,819,325

F-138

41.  SUBSEQUENT EVENTS

i. On January 2021, the Company’s subsidiaries Enel Generación Chile and Enel Green Power Chile, signed a document referred to as a Joinder, by virtue of which they became party to the instrument governed by foreign law known as Commitment and Engagement Letter, dated December 31, 2020, jointly with Goldman Sachs & Co. LLC and Goldman Sachs Lending Partners LLC, among other parties, which also entered into this agreement. Subsequently, on January 29, 2021, Enel Generación Chile and Enel Green Power Chile signed an instrument with the Inter-American Investment Corporation referred to as Commitment Agreement, which is subject to foreign law. Both instruments are intended to regulate terms and conditions for the sale and transfer performed by Enel Generación Chile and Enel Green Power Chile of balances generated in their favor (the “Balances”) from the application of the temporary electric power pricing stabilization mechanism for customers subject to price regulation, as established by Law No. 21,185 (see Note 9).

The transfer of Balances may be performed by Enel Generación Chile and Enel Green Power Chile, from time to time, and under different conditions, to a non-related entity referred to as Chile Electricity PEC SpA, which was incorporated specifically for this purpose, in accordance with the terms and conditions that would be established in the instrument subject to foreign legislation titled Sale and Purchase Agreement to be entered into by Enel Generación Chile, Enel Green Power Chile and Chile Electricity PEC SpA. The total nominal value of the Balances of both agreements is expected to be approximately US$268 million for Enel Generación Chile and US$ 21 million for Enel Green Power Chile.

Additionally, on January 29, 2021, Enel Generación Chile and Enel Green Power Chile entered into an agreement with Chile Electricity PEC SpA subject to foreign legislation, referred to as Sale and Purchase Agreement (the “Sale Agreement”) for the sale and transfer of Balances. By virtue of this Sale Agreement, Enel Generación Chile and Enel Green Power Chile agreed to sell and transfer to Chile Electricity PEC two sets of Balances, for a nominal value of US$167.1 million and US$12.7 million, for Enel Generación Chile and Enel Green Power Chile, respectively. The sale and transfer of these sets of Balances are defined by terms and conditions established in the Commitment and Engagement Letter and in the Commitment Agreement, both described above.

The sales and transfers of these sets of Balances was concluded on February 8, 2021 for the first set and March 31, 2021 for the second set. As a result of these transactions, during 2021, Enel Generación Chile and Enel Green Power Chile have recognized a financial loss of US$38.7 million and US$3.1 million, respectively.

As indicated before, Enel Generación Chile and Enel Green Power Chile may continue to make new sales of Balances from time to time. The completion of additional sales of Balances will depend on Management’s analysis and evaluation of cash needs and market conditions existing at the time.

ii. On April 1, 2021, Enel Chile S.A. entered into a Sustainable Development Goals (SDGs)-linked US$-denominated revolving facility agreement with Enel Finance International N.V. (EFI) for US$290 million at a variable rate of LIBOR plus 1.00%, to the date, this credit line was undrawn. Also, On April 1, 2021, the Company signed a SDGs-linked US$-denominated loan facility agreement with EFI for US$300 million at a fixed annual interest rate of 2.5%. As of April 1, 2021, the outstanding balance of the loan was US$300 million.

These loans are rated SDG-linked financing that aims to support economic activity linked to the environment and socially sustainable activities, promoting the debtor to contribute to certain UN Sustainable Development Goals.

iii. In April 2021, the Company announced a Voluntary Retirement Program, open to men of at least 60 and women of at least 55 years old, with an incentive for qualifying employees who voluntarily anticipate their retirement. The program is one of the initiatives that the Group is promoting in the context of its digitization strategy in 2021-2024, enabling the adoption of new work and operation models, and demands new skills and

F-139

knowledge to make processes more efficient and effective at a time when the transformation of the Company’s platforms and business processes is becoming increasingly relevant to the Company’s clients and stakeholders. As a consequence of this restructuring plan, the Company will account for an expense of approximately ThCh$17,500,000 in 2021.

iv. At the OSM held on April 28, 2021, our new Board of Directors was elected for a term of three years starting from the date of the meeting. At the Board of Directors meeting held on April 28, 2021, the directors agreed to appoint Fernán Gazmuri Plaza, Pablo Cabrera Gaete and Luis Gonzalo Palacios Vásquez as members of the Directors’ Committee. Additionally, Fernán Gazmuri Plaza was appointed as Financial Expert of the Directors’ Committee.

The members of our new Board of Directors are as follows:

• Mr. Herman Chadwick Piñera (Chairman)

• Ms. Monica Girardi

• Ms. Isabella Alessio

• Mr. Salvatore Bernabei

• Mr. Fernán Gazmuri Plaza

• Mr. Pablo Cabrera Gaete

• Mr. Luis Gonzalo Palacios Vásquez

Between January 1, 2021 and the date of issuance of these consolidated financial statements, the Company has no knowledge of any financial or other events which significantly affect its financial position and results presented.

F-140

APPENDIX 1 DETAIL OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY

This appendix forms an integral part of the consolidated financial statements of Enel Chile.

The detail of assets and liabilities denominated in foreign currency is as follows:

	12-31-2020
ASSETS	U.F.	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Angentine Peso	Brazilian Real	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	-	300,357,149	27,617,370	83,819	-	3,977,675	-	332,036,013
Other current financial assets	707,749	2,614,678	29,977	-	-	-	-	3,352,404
Other current non-financial assets	1,117,707	15,358,682	2,189,622	293,128	-	842,434	-	19,801,573
Trade and other current receivables	1,663,044	544,736,403	7,713,459	773,733	-	-	-	554,886,639
Current accounts receivable from related parties	-	3,106,532	29,404,983	25,464,610	-	-	-	57,976,125
Inventories	48,280	17,978,682	4,042,276	1,234,785	-	6,006	-	23,310,029
Current tax assets	-	35,025,069	-	-	-	13,344	-	35,038,413
TOTAL CURRENT ASSETS	3,536,780	919,177,195	70,997,687	27,850,075	-	4,839,459	-	1,026,401,196
NON-CURRENT ASSETS
Other non-current financial assets	-	18,745,200	1,373,356	541,894	-	-	-	20,660,450
Other non-current non-financial assets	58,216	65,728,999	-	-	-	-	-	65,787,215
Trade and other non-current receivables	8,745,386	77,106,644	359,154,278	-	-	10,258	-	445,016,566
Non-current accounts receivable from related parties	-	-	48,358,915	-	-	-		48,358,915
Investments accounted for using the equity method	-	7,451,193	5,171,047	-	-	370,563	-	12,992,803
Intangible assets other than goodwill	-	115,140,459	49,736,710	-	-	237,352	-	165,114,521
Goodwill	-	887,257,655	28,447,714	-	-	-	-	915,705,369
Property, plant and equipment	1,045,376,735	3,102,444,105	871,743,874	-	-	13,931,758	-	5,033,496,472
Investment property	-	7,421,940	-	-	-	-	-	7,421,940
Right-of-use asset	19,262,028	27,760,561	1,634,255	6,845,348	-	-	-	55,502,192
Deferred tax assets	-	98,353,360	9,660,585	-	-	-	-	108,013,945
TOTAL NON CURRENT ASSETS	1,073,442,365	4,407,410,116	1,375,280,734	7,387,242	-	14,549,931	-	6,878,070,388
TOTAL ASSETS	1,076,979,145	5,326,587,311	1,446,278,421	35,237,317	-	19,389,390	-	7,904,471,584

	12-31-2019
ASSETS	UF	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Angentine Peso	Brazilian Real	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	-	209,818,277	18,115,385	654,319	-	7,096,519	-	235,684,500
Other current financial assets	707,749	280,529	322,317	-	-	-	-	1,310,595
Other current non-financial assets	-	34,098,847	535,716	-	-	-	-	34,634,563
Trade and other current receivables	-	500,407,168	10,964,072	84,090	-	-	-	511,455,330
Current accounts receivable from related parties	-	3,419,722	40,603,423	22,859,682	833,336	-	465,970	68,182,133
Inventories	53,034	34,959,079	4,212,534	447,603	-	-	-	39,672,250
Current tax assets	-	117,532,553	9,740,736	-	-	-	-	127,273,289
TOTAL CURRENT ASSETS	760,783	900,516,175	84,494,183	24,045,694	833,336	7,096,519	465,970	1,018,212,660
NON-CURRENT ASSETS
Other non-current financial assets	-	7,220,618	2	-	-	-	-	7,220,620
Other non-current non-financial assets	56,950	37,993,234	-	-	-	-	-	38,050,184
Trade and other non-current receivables	-	146,276,706	167,297,679	-	-	-	-	313,574,385
Non-current accounts receivable from related parties	-	-	34,407,142	-	-	-	-	34,407,142
Investments accounted for using the equity method	-	7,928,588	-	-	-	-	-	7,928,588
Intangible assets other than goodwill	-	86,594,286	45,684,307	-	-	-	-	132,278,593
Goodwill	-	909,078,058	8,274,916	-	-	-	-	917,352,974
Property, plant and equipment	35,346,435	3,623,068,833	1,638,296,993	7,763,853	-	-	-	5,304,476,114
Investment property	-	6,795,155	-	-	-	-	-	6,795,155
Right-of-use asset	27,741,230	19,795,447	-	8,306,833	-	-	-	55,843,510
Deferred tax assets	-	6,530,201	15,318,038	-	-	-	-	21,848,239
TOTAL NON CURRENT ASSETS	63,144,615	4,851,281,126	1,909,279,077	16,070,686	-	-	-	6,839,775,504
TOTAL ASSETS	63,905,398	5,751,797,301	1,993,773,260	40,116,380	833,336	7,096,519	465,970	7,857,988,164

F-141

	12-31-2020
LIABILITIES	Unidad de Fomento	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Argentine Peso	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	33,601,292	4	123,897,845	-	-	-	157,499,141
Current lease liability	3,129,937	65,504	2,841,336	970,934	-	-	7,007,711
Trade and other current payables	16,207,046	363,193,954	242,153,349	6,133,452		270,221	627,958,022
Current accounts payable to related parties	-	3,105,229	21,185,153	105,759,004	4,576	-	130,053,962
Other current provisions	-	3,194,786	-	-	-	240,018	3,434,804
Current tax liabilities	-	69,682,409	2,677,535	-	-	-	72,359,944
Other current non-financial liabilities	-	43,065,405	542,959	3,532,025	-	26,192	47,166,581
TOTAL CURRENT LIABILITIES	52,938,275	482,307,291	393,298,177	116,395,415	4,576	536,431	1,045,480,165
NON-CURRENT LIABILITIES
Other non-current financial liabilities	249,693,690	-	1,233,895,436	-	-	-	1,483,589,126
Non-current lease liability	28,337,700	56,084	9,461,026	7,002,997	-		44,857,807
Trade and other non-current payables	-	27,661	117,182,398	-	-	-	117,210,059
Non-current accounts receivable to related parties	-	-	1,164,044,462	-	-	-	1,164,044,462
Other long-term provisions	-	192,728,322	17,513,349	-	-	-	210,241,671
Deferred tax liabilities	-	69,239,139	98,818,423	-	-	-	168,057,562
Non-current provisions for employee benefits	-	74,814,799	723,466	-	-	-	75,538,265
Other non-current non-financial liabilities	-	1,177,968	-	-	-	-	1,177,968
TOTAL NON-CURRENT LIABILITIES	278,031,390	338,043,973	2,641,638,560	7,002,997	-	-	3,264,716,920
TOTAL LIABILITIES	330,969,665	820,351,264	3,034,936,737	123,398,412	4,576	536,431	4,310,197,085

	12-31-2019
LIABILITIES	Unidad de Fomento	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Argentine Peso	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	32,860,004	5	175,954,552	-	-	-	208,814,561
Current lease liability	2,357,438	20,000	2,836,524	628,053	-	-	5,842,015
Trade and other current payables	5,215,585	523,504,426	66,209,531	4,333,666	-	-	599,263,208
Current accounts payable to related parties	-	38,133,907	11,910,024	109,765,956	-	-	159,809,887
Other current provisions	-	4,065,965	-	-	-	-	4,065,965
Current tax liabilities	-	17,940,784	55,049	-	-	-	17,995,833
Other current non-financial liabilities	254,084	38,929,298	2,933,274	3,391,727	-	-	45,508,383
TOTAL CURRENT LIABILITIES	40,687,111	622,594,385	259,898,954	118,119,402	-	-	1,041,299,852
NON-CURRENT LIABILITIES
Other non-current financial liabilities	274,035,059	-	1,418,569,186	-	-	-	1,692,604,245
Non-current lease liability	27,672,124	68,922	12,754,827	7,069,801	-	-	47,565,674
Trade and other non-current payables	-	27,661	56,222,424	-	-	-	56,250,085
Non-current accounts receivable to related parties	-	-	486,839,483	297,534,001	-	-	784,373,484
Other long-term provisions	-	155,315,044	16,545,238	-	-	-	171,860,282
Deferred tax liabilities	-	161,017,178	88,267,463	-	-	-	249,284,641
Non-current provisions for employee benefits	-	65,531,375	632,115	-	-	-	66,163,490
Other non-current non-financial liabilities	-	1,302,759	-	-	-	-	1,302,759
TOTAL NON-CURRENT LIABILITIES	301,707,183	383,262,939	2,079,830,736	304,603,802	-	-	3,069,404,660
TOTAL LIABILITIES	342,394,294	1,005,857,324	2,339,729,690	422,723,204	-	-	4,110,704,512

F-142

APPENDIX 2 ADDITIONAL INFORMATION CIRCULAR No. 715 OF FEBRUARY 3, 2012

This appendix is part of Note 9, “Trade and Other Receivables,” and forms an integral part of the consolidated financial statements of Enel Chile.

a) Portfolio stratification

-By aging of trade and other accounts receivable:

	As of December 31, 2020
	Current Portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	Total Current	Total Non- Current
Trade and Other Receivables	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, gross	377,746,656	36,385,017	12,407,192	6,537,514	6,900,741	7,546,970	7,056,042	3,869,232	3,539,702	69,190,250	531,179,316	377,160,616
Impairment provision	(5,564,122)	(291,820)	(999,683)	(1,089,744)	(2,061,977)	(2,685,492)	(3,242,896)	(2,392,141)	(2,225,233)	(29,184,188)	(49,737,296)	(113,332)
Accounts receivable for leasing, gross	8,556,146	—	—	—	—	—	—	—	—	—	8,556,146	62,602,528
Impairment provision	(4,483,408)	—	—	—	—	—	—	—	—	—	(4,483,408)	—
Other receivables, gross	69,371,881	—	—	—	—	—	—	—	—	10,518,967	79,890,848	5,366,754
Impairment provision	—	—	—	—	—	—	—	—	—	(10,518,967)	(10,518,967)	—
Total	445,627,153	36,093,197	11,407,509	5,447,770	4,838,764	4,861,478	3,813,146	1,477,091	1,314,469	40,006,062	554,886,639	445,016,566
	As of December 31, 2019
	Current Portfolio	1-30 days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	Total Current	Total Non- Current
Trade and Other Receivables	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, gross	393,746,637	32,460,011	7,929,315	4,700,283	2,997,797	2,754,366	3,037,705	2,667,099	2,510,683	47,236,887	500,040,783	191,966,929
Impairment provision	(3,148,393)	(357,214)	(484,022)	(587,103)	(677,088)	(845,948)	(804,567)	(1,413,915)	(1,114,081)	(34,055,771)	(43,488,101)	—
Accounts receivable for leasing, gross	13,158,795	—	—	—	—	—	—	—	—	—	13,158,795	117,873,340
Impairment provision	(2,036,917)	—	—	—	—	—	—	—	—	—	(2,036,917)	—
Other receivables, gross	43,836,461	—	—	—	—	—	—	—	—	9,883,938	53,720,399	3,734,116
Impairment provision	(55,690)	—	—	—	—	—	—	—	—	(9,883,938)	(9,939,628)	—
Total	445,500,893	32,102,797	7,445,293	4,113,180	2,320,709	1,908,418	2,233,138	1,253,184	1,396,602	13,181,116	511,455,331	313,574,385

- By type of portfolio:

	December 31, 2020						December 31, 2019
	Non-renegotiated Portfolio		Renegotiated Portfolio		Total Gross Portfolio		Non-renegotiated Portfolio		Renegotiated Portfolio		Total Gross Portfolio
	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount
	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$
Up-to-date	1,466,900	523,805,724	52,534	231,101,548	1,519,434	754,907,272	1,340,828	469,633,677	36,952	116,079,889	1,377,780	585,713,566
1 to 30 days	395,186	34,812,023	20,715	1,572,994	415,901	36,385,017	433,225	30,871,310	21,280	1,588,701	454,505	32,460,011
31 to 60 days	80,032	9,839,311	6,815	2,567,881	86,847	12,407,192	106,521	7,630,607	8,018	298,708	114,539	7,929,315
61 to 90 days	33,889	6,030,130	3,116	507,384	37,005	6,537,514	17,349	4,363,345	2,080	336,938	19,429	4,700,283
91 to 120 days	20,530	6,763,017	2,021	137,724	22,551	6,900,741	11,084	2,852,961	1,661	144,836	12,745	2,997,797
121 to 150 days	14,558	6,398,089	1,478	1,148,881	16,036	7,546,970	5,819	2,510,766	1,256	243,600	7,075	2,754,366
151 to 180 days	14,025	5,653,084	1,393	1,402,958	15,418	7,056,042	3,962	2,863,659	544	174,046	4,506	3,037,705
181 to 210 days	9,955	3,625,873	1,311	243,359	11,266	3,869,232	3,647	2,571,731	377	95,368	4,024	2,667,099
211 to 250 days	8,864	3,314,300	1,526	225,402	10,390	3,539,702	2,677	2,421,028	342	89,655	3,019	2,510,683
More than 251 days	52,024	68,459,538	15,224	730,712	67,248	69,190,250	114,518	46,531,813	6,517	705,074	121,035	47,236,887
Total	2,095,963	668,701,089	106,133	239,638,843	2,202,096	908,339,932	2,039,630	572,250,897	79,027	119,756,815	2,118,657	692,007,712

b) Portfolio in default and in legal collection process

	As of December 31,
	2020		2019
	Number of	Amount	Number of	Amount
Portfolio in Default and in Legal Collection Process	Customers	ThCh$	Customers	ThCh$
Notes receivable in default	1,878	256,927	1,888	258,073
Notes receivable in legal collection process (*)	1,140	5,600,040	1,287	6,313,513
Total	3,018	5,856,967	3,175	6,571,586

(*) Legal collections are included in the portfolio in arrears.

F-143

c) Provisions and write-offs

	As of December 31,
	12-31-2020	12-31-2019
Provisions and Write-offs	ThCh$	ThCh$
Provision for non-renegotiated portfolio	12,467,992	4,403,135
Provision for renegotiated portfolio	2,699,715	5,643,865
Total	15,167,707	10,047,000

d) Number and value of transactions

	12-31-2020		12-31-2019
	Total detail by type of transaction	Total detail by type of operation	Total detail by type of transaction	Total detail by type of operation
Number and Amount of Transactions	Last Quarter	Year-to-date	Last Quarter	Year-to-date
Allowance for impairment and recoveries:
Number of Transactions	10,390	72,590	52,870	88,750
Amount of the transactions	7,768,107	15,167,707	2,451,690	10,047,000

F-144

APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:

This appendix is part of Note 9, “Trade and Other Receivables,” and forms an integral part of these consolidated financial statements of Enel Chile.

a) Portfolio stratification

- By aging of trade receivables

	12-31-2020
Trade receivables	Up-to-date Portfolio	1-30 days in arrears	31-60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non- Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, Generation and Transmission	207,362,673	17,592,321	1,880,972	373,611	457,537	494,444	356,603	377,744	533,493	1,925,441	9,037,377	240,392,216	164,089,704
- Large customers	204,354,697	17,521,848	1,876,016	368,006	135,284	485,164	199,958	243,828	270,705	853,335	8,634,892	234,943,733	164,089,704
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—	—
- Others	3,007,976	70,473	4,956	5,605	322,253	9,280	156,645	133,916	262,788	1,072,106	402,485	5,448,483	—
Allowance for impairment	(123,260)	(989)	(1,163)	(1,002)	(56,036)	(633)	(722)	(4,160)	(3,946)	(406,781)	(3,192,642)	(3,791,334)	(113,332)
Unbilled services	174,934,439	—	—	—	55,670	—	—	—	—	—	—	174,990,109	164,089,704
Billed services	32,428,234	17,592,321	1,880,972	373,611	401,867	494,444	356,603	377,744	533,493	1,925,441	9,037,377	65,402,107	—
Trade receivables, Distribution	170,383,983	18,792,696	10,526,220	6,163,903	6,443,204	7,052,526	6,699,439	3,491,488	3,006,209	12,804,907	45,422,525	290,787,100	213,070,912
- Mass-market customers	102,010,816	10,395,375	5,325,182	4,551,187	3,889,157	4,248,311	4,049,459	2,189,259	2,730,394	8,211,749	31,036,019	178,636,908	209,112,768
- Large Clients	63,058,780	6,720,252	1,907,638	817,788	1,875,941	1,031,268	358,060	(17,541)	(16,790)	469,117	6,492,927	82,697,440	807,561
- Institutional customers	5,314,387	1,677,069	3,293,400	794,928	678,106	1,772,947	2,291,920	1,319,770	292,605	4,124,041	7,893,579	29,452,752	3,150,583
Allowance for impairment	(5,440,862)	(290,831)	(998,520)	(1,088,742)	(2,005,941)	(2,684,859)	(3,242,174)	(2,387,981)	(2,221,287)	(8,803,398)	(16,781,367)	(45,945,962)	—
Unbilled services	126,861,713	—	—	—	—	—	—	—	—	—	—	126,861,713	206,186,925
Billed services	43,522,270	18,792,696	10,526,220	6,163,903	6,443,204	7,052,526	6,699,439	3,491,488	3,006,209	12,804,907	45,422,525	163,925,387	6,883,986
Total trade receivables, gross	377,746,656	36,385,017	12,407,192	6,537,514	6,900,741	7,546,970	7,056,042	3,869,232	3,539,702	14,730,348	54,459,902	531,179,316	377,160,616
Total Allowance for impairment	(5,564,122)	(291,820)	(999,683)	(1,089,744)	(2,061,977)	(2,685,492)	(3,242,896)	(2,392,141)	(2,225,233)	(9,210,179)	(19,974,009)	(49,737,296)	(113,332)
Total trade receivables, net	372,182,534	36,093,197	11,407,509	5,447,770	4,838,764	4,861,478	3,813,146	1,477,091	1,314,469	5,520,169	34,485,893	481,442,020	377,047,284

	12-31-2019
Trade receivables	Up-to-date Portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	More than 365 days in arrears	Total Current	Total Non- Current
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, Generation and Transmission	199,019,252	2,888,824	224,770	705,885	404,757	116,371	787,421	187,920	592,987	1,354,217	6,240,193	212,522,597	86,403,772
- Large Clients	193,125,348	2,763,610	43,392	551,201	290,439	13,672	574,794	78,802	487,520	846,079	4,944,351	203,719,208	86,403,772
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—	—
- Others	5,893,904	125,214	181,378	154,684	114,318	102,699	212,627	109,118	105,467	508,138	1,295,842	8,803,389	—
Allowance for impairment	(10,907)	(260)	(200)	(142)	(103)	(93)	(258)	(154)	(98)	(577)	(2,901,975)	(2,914,767)	—
Unbilled services	142,968,302	—	—	—	—	—	—	—	—	—	—	142,968,302	86,403,772
Billed services	56,050,950	2,888,824	224,770	705,885	404,757	116,371	787,421	187,920	592,987	1,354,217	6,240,193	69,554,295	—
Trade receivables, Distribution	194,727,385	29,571,187	7,704,545	3,994,398	2,593,040	2,637,995	2,250,284	2,479,179	1,917,696	3,635,526	36,006,951	287,518,186	105,563,157
- Massive Clients	144,845,823	21,084,861	5,054,606	1,889,878	1,672,041	1,384,133	1,257,238	922,539	789,642	2,097,222	24,433,032	205,431,015	103,267,572
- Large Clients	44,406,790	6,202,698	1,154,539	421,771	95,168	271,785	448,510	209,272	206,091	775,558	5,784,217	59,976,399	7,086
- Institutional Clients	5,474,772	2,283,628	1,495,400	1,682,749	825,831	982,077	544,536	1,347,368	921,963	762,746	5,789,702	22,110,772	2,288,499
Allowance for impairment	(3,137,486)	(356,954)	(483,822)	(586,961)	(676,985)	(845,855)	(804,309)	(1,413,761)	(1,113,983)	(2,476,763)	(28,676,455)	(40,573,334)	—
Unbilled services	141,740,569	—	—	—	—	—	—	—	—	—	—	141,740,569	100,458,746
Billed services	52,986,816	29,571,187	7,704,545	3,994,398	2,593,040	2,637,995	2,250,284	2,479,179	1,917,696	3,635,526	36,006,951	145,777,617	5,104,411
Total trade receivables, gross	393,746,637	32,460,011	7,929,315	4,700,283	2,997,797	2,754,366	3,037,705	2,667,099	2,510,683	4,989,743	42,247,144	500,040,783	191,966,929
Total Allowance for impairment	(3,148,393)	(357,214)	(484,022)	(587,103)	(677,088)	(845,948)	(804,567)	(1,413,915)	(1,114,081)	(2,477,340)	(31,578,430)	(43,488,101)	—
Total trade receivables, net	390,598,244	32,102,797	7,445,293	4,113,180	2,320,709	1,908,418	2,233,138	1,253,184	1,396,602	2,512,403	10,668,714	456,552,682	191,966,929

Since not all of our commercial databases in our Group’s different consolidated entities distinguish whether the final electricity service consumer is an individual or legal entity, the main management segmentation used by all consolidated entities to monitor and follow up on trade receivables is the following:

- Mass-market Customers

- Large Customers

- Institutional Customers

F-145

- By type of portfolio:

	12-31-2020
Type of Portfolio	Up-to-date portfolio	1 - 30 days in arrears	31 - 60 days in arrears	61 - 90 days in arrears	91 - 120 days in arrears	121 - 150 days in arrears	151 - 180 days in arrears	181 - 210 days in arrears	211 - 250 days in arrears	More than 251 days in arrears	Total gross portfolio	Total non-current gross portfolio
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	207,362,673	17,592,321	1,880,972	373,611	457,537	494,444	356,603	377,744	533,493	10,596,272	240,025,670	164,089,704
- Large Clients	204,354,697	17,521,848	1,876,016	368,006	135,284	485,164	199,958	243,828	270,705	9,488,227	234,943,733	164,089,704
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Other	3,007,976	70,473	4,956	5,605	322,253	9,280	156,645	133,916	262,788	1,108,045	5,081,937	—
Renegotiated portfolio	—	—	—	—	—	—	—	—	—	—	—	—
- Large Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional Clients	—	—	—	—	—	—	—	—	—	—	—	—
- Other	—	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Non-renegotiated portfolio	151,965,997	17,219,702	7,958,339	5,656,519	6,305,480	5,903,645	5,296,481	3,248,129	2,780,807	57,863,266	264,198,365	387,350
- Mass-market Clients	87,768,761	9,237,781	4,772,065	4,091,907	3,771,913	3,897,093	3,590,787	1,945,914	2,524,013	38,886,067	160,486,301	163,843
- Large Clients	61,579,935	6,530,802	1,801,692	772,761	1,855,461	1,031,268	358,060	(17,541)	(35,811)	6,962,044	80,838,671	223,507
- Institutional Clients	2,617,301	1,451,119	1,384,582	791,851	678,106	975,284	1,347,634	1,319,756	292,605	12,015,155	22,873,393	—
Renegotiated portfolio	18,417,986	1,572,994	2,567,881	507,384	137,724	1,148,881	1,402,958	243,359	225,402	730,712	26,955,281	212,683,562
- Mass-market Clients	14,242,055	1,157,595	553,116	459,280	117,244	351,218	458,673	243,345	206,381	728,248	18,517,155	208,948,925
- Large Clients	1,478,845	189,449	105,946	45,027	20,480	—	—	—	19,021	—	1,858,768	584,054
- Institutional Clients	2,697,086	225,950	1,908,819	3,077	—	797,663	944,285	14	—	2,464	6,579,358	3,150,583
Total gross portfolio	377,746,656	36,385,017	12,407,192	6,537,514	6,900,741	7,546,970	7,056,042	3,869,232	3,539,702	69,190,250	531,179,316	377,160,616

	12-31-2019
Type of Portfolio	Current Portfolio	1-30 days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	Total Current Gross Portfolio	Total Non- Current Gross Portfolio
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION AND TRANSMISSION
Non-renegotiated portfolio	199,019,252	2,888,824	224,770	705,885	404,757	116,371	787,421	187,920	592,987	7,594,410	212,522,597	86,403,772
- Large customers	193,125,348	2,763,610	43,392	551,201	290,439	13,672	574,794	78,802	487,520	5,790,430	203,719,208	86,403,772
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	5,893,904	125,214	181,378	154,684	114,318	102,699	212,627	109,118	105,467	1,803,980	8,803,389	—
Renegotiated portfolio	—	—	—	—	—	—	—	—	—	—	—	—
- Large customers	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Non-renegotiated portfolio	184,125,135	27,982,486	7,405,837	3,657,460	2,448,204	2,394,395	2,076,238	2,383,811	1,828,041	38,937,403	273,239,010	85,518
- Mass-market customers	136,847,474	20,324,155	4,780,197	1,556,017	1,527,205	1,162,547	1,083,203	827,171	699,987	26,043,745	194,851,701	85,518
- Large customers	44,252,680	6,148,385	1,130,250	421,771	95,168	271,785	448,510	209,272	206,091	4,961,884	58,145,796	—
- Institutional customers	3,024,981	1,509,946	1,495,390	1,679,672	825,831	960,063	544,525	1,347,368	921,963	7,931,774	20,241,513	—
Renegotiated portfolio	10,602,250	1,588,701	298,708	336,938	144,836	243,600	174,046	95,368	89,655	705,074	14,279,176	105,477,639
- Mass-market customers	7,998,348	760,707	274,411	333,861	144,836	221,586	174,035	95,368	89,655	486,509	10,579,316	103,182,054
- Large Customers	154,110	54,312	24,288	—	—	—	—	—	—	46,775	279,485	7,086
- Institutional Customers	2,449,792	773,682	9	3,077	—	22,014	11	—	—	171,790	3,420,375	2,288,499
Total Gross Portfolio	393,746,637	32,460,011	7,929,315	4,700,283	2,997,797	2,754,366	3,037,705	2,667,099	2,510,683	47,236,887	500,040,783	191,966,929

F-146

APPENDIX 2.2 ESTIMATES OF SALES AND PURCHASES OF ENERGY, POWER AND TOLL

This appendix forms an integral part of the consolidated financial statements of Enel Chile.

	12-31-2020		12-31-2019
	Energy and Capacity	Tolls	Energy and Capacity	Tolls
STATEMENT OF FINANCIAL POSITION	ThCh$	ThCh$	ThCh$	ThCh$
Current accounts receivable from related parties	—	—	—	—
Trade and other receivables, current	229,499,918	33,270,963	209,842,624	13,929,209
Trade and other receivables, non-current	396,509,053	—	192,961,043	—
Total Estimated Assets	626,008,971	33,270,963	402,803,667	13,929,209
Current accounts payable to related parties	—	—	—	—
Trade and other payables, current	68,569,674	13,216,339	71,189,226	20,059,576
Trade and other payables, non-current	121,315,888	—	53,941,373	—
Total Estimated Liabilities	189,885,562	13,216,339	125,130,599	20,059,576

	12-31-2020		12-31-2019
	Energy and power	Tolls	Energy and power	Tolls
INCOME STATEMENT	ThCh$	ThCh$	ThCh$	ThCh$
Energy Sales	422,457,671	33,270,962	310,301,370	13,929,209
Energy Purchases	147,662,168	11,928,862	125,130,599	20,059,576

F-147

APPENDIX 3 DETAIL OF DUE DATES OF PAYMENTS TO SUPPLIERS

This appendix is part of Note 24, “Current and Non-Current Payables,” and forms an integral part of the consolidated financial statements of Enel Chile.

	12-31-2020				12-31-2019
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers with Current Payments	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Up to 30 days	133,063,016	89,574,397	166,733,893	389,371,306	101,666,302	148,397,518	121,111,092	371,174,912
Between 31 and 60 days	49,211,386	60,808,696	79,770	110,099,852	5,579,618	71,069,622	219,965	76,869,205
Between 61 and 90 days	78,114,700	343,314	187,027	78,645,041	9,045,950	1,118,102	11,177,955	21,342,007
Between 91 and 120 days	—	—	—	—	—	—	—	—
Between 121 and 365 days	—	—	—	—	48,102,870	—	—	48,102,870
More than 365 days	—	487	117,129,284	117,129,771	—	487	56,222,424	56,222,911
Total	260,389,102	150,726,894	284,129,974	695,245,970	164,394,740	220,585,729	188,731,436	573,711,905

	12-31-2020				12-31-2019
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers details	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Suppliers for energy purchase	-	22,475,111	226,238,177	248,713,288	-	63,364,701	168,730,485	232,095,186
Suppliers for the purchase of fuels and gas	-	36,735,748	-	36,735,748	-	55,179,023	-	55,179,023
Accounts payable for goods and services	202,897,547	91,516,035	-	294,413,582	81,807,039	102,042,005	-	183,849,044
Accounts payable for the purchase of assets	57,491,555	-	57,891,797	115,383,352	82,587,701	-	20,000,951	102,588,652
Total	260,389,102	150,726,894	284,129,974	695,245,970	164,394,740	220,585,729	188,731,436	573,711,905

F-148